Vol. 78 Tuesday, 

No. 63 April 2, 2013 

Part II 

Environmental Protection Agency 

40 CFR Part 98 

2013 Revisions to the Greenhouse Gas Reporting Rule and Proposed 

Confidentiality Determinations for New or Substantially Revised Data 

Elements; Proposed Rule 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
19802 Federal Register / Vol. 78, No. 63 / Tuesday, April 2, 2013 / Proposed Rules 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 98 

[EPA–HQ–OAR–2012–0934; FRL–9789–1] 

RIN 2060–AR52 

2013 Revisions to the Greenhouse Gas 

Reporting Rule and Proposed 

Confidentiality Determinations for New 

or Substantially Revised Data 

Elements 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Proposed rule. 

SUMMARY: The EPA is proposing to 

amend the Greenhouse Gas Reporting 

Rule and to clarify or change specific 

provisions. Particularly, the EPA is 

proposing to amend a table in the 

General Provisions, to reflect revised 

global warming potentials of some 

greenhouse gases that have been 

published by the Intergovernmental 

Panel on Climate Change and to add 

global warming potentials for certain 

fluorinated greenhouse gases not 

currently listed in the table. This action 

also proposes confidentiality 

determinations for the reporting of new 

or substantially revised (i.e., requiring 

additional or different data to be 

reported) data elements contained in 

these proposed amendments to the 

Greenhouse Gas Reporting Rule. 

DATES: Comments. Comments must be 

received on or before May 17, 2013. 

Public Hearing. The EPA does not 

plan to conduct a public hearing unless 

requested. To request a hearing, please 

contact the person listed in the FOR

FURTHER INFORMATION CONTACT section of 

this preamble by April 9, 2013. If 

requested, the hearing will be 

conducted on April 17, 2013, in the 

Washington, DC area. The EPA will 

provide further information about the 

hearing on its Web page if a hearing is 

requested. 

ADDRESSES: You may submit your 

comments, identified by Docket ID No. 

EPA–HQ–OAR–2012–0934 by any of the 

following methods: 

• Federal eRulemaking Portal: http:// 

www.regulations.gov. Follow the online 

instructions for submitting comments. 

• Email: MRR_Corrections@epa.gov. 

Include Docket ID No. EPA–HQ–OAR– 

2012–0934 or RIN No. 2060–AR52 in 

the subject line of the message. 

• Fax: (202) 566–1741. 

• Mail: Environmental Protection 

Agency, EPA Docket Center (EPA/DC), 

Mailcode 6102T, Attention Docket ID 

No. EPA–HQ–OAR–2012–0934, 1200 

Pennsylvania Avenue NW., Washington, 

DC 20004. 

• Hand/Courier Delivery: EPA Docket 

Center, Public Reading Room, EPA West 

Building, Room 3334, 1301 Constitution 

Avenue NW., Washington, DC 20004. 

Such deliveries are accepted only 

during the normal hours of operation of 

the Docket Center, and special 

arrangements should be made for 

deliveries of boxed information. 

Additional Information on Submitting 

Comments: To expedite review of your 

comments by agency staff, you are 

encouraged to send a separate copy of 

your comments, in addition to the copy 

you submit to the official docket, to 

Carole Cook, U.S. EPA, Office of 

Atmospheric Programs, Climate Change 

Division, Mail Code 6207–J, 

Washington, DC, 20460, telephone (202) 

343–9263, email address: 

GHGReporting@epa.gov. 

Instructions: Direct your comments to 

Docket ID No. EPA–HQ–OAR–2012– 

0934, 2013 Revisions to the Greenhouse 

Gas Reporting Rule and Proposed 

Confidentiality Determinations for New 

or Substantially Revised Data Elements. 

The EPA’s policy is that all comments 

received will be included in the public 

docket without change and may be 

made available online at http:// 

www.regulations.gov, including any 

personal information provided, unless 

the comment includes information 

claimed to be confidential business 

information (CBI) or other information 

whose disclosure is restricted by statute. 

Should you choose to submit 

information that you claim to be CBI, 

clearly mark the part or all of the 

information that you claim to be CBI. 

For information that you claim to be CBI 

in a disk or CD ROM that you mail to 

the EPA, mark the outside of the disk or 

CD ROM as CBI and then identify 

electronically within the disk or CD 

ROM the specific information that is 

claimed as CBI. In addition to one 

complete version of the comment that 

includes information claimed as CBI, a 

copy of the comment that does not 

contain the information claimed as CBI 

must be submitted for inclusion in the 

public docket. Information marked as 

CBI will not be disclosed except in 

accordance with procedures set forth in 

40 CFR part 2. Send or deliver 

information identified as CBI to only the 

mail or hand/courier delivery address 

listed above, attention: Docket ID No. 

EPA–HQ–OAR–2012–0934. If you have 

any questions about CBI or the 

procedures for claiming CBI, please 

consult the person identified in the FOR

FURTHER INFORMATION CONTACT section. 

Do not submit information that you 

consider to be CBI or otherwise 

protected through http:// 

www.regulations.gov or email. The 

http://www.regulations.gov Web site is 

an ‘‘anonymous access’’ system, which 

means the EPA will not know your 

identity or contact information unless 

you provide it in the body of your 

comment. If you send an email 

comment directly to the EPA without 

going through http:// 

www.regulations.gov your email address 

will be automatically captured and 

included as part of the comment that is 

placed in the public docket and made 

available on the Internet. If you submit 

an electronic comment, the EPA 

recommends that you include your 

name and other contact information in 

the body of your comment and with any 

disk or CD–ROM you submit. If the EPA 

cannot read your comment due to 

technical difficulties and cannot contact 

you for clarification, the EPA may not 

be able to consider your comment. 

Electronic files should avoid the use of 

special characters, any form of 

encryption, and be free of any defects or 

viruses. 

Docket: All documents in the docket 

are listed in the http:// 

www.regulations.gov index. Although 

listed in the index, some information is 

not publicly available, e.g., CBI or other 

information whose disclosure is 

restricted by statute. Certain other 

material, such as copyrighted material, 

will be publicly available only in hard 

copy. Publicly available docket 

materials are available either 

electronically in http:// 

www.regulations.gov or in hard copy at 

the Air Docket, EPA/DC, EPA West 

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 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/ 

climatechange/emissions/ 

ghgrulemaking.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 today’s proposal will 

also be available through the WWW. 


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Federal Register / Vol. 78, No. 63 / Tuesday, April 2, 2013 / Proposed Rules 19803 

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/ 

climatechange/emissions/ 

ghgrulemaking.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 proposed 

amendments to existing regulations. If 

finalized, these amended regulations 

would 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. 

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

wholesalers. 

333415 ................................................................................ Air-conditioning equipment (except motor vehicle) manufacturing. 

423620 ................................................................................ Air-conditioners, room, merchant wholesalers. 


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19804 Federal Register / Vol. 78, No. 63 / Tuesday, April 2, 2013 / Proposed Rules 

TABLE 1—EXAMPLES OF AFFECTED ENTITIES BY CATEGORY—Continued 

Category NAICS Examples of affected facilities 

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. 

Oil and Natural Gas 

Systems.

486210 ................................................................................ Pipeline transportation of natural gas. 

221210 ................................................................................ Natural gas distribution facilities. 

325212 ................................................................................ Synthetic rubber manufacturing facilities. 

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

325199 ................................................................................ Acrylonitrile, ethylene oxide, methanol manufacturing facilities. 

325110 ................................................................................ Ethylene manufacturing facilities. 

325182 ................................................................................ Carbon black manufacturing facilities. 

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

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

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.

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. 


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Federal Register / Vol. 78, No. 63 / Tuesday, April 2, 2013 / Proposed Rules 19805 

TABLE 1—EXAMPLES OF AFFECTED ENTITIES BY CATEGORY—Continued 

Category NAICS Examples of affected 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. 

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. Other types of facilities than 

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

GENERAL INFORMATION CONTACT Section. 

Acronyms and Abbreviations. The 

following acronyms and abbreviations 

are used in this document. 

AF&PA American Forest & Paper 

Association 

AR4 Fourth Assessment Report 

BAMM best available monitoring methods 

CAA Clean Air Act 

CBI confidential business information 

CBP U.S. Customs and Border Protection 

CEMS continuous emissions monitoring 

system 

CFC chlorofluorocarbon 

CFR Code of Federal Regulations 

CH4 methane 

CO2 carbon dioxide 

CO2e carbon dioxide equivalent 

DOC degradable organic carbon 

EAF electric arc furnace 

e-GGRT Electronic Greenhouse Gas 

Reporting Tool 

EF emission factor 

EIA Energy Information Administration 

EO Executive Order 

EPA U.S. Environmental Protection Agency 

°F degrees Fahrenheit 

FR Federal Register 

GHG greenhouse gas 

GHGRP Greenhouse Gas Reporting Program 

GWP global warming potential 

HFC hydrofluorocarbon 

HHV high heat value 

IPCC Intergovernmental Panel on Climate 

Change 

ISBN International Standard Book Number 

F–GHG fluorinated greenhouse gas 

F–HTF fluorinated heat transfer fluid 

kg kilograms 

LDC Local Distribution Company 

Mscf thousand standard cubic feet 

MSW municipal solid waste 

N2O nitrous oxide 

NAICS North American Industry 

Classification System 

NCASI National Council for Air and Stream 

Improvement 

NGL natural gas liquid 

OMB Office of Management and Budget 

ORIS Office of the Regulatory Information 

System 

PFC perfluorocarbon 

QA/QC quality assurance/quality control 

RFA Regulatory Flexibility Act 

SAR Second Assessment Report 

SF6 sulfur hexafluoride 

SNAP Significant New Alternative Policy 

TAR Third Assessment Report 

UNFCCC United Nations Framework 

Convention on Climate Change 

U.S. United States 

UMRA Unfunded Mandates Reform Act of 

1995 

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 Proposed Action 

C. Legal Authority 

II. Technical Corrections and Other 

Amendments 

A. Subpart A—General Provisions 

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 X—Petrochemical Production 

K. Subpart Y—Petroleum Refineries 

L. Subpart Z—Phosphoric Acid Production 

M. Subpart AA—Pulp and Paper 

Manufacturing 

N. Subpart BB—Silicon Carbide 

Production 

O. Subpart DD—Electrical Transmission 

and Distribution Equipment Use 

P. Subpart FF—Underground Coal Mines 

Q. Subpart HH—Municipal Solid Waste 

Landfills 

R. Subpart LL—Suppliers of Coal-based 

Liquid Fuels 

S. Subpart MM—Suppliers of Petroleum 

Products 

T. Subpart NN—Suppliers of Natural Gas 

and Natural Gas Liquids 

U. Subpart PP—Suppliers of Carbon 

Dioxide 

V. Subpart QQ—Importers and Exporters of 

Fluorinated Greenhouse Gases Contained 

in Pre-Charged Equipment or Closed-Cell 

Foams 

W. Subpart RR—Geologic Sequestration of 

Carbon Dioxide 

X. Subpart SS—Electrical Equipment 

Manufacture or Refurbishment 

Y. Subpart TT—Industrial Waste Landfills 

Z. Subpart UU—Injection of Carbon 

Dioxide 

AA. Other Technical Corrections 

III. Schedule for the Proposed Amendments 

A. When would the proposed amendments 

become effective? 

B. Options Considered for Revision and 

Republication of Emissions Estimates for 

Prior Year Reports 

IV. Confidentiality Determinations 

A. Overview and Background 

B. Approach to Proposed Confidentiality 

Determinations for New or Substantially 

Revised Data Elements 

C. Proposed Confidentiality 

Determinations for Individual Data 

Elements in Two Direct Emitter Data 

Categories and Two Supplier Data 

Categories 

D. Proposed New Inputs to Emission 

Equations 

E. Request for Comments on Proposed 

Category Assignments and 

Confidentiality Determinations 

V. Impacts of the Proposed Rule 

A. Impacts of the Proposed Amendments to 

Global Warming Potentials 

B. Additional Impacts of the Proposed 

Technical Corrections and Other 

Amendments 

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 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
19806 Federal Register / Vol. 78, No. 63 / Tuesday, April 2, 2013 / Proposed Rules 

1The GWP, a metric that incorporates both the 

heat-trapping ability and atmospheric lifetime of 

each GHG, can be used to develop comparable 

numbers by adjusting all GHGs relative to the GWP 

of CO2. When quantities of the different GHGs are 

multiplied by their GWPs, the different GHGs can 

be compared on a CO2 basis. The GWP of CO2 is 

1.0, and the GWP of other GHGs are expressed 

relative to CO2. IPCC GWP values are based on the 

effects of the greenhouse gases over a 100-year time 

horizon. See 74 FR 16448, 53 (April 10, 2009). 

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. 

F. Executive Order 13175: Consultation 

and Coordination with Indian Tribal 

Governments 

G. Executive Order 13045: Protection of 

Children from Environmental Health 

Risks and Safety Risks 

H. Executive Order 13211: Actions that 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer and 

Advancement Act 

J. Executive Order 12898: Federal Actions 

to Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

I. Background 

A. How is this preamble organized? 

The first section of this preamble 

contains background information 

regarding the origin of the proposed 

amendments. This section also 

discusses EPA’s legal authority under 

the Clean Air Act (CAA) to promulgate 

(including subsequent amendments to) 

40 CFR part 98 of the Greenhouse Gas 

Reporting Rule (hereinafter referred to 

as ‘‘Part 98’’). Section II of this preamble 

is organized by Part 98 subpart and 

contains detailed information on the 

proposed revisions to the GHG 

Reporting Rule and the rationale for the 

proposed amendments. Section III of 

this preamble discusses the effective 

date of the proposed revisions for new 

and existing reporters and the options 

EPA is considering for revising and 

republishing emissions estimates for the 

reporting years 2010, 2011, and 2012. 

Section IV of this preamble discusses 

the proposed 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 

proposed amendments, primarily for 

current and new reporters of gases 

proposed to have revised or new global 

warming potentials (GWPs) listed in 

Part 98. Finally, Section VI of this 

preamble describes the statutory and 

executive order requirements applicable 

to this action. 

B. Background on the Proposed Action 

Part 98 was 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). The EPA is proposing to 

further revise Part 98. This proposed 

revision includes technical corrections, 

clarifying revisions, and additional 

amendments to Part 98. 

Changes proposed in this notice for 

certain source categories include, among 

other things, clarifying the data 

reporting requirements for certain 

facilities; correcting ambiguities or 

minor inconsistencies in greenhouse gas 

monitoring, calculation, and reporting 

requirements; amending monitoring and 

quality assurance methods to provide 

flexibility for certain facilities; and 

making other corrections identified as a 

result of working with the affected 

sources during rule implementation and 

outreach. In conjunction with this 

action, we are proposing confidentiality 

determinations for the new and 

substantially revised (i.e., requiring 

additional or different data to be 

reported) data elements under this 

proposed amendment. 

In the first two years of 

implementation of Part 98, the EPA 

responded to thousands of questions 

from reporters and engaged in a 

stakeholder and public testing process 

to help improve development of EPA’s 

electronic reporting system. Through 

these extensive outreach efforts, the 

EPA has improved our understanding of 

the technical challenges and burden 

associated with implementation of Part 

98 provisions. The proposed changes 

would improve the Greenhouse Gas 

Reporting Program (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 EPA is also proposing 

amendments to Table A–1 to Subpart A, 

General Provisions, of Part 98 to revise 

the values for the GWP of some GHGs 

and adding some GHGs (with associated 

GWP values) that are not currently 

included in the table.1 The newly added 

GWP values are from the 

Intergovernmental Panel for Climate 

Change (IPCC) Fourth Assessment 

Report 2 (AR4) and EPA assessments of 

data supporting GWP estimates for 

certain GHGs identified since 

promulgation. Data supporting the 

proposed GWP estimates include 

information provided by chemical 

manufacturers currently reporting under 

the GHGRP as well as published 

literature. The EPA is proposing these 

changes to 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; to reflect 

improved scientific understanding; and 

to promote consistency across the 

estimation methods used in the rule. 

C. Legal Authority 

The EPA is proposing these rule 

amendments under its existing CAA 

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 

proposed to be gathered by this rule 

because such data would 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 proposing 

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 obtain 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 qualify for 

confidential treatment. The 

Administrator has determined that this 

action (proposed amendments and 

confidentiality determinations) is 

subject to the provisions of section 

307(d) of the CAA. 

II. Technical Corrections and Other 

Amendments 

The EPA is proposing to revise Part 98 

to introduce technical corrections, 

clarifying revisions, and other 

amendments to Part 98 to improve the 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 78, No. 63 / Tuesday, April 2, 2013 / Proposed Rules 19807 

3 Fluorinated greenhouse gases, as defined in 40 

CFR 98.6, include sulfur hexafluoride, nitrogen 

trifluoride, and any fluorocarbon except for 

controlled substances as defined at 40 CFR part 82, 

subpart A and substances with vapor pressures of 

less than 1 mm of Hg absolute at 25 degrees C. 

4See United Nations Framework Convention on 

Climate Change, 1992. Available at: http:// 

unfccc.int/resource/docs/convkp/conveng.pdf. For 

more information about the UNFCCC, please refer 

to: http://www.unfccc.int. 

5See Articles 4 and 12 of the Convention on 

Climate Change. Parties to the Convention, by 

ratifying, ‘‘shall develop, periodically update, 

publish and make available * * * national 

inventories of anthropogenic emissions by sources 

and removals by sinks of all greenhouse gases not 

controlled by the Montreal Protocol, using 

comparable methodologies * * *.’’ 

quality and consistency of the data 

collected by the EPA in response to 

feedback received from stakeholders 

during program implementation. The 

proposed amendments include the 

following types of changes: 

• Revising GWPs for GHGs defined in 

Table A–1 of subpart A of Part 98 for 

consistency with the Inventory, and 

adding GWPs for fluorinated greenhouse 

gases (F–GHGs) used by Part 98 

facilities that are not currently included 

in Table A–1 to reflect industry 

practices. 

• Changes to clarify the applicability 

of calculation methods to certain 

sources at a facility. 

• Corrections to terms and definitions 

in certain equations to provide clarity or 

better reflect actual operating 

conditions. 

• Changes to correct typographical 

errors or cross references within and 

between subparts. 

• Amending monitoring and quality 

assurance methods to provide flexibility 

for certain facilities. 

• Corrections to data reporting 

requirements so that they more closely 

conform to the information used to 

perform emission calculations. 

• Adding readily available data 

reporting requirements that would allow 

the EPA to verify the data submitted and 

assess the reasonableness of the data 

reported. 

• Other amendments or corrections 

related to certain issues identified 

during rule implementation and 

outreach. 

Sections II.A through II.AA of this 

preamble describe the more substantive 

corrections, clarifying, and other 

amendments we are proposing for each 

subpart. The proposed amendments 

discussed in this preamble include: 

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 would substantively clarify the 

reported data element or introduce a 

new data element, clarifications of 

general monitoring and quality 

assurance requirements, and new terms 

and definitions. To reduce the length of 

this preamble, we have summarized less 

substantive corrections for each subpart 

in the memorandum, ‘‘Table of 2013 

Revisions to the Greenhouse Gas 

Reporting Rule’’ (hereafter referred to as 

the ‘‘Table of Revisions’’) available in 

the docket for this rulemaking (EPA– 

HQ–OAR–2012–0934). The proposed 

changes discussed in the Table of 

Revisions are straightforward 

clarifications of requirements to better 

reflect the EPA’s intent, simple 

corrections to calculation terms or crossreferences 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. The Table of Revisions 

describes each proposed change within 

a subpart, including those itemized in 

this preamble, and provides the current 

rule text and the proposed correction. 

Where the proposed change is listed 

only in the Table of Revisions, the 

rationale for the proposed change is also 

listed there. You may comment on those 

proposed technical corrections, 

clarifying and other amendments 

identified in the Table of Revisions as 

well as any other part of this proposal. 

A. Subpart A—General Provisions 

1. Proposed Amendments to Subpart 

A—Global Warming Potentials 

In today’s action, we are proposing to 

revise Table A–1 of subpart A of Part 98 

(hereafter referred to as ‘‘Table A–1’’) by 

updating the GWP values of certain 

compounds and adding certain F–GHGs 

and their GWPs not previously included 

in Table A–1. These proposed changes 

relate to facilities and suppliers under 

Part 98 reporting the following 

greenhouse gases: methane (CH4), 

nitrous oxide (N2O), sulfur hexafluoride 

(SF6), hydrofluorocarbons (HFCs), 

perfluorocarbons (PFCs), and other F– 

GHGs.3

The changes are being proposed for 

two reasons. First, we propose to revise 

GWPs for GHGs currently in Table A– 

1 to ensure continued consistency with 

the Inventory as the Inventory begins to 

use GWPs from the IPCC Fourth 

Assessment Report. Second, we propose 

to add GWPs for F–GHGs that are not 

currently included in Table A–1 but that 

are emitted in significant quantities or 

for which newly available data or 

literature supports the establishment of 

a GWP in Table A–1. The background 

and general rationale for these proposed 

amendments are discussed in Section 

II.A.1.a of this preamble. The proposed 

changes to the GWPs currently in Table 

A–1 and the GWP determinations for 

new proposed compounds in Table A– 

1 are discussed in Sections II.A.1.b and 

II.A.1.c of this preamble. The schedule 

for the proposed amendments is 

discussed in Section III.A of this 

preamble. 

The EPA is also considering options 

for revising and republishing emissions 

estimates for the reporting years 2010, 

2011, and 2012 using the revised GWPs 

in Table A–1. The EPA is seeking 

comment on these options, which are 

discussed in Section III.B of this 

preamble. Because reporters affected by 

the GHG reporting rule use the GWPs in 

Table A–1 to calculate annual GHG 

emissions (or GHGs supplied, as 

applicable), and, for source categories 

with a carbon dioxide equivalent 

(CO2e)-based threshold, to determine 

whether they are required to report, the 

proposed new and revised GWPs could 

change the number of reporters and the 

magnitude of emissions reported for 

some source categories. If these 

amendments are finalized, some 

facilities to which the rule did not 

previously apply may be required to 

report based on increases in calculated 

GHG quantities that affect applicability 

(see Section V of this preamble for 

additional information). These impacts 

and the potential compliance costs of 

the proposed amendments for affected 

subparts are discussed in Section V of 

this preamble. 

a. Background and General Rationale for 

GWP Revisions 

U.S. GHG reporting programs and the 

IPCC Fourth Assessment Report. As a 

party to the United Nations Framework 

Convention on Climate Change 

(UNFCCC), the United States 

participates in ongoing negotiations 

with the international community to 

promote global cooperation on climate 

change. The UNFCCC treaty, ratified by 

the U.S. in 1992, sets an overall 

framework for intergovernmental efforts 

to address the challenges posed by 

climate change.4 As part of its 

commitment to the UNFCCC, the U.S. 

submits the Inventory of U.S. 

Greenhouse Gas Emissions and Sinks to 

the Secretariat of the UNFCCC as an 

annual reporting requirement.5 The 

Inventory is a comprehensive 

assessment of U.S. GHG emissions 

based on national-level data and is 

prepared by EPA’s Office of Air and 


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6Stakeholder Workshop on the U.S. GHG 

Inventory for Natural Gas Systems. September 13– 

14, 2012, Washington, DC. See http://www.epa.gov/ 

climatechange/ghgemissions/ 

Sept2012stakeholderworkshop.html. 

7For certain F–GHGs that were not addressed by 

the SAR but were included in Part 98 (e.g., NF3), 

the EPA promulgated up-to-date GWPs from the 

IPCC AR4. (The one exception was sevoflurane, 

whose GWP was based on a study by Langbein et 

al. as explained in the February 6, 2009 Technical 

Support Document for Industrial Gas Supply: 

Production, Transformation, and Destruction of 

Fluorinated GHGs and N2O.) This approach was 

consistent with the GWP values used for F–GHGs 

in the Inventory prepared by the EPA as part of the 

U.S. commitment to the UNFCCC. 

8Please refer to http://unfccc.int/. See Decision 

15/CP.17, Revision of the UNFCCC reporting 

guidelines on annual inventories for Parties 

included in Annex I to the Convention. Parties of 

the Convention ‘‘* * * Decide[s] that, from 2015 

until a further decision by the Conference of the 

Parties, the global warming potentials used by 

Parties to calculate the carbon dioxide equivalence 

of anthropogenic emissions by sources and 

removals by sinks of greenhouse gases shall be 

those listed in the column entitled ‘‘Global warming 

potential for given time horizon’’ in table 2.14 of 

the errata to the contribution of Working Group I 

to the Fourth Assessment Report of the 

Intergovernmental Panel on Climate Change 

* * *.’’ 

Radiation in coordination with other 

federal agencies. To ensure consistency 

and comparability with national 

inventory data submitted by other 

UNFCCC Parties, the Inventory 

submitted to the UNFCCC uses 

internationally-accepted methods 

agreed upon by the Parties (including 

the United States) to develop and 

characterize emission estimates. 

As described in the preamble of the 

proposed GHG Reporting Rule (74 FR 

16448, April 10, 2009), the GHGRP is 

intended 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 

inventories and other U.S. climate 

programs by advancing the 

understanding of emission processes 

and monitoring methodologies for 

particular source categories or sectors. 

Specifically, the GHGRP 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 will 

provide or confirm the national 

statistics and emission estimates 

presented in the Inventory, which are 

calculated using aggregated national 

data. The EPA has received 

encouragement from stakeholders to use 

GHG data from the GHGRP to 

complement the Inventory, such as from 

EPA’s stakeholder workshop for natural 

gas systems.6

During the development of the GHG 

Reporting Rule, 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. This approach allows the 

data collected under the GHGRP to be 

easily compared to the data in the 

Inventory and to data from other 

national and international programs. 

Specifically, the EPA generally 

promulgated GWP values published in 

the IPCC Second Assessment Report 

(hereinafter referred to as ‘‘SAR GWP 

values’’) to convert mass emissions (or 

supply) of each GHG into a common 

unit of measure, CO2e, for final 

reporting. At the time that Part 98 was 

finalized, in order to comply with 

international reporting standards under 

the UNFCCC, official emission estimates 

were to be reported by the United States 

and other parties using SAR GWP 

values. Although the IPCC published its 

Fourth Assessment Report (AR4) prior 

to publication of the final GHG 

reporting rule (74 FR 56260), the 

UNFCCC continued to require the use of 

SAR GWP values for reporting. For 

consistency and comparability of the 

data collected between the GHGRP and 

the Inventory, the EPA adopted the SAR 

GWP values in Table A–1 to subpart A 

of Part 98, with the exception of GWPs 

for certain F–GHGs adopted from the 

IPCC AR4.7

The IPCC AR4 was published in 2007 

and is among the most current and 

comprehensive peer-reviewed 

assessments of climate change. The AR4 

provides revised GWPs of several GHGs 

relative to the values provided in 

previous assessment reports, following 

advances in scientific knowledge on the 

radiative efficiencies and atmospheric 

lifetimes of these GHGs and of CO2. 

Because the GWPs provided in the AR4 

reflect an improved scientific 

understanding of the radiative effects of 

these gases in the atmosphere, the 

values provided are more appropriate 

for supporting the overall goal of the 

reporting program to collect GHG data 

than the SAR GWP values currently 

included in Table A–1. While we 

recognize that GWPs reflecting further 

scientific advances may become 

available in the near future (e.g., the 

IPCC Fifth Assessment Report, currently 

in development), it is not now EPA’s 

intent to revise the GWPs in Table A– 

1 each time new data are published. 

Rather, we understand that it is also 

important for stakeholders to have 

consistent, predictable requirements to 

avoid confusion and additional burden. 

As discussed below, we are not 

proposing to adopt GWP values from the 

Fifth Assessment Report because it is 

our intent to have the GHGRP 

complement the requirements of the 

Inventory. 

On March 15, 2012, the UNFCCC 

published a decision, reached by 

UNFCCC member parties, to require 

countries submitting an annual report in 

2015 and beyond to use GWP values 

from the IPCC AR4 (hereinafter referred 

to as the ‘‘AR4 GWP values’’).8

Accordingly, the United States has a 

commitment to submit the Inventory for 

2015 and future years using the revised 

AR4 GWP values. The Inventory for 

2015 will contain national level 

estimates of emissions for each year 

from 1990–2013. In order to ensure that 

the GHGRP continues to complement 

and inform the Inventory submitted to 

the UNFCCC and relies on recent 

scientific data, we are proposing to 

revise the GWP values in Table A–1 of 

Part 98 to reflect the updated AR4 GWP 

values. The proposed changes would 

keep the reporting metrics in Part 98 

consistent with the updated 

international reporting standards 

followed by the Inventory. Additionally, 

the proposed changes would allow for 

improved understanding of the radiative 

forcing from reported GHG emissions 

and supply, based on GWP values that 

are more up-to-date relative to the 

values currently provided in Table A–1. 

The proposed changes to Table A–1 

would also ensure that the data 

collected in the GHGRP can be 

compared to other national and 

international inventories. These 

proposed changes are in keeping with 

the Agency’s decision to use methods 

consistent with UNFCCC guidelines in 

the development of the October 30, 2009 

GHG Reporting Rule. 

We recognize that some other EPA 

programs use the GWP values in Table 

A–1 to determine applicability of the 

program to direct emitters or suppliers 

above certain thresholds. For example, 

EPA’s Greenhouse Gas Tailoring Rule 

(75 FR 31514; June 3, 2010) crossreferences Table A–1 for calculating 

GHG emissions under the PSD and title 

V permitting programs. See, e.g., 40 CFR 

52.21(b)(49)(ii)(a). Because the 

permitting applicability is based partly 

on CO2e emissions, which are 

calculated using the GWP values 

codified in Table A–1, an amendment to 

Table A–1 may affect program 

applicability for a source. As a result, a 

source that is assessing applicability 

under the PSD or title V permitting 

program should be aware of the 


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9This reliance of other EPA programs on Table 

A–1 promotes implementation consistency and 

avoids having to revise the other rules each time a 

GWP revision occurs. As noted in the Tailoring 

Rule preamble, ‘‘[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 EPA after a regulatory process and will be 

consistent with those values used in the EPA’s 

mandatory GHG reporting rule.’’ (75 FR at 31522; 

June 3, 2010). 10While we are seeking comments on specific 

GWP values proposed in this action, we are not 

reopening for comment the decision made in the 

Light Duty Vehicle Rule, or any other rules or 

programs, to use AR4 GWPs. 

11 Fluorinated heat transfer fluids are defined as 

F–GHGs used for temperature control, device 

testing, cleaning substrate surfaces and other parts, 

and soldering in certain types of electronics 

manufacturing production processes. Under subpart 

I, the lower vapor pressure limit of 1 mm Hg in 

absolute at 25 °C in the definition of fluorinated 

greenhouse gas in 40 CFR 98.6 does not apply. 

proposed changes to Table A–1 that may 

affect the CO2e emissions of the source 

once the Table A–1 amendment is 

promulgated and effective.9 To the 

extent that a Table A–1 amendment 

raises permitting implementation 

questions or concerns, EPA’s regional 

offices and the Office of Air Quality 

Planning and Standards, which manage 

the PSD and title V programs, will work 

with permitting authorities and other 

stakeholders as necessary to provide 

guidance on their issues and concerns. 

While we are seeking comments on 

specific GWP values proposed in this 

action, we are not reopening for 

comment the decision made in the 

Tailoring Rule, or any other rules or 

programs, to reference Table A–1. 

Use of the AR4 GWPs is also in 

keeping with other EPA programs. For 

example, the Agency decided to use 

these values in rules published jointly 

with the Department of Transportation, 

National Highway Traffic Safety 

Administration, the ‘‘Light-Duty Vehicle 

Greenhouse Gas Emission Standards 

and Corporate Average Fuel Economy 

Standards’’ (75 FR 25324, May 7, 

2010).10

Section II.A.1.b of this preamble lists 

the changes we are proposing to 

incorporate as a result of the updated 

AR4 GWPs. 

Identification of GWPs in the 

scientific literature. 

During implementation of Part 98, the 

EPA has collected data on the range and 

volume of F–GHGs emitted and 

supplied in the U.S. market by various 

F–GHG producers, importers, exporters, 

and manufacturers using F–GHGs in 

their production processes (e.g., 

electronics manufacturing, magnesium 

production).11 The EPA reviewed 

available production and usage data for 

existing and newly synthesized gases 

and assessed available data 

substantiating the GWP calculation for 

gases for which a GWP value was not 

included in Table A–1 in the October 

30, 2009 final rule. In this action, we are 

proposing to amend Table A–1 to add 

F–GHGs emitted or supplied by 

reporters under subparts I (Electronics 

Manufacturing), L (Fluorinated Gas 

Production), T (Magnesium Production), 

OO (Industrial GHG Suppliers), and QQ 

(Importers and Exporters of G–GHGs 

Contained in Pre-Charged Equipment 

and Closed-Cell Foams). Section II.A.1.c 

of this preamble lists the changes we are 

proposing to incorporate the additional 

F–GHGs into Table A–1. 

The EPA is proposing to amend Table 

A–1 to subpart A of Part 98 to add 26 

F–GHGs for which we have identified a 

GWP based on an assessment of recent 

scientific literature. Table A–1 to 

subpart A is a compendium of GWP 

values of select GHGs that are required 

to be reported under one or more 

subparts of Part 98, and where the EPA 

has identified the GWP in the IPCC AR4 

report or other sources. As 

acknowledged in the preamble to the 

final Part 98 (74 FR 56260, October 30, 

2009), Table A–1 is not a complete 

listing of current or potential 

compounds, but reflects only those 

GWPs for listed materials that had been 

synthesized, their atmospheric 

properties investigated, and the results 

published and reviewed prior to 

promulgation of the final rule. 

Currently, some Part 98 source 

categories provide calculation 

methodologies and reporting 

requirements for F–GHGs for which 

GWP values were not available in the 

IPCC SAR, TAR, AR4, or other scientific 

assessments at promulgation. As noted 

in the preamble to the final Part 98 (74 

FR 56260), it is the EPA’s intent to 

periodically update Table A–1 as GWPs 

are evaluated or re-evaluated by the 

scientific community. 

b. Proposed Revisions From the IPCC 

Fourth Assessment Report 

The proposed amendments to Table 

A–1 would revise the GWPs for 23 

GHGs to reflect the 100-year GWP 

values adopted by the UNFCCC and 

published in the IPCC AR4. Table 2 of 

this preamble lists the GHGs whose 

GWP values we are proposing to revise, 

along with the GWP values currently 

listed in Table A–1 and the proposed 

revised GWP values from the IPCC AR4. 

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

Name CAS No. 

Current global 

warming potential a

Proposed 

global warming potential b

Methane ....................................................................................................................................... 74–82–8 21 25 

Nitrous oxide ................................................................................................................................ 10024–97–2 310 298 

HFC–23 ........................................................................................................................................ 75–46–7 11,700 14,800 

HFC–32 ........................................................................................................................................ 75–10–5 650 675 

HFC–41 ........................................................................................................................................ 593–53–3 150 92 

HFC–125 ...................................................................................................................................... 354–33–6 2,800 3,500 

HFC–134 ...................................................................................................................................... 359–35–3 1,000 1,100 

HFC–134a .................................................................................................................................... 811–97–2 1,300 1,430 

HFC–143 ...................................................................................................................................... 430–66–0 300 353 

HFC–143a .................................................................................................................................... 420–46–2 3,800 4,470 

HFC–152a .................................................................................................................................... 75–37–6 140 124 

HFC–227ea .................................................................................................................................. 431–89–0 2,900 3,220 

HFC–236fa ................................................................................................................................... 690–39–1 6,300 9,810 

HFC–245ca .................................................................................................................................. 679–86–7 560 693 

HFC–43–10mee ........................................................................................................................... 138495–42–8 1,300 1,640 

Sulfur hexafluoride ....................................................................................................................... 2551–62–4 23,900 22,800 

PFC–14 (Perfluoromethane) ........................................................................................................ 75–73–0 6,500 7,390 

PFC–116 (Perfluoroethane) ......................................................................................................... 76–16–4 9,200 12,200 

PFC–218 (Perfluoropropane) ...................................................................................................... 76–19–7 7,000 8,830 


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12The Montreal Protocol on Substances that 

Deplete the Ozone Layer is an international treaty 

that controls and phases out various ozonedepleting substances including 

chlorofluorocarbons, hydrochlorofluorocarbons and 

halons. These compounds are regulated in the U.S. 

under Title VI of the CAA. The UNFCCC does not 

cover these substances, and instead defers their 

treatment to the Montreal Protocol. 

13Refer to: http://www.unfccc.int. See Article 4 of 

the Convention on Climate Change. 

14 In some cases, the F–GHGs had not been 

developed or had not become commercially 

important in time for inclusion in AR4; in others, 

the F–GHGs were known to have short atmospheric 

lifetimes and/or low GWPs. 

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

Name CAS No. 

Current global 

warming potential a

Proposed 

global warming potential b

PFC–3–1–10 (Perfluorobutane) ................................................................................................... 355–25–9 7,000 8,860 

Perfluorocyclobutane ................................................................................................................... 115–25–3 8,700 10,300 

PFC–4–1–12 (Perfluoropentane) ................................................................................................. 678–26–2 7,500 9,160 

PFC–5–1–14 (Perfluorohexane) .................................................................................................. 355–42–0 7,400 9,300 

aFrom Table A–1 to subpart A of the October 30, 2009 GHG Reporting Rule. 

bFrom Table 2.14 of the errata to Working Group 1 of the IPCC AR4. 

We are proposing to adopt only GWP 

values based on a 100-year time 

horizon, although other time horizons 

are available in the IPCC AR4 (e.g., 20- 

year or 500-year GWPs). As 

acknowledged in the April 10, 2009 

proposed GHG reporting rule (74 FR 

16448), the parties to the UNFCCC 

agreed to use GWPs based upon a 100- 

year time horizon. Therefore, 100-year 

GWPs are used as the metric in the 

Inventory. Because the proposed 

changes are intended to make the 

GHGRP reporting methods more 

consistent with the Inventory, we are 

not considering the use of GWPs based 

on other time horizons. 

As noted above, Table A–1 already 

includes AR4 GWPs for chemicals for 

which GWPs were not presented in the 

SAR (e.g., fluorinated ethers); the EPA is 

therefore proposing to retain the current 

GWPs for these chemicals (and for 

sevoflurane, which has not been 

included in any IPCC assessment but 

already is included in Table A–1). A 

complete listing of the current GWPs in 

Table A–1 to subpart A and the AR4 

GWP values may be found in the 

memorandum, ‘‘Assessment of 

Emissions and Cost Impacts of 2013 

Revisions to the Greenhouse Gas 

Reporting Rule’’ (hereafter referred to as 

‘‘Impacts Analysis’’) (see Docket ID No. 

EPA–HQ–OAR–2012–0934). 

For one set of chemicals, fluorinated 

ethers and alcohols, the EPA is seeking 

comment on adopting GWPs from an 

international scientific assessment 

published more recently than AR4, the 

WMO (World Meteorological 

Organization) Scientific Assessment of 

Ozone Depletion: 2010 (Global Ozone 

Research and Monitoring Project-Report 

No. 52, 516 pp., Geneva, Switzerland, 

2011). Like the IPCC Assessment 

Reports, the WMO Scientific 

Assessments include regularly updated 

international reviews of the scientific 

findings on the lifetimes and impacts of 

trace gases in the atmosphere. While the 

primary focus of the WMO Scientific 

Assessments is depletion of 

stratospheric ozone, they have also 

included estimated GWPs for a number 

of fluorocarbons that do not deplete 

stratospheric ozone (many of which are 

substitutes for ozone-depleting 

substances) since 1989. 

The current Table A–1 includes AR4 

GWPs for several fluorinated ethers and 

alcohols, including several 

hydrofluoroethers (HFEs), which could 

be updated through the WMO Scientific 

Assessments. These fluorinated ethers 

and alcohols are not required to be 

included in national GHG inventories 

reported under the UNFCCC. In general, 

the compounds required to be reported 

under the GHGRP go beyond the 

minimum reporting requirements of the 

UNFCCC (e.g., NF3 or fluorinated heat 

transfer fluids). These compounds were 

included in Part 98 because they are 

long-lived in the atmosphere, have high 

GWPs, and, in many cases, are used in 

expanding industries or as substitutes 

for HFCs (see 74 FR 16464, April 10, 

2009). Thus, adopting GWPs for these 

compounds from an international 

assessment that is more recent than the 

AR4 would not conflict with UNFCCC 

reporting. 

The 2010 WMO Scientific Assessment 

includes significant updates to the 

GWPs for several HFEs in commerce, 

reflecting improved understanding of 

the atmospheric lifetimes and radiative 

efficiencies of these chemicals. In a 

number of cases, estimated 100-year 

GWPs for HFEs have approximately 

doubled; in one, (for HFE–338mmz1), 

the estimated 100-year GWP rose by 

over a factor of six, from 380 to 2570. 

(The changes to the estimated GWPs of 

other fluorinated GHGs, such as the 

HFCs and PFCs, were far smaller.) To 

ensure consistency between the GHGRP 

and UNFCCC reporting, the EPA is not 

proposing to adopt GWPs from the 2010 

WMO Scientific Assessment for 

chemicals other than fluorinated ethers 

and alcohols. However, the EPA 

requests comment on adopting GWPs 

from the 2010 WMO Scientific 

Assessment for a subset of chemicals, 

fluorinated ethers and alcohols, that are 

not reported under the Inventory. 

We are not proposing to include 

GWPs for ozone-depleting substances 

controlled by the Montreal Protocol 12

and by Title VI of the CAA (e.g., 

chlorofluorocarbons, 

hydrochlorofluorocarbons, and halons) 

in Table A–1, although the IPCC AR4 

includes updated GWPs for them. These 

controlled substances are specifically 

excluded from the definition of GHG, F– 

GHG, and F–HTF under Part 98 (and 

thus not required to be reported under 

Part 98), as these substances are already 

effectively reported under 40 CFR part 

82. Furthermore, the reduction of these 

substances is controlled under the 

Montreal Protocol. The UNFCCC does 

not cover these substances or require 

reporting of these substances by 

UNFCCC parties,13 so collecting data on 

these substances is unnecessary to 

complement or supplement the 

Inventory. 

c. Proposed Additional F–GHGs and 

GWPs for Table A–1 

We are proposing to include 26 new 

F–GHGs in Table A–1 of subpart A for 

which the EPA has identified scientific 

assessments of the GWPs. These F– 

GHGs were not included in AR4 for a 

variety of reasons.14 As discussed in 

Section II.A.1.a of this preamble, the 

F–GHGs we are proposing to include in 

Table A–1 are emitted or supplied by 

reporters under subparts I, L, T, OO, and 

QQ. Including GWP values in Table A– 

1 for these compounds would ensure 

that their atmospheric impacts are 

accurately reflected in annual reports, 

threshold determinations, or other 

calculations, as appropriate for each 

subpart in Part 98. In general, those F– 


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15The one exception to this is F–GHGs reported 

under subpart L. Under a final rule published on 

August 24, 2012 (77 FR 51477), fluorinated gas 

producers are required for RY 2011 and RY 2012 

to report total annual emissions in CO2e and to use 

either default or best-estimate GWPs for fluorinated 

GHGs that do not have GWPs listed in Table A–1. 

16This is part of the provision of subpart L that 

allows facilities to request to use provisional GWPs 

to calculate a preliminary estimate of emissions 

from each process vent. If the preliminary estimate 

indicates that a vent emits 10,000 metric tons CO2e 

or more, the subpart L reporter is required to use 

stack testing to establish an emission factor for the 

continuous process vent. If the preliminary estimate 

indicates that the vent emits less than 10,000 metric 

tons CO2e, the subpart L reporter may use 

engineering calculations or assessments to develop 

an emission calculation factor. 

17For reporting years 2011 and 2012, subpart L 

reporters may use a best estimate of the GWP 

meeting the data requirements for provisional 

GWPs in 40 CFR 98.123(c)(1)(vi)(A)(3) as part of 

their facility-wide reported emissions. 

18The SNAP program is EPA’s program to 

evaluate substitutes for the ozone-depleting 

substances that are being phased out under the 

stratospheric ozone protection provisions of the 

Clean Air Act (as implemented in 40 CFR part 82). 

As part of EPA’s assessment of a substitute’s overall 

risk to human health and the environment, the EPA 

reviews scientific assessments of the GWP and 

considers this, among other criteria, in evaluating 

a substitute. 

19The key component of the GWP calculation is 

the time-integrated radiative forcing of a one-kg 

emission of the compound over a 100-year time 

horizon. The accuracy of the radiative forcing 

calculation depends on the accuracies of the 

infrared absorption spectrum and the atmospheric 

lifetime of the compound. The lifetime is affected 

by the compound’s reaction rates through reaction 

with atmospheric oxidants (e.g., ozone or hydroxyl 

radicals) or through photolysis (destruction by 

light). These rates, as well as the radiative efficiency 

of the compound, depend on the distribution of the 

compound in the atmosphere with altitude, latitude 

and longitude. The factors affecting GWPs are 

discussed in more detail in Supporting Analysis for 

Mandatory Reporting Of Greenhouse Gases: Notice 

Of Preliminary Determinations Regarding Requests 

to Use Provisional Global Warming Potentials 

Under the Fluorinated Gas Production Category of 

the Greenhouse Gas Reporting Rule (January 23, 

2011), which is available in Docket EPA–HQ–OAR– 

2012–0934. 

GHGs whose GWPs are currently not 

listed in Table A–1 are not currently 

included in threshold calculations for 

applicability or in the CO2e totals 

reported by facilities and suppliers 15

(although they are currently reported in 

metric tons of substance emitted or 

supplied (40 CFR 98.3(c)(4))). Where 

their GWPs are low, these compounds 

may have little effect on facility CO2e 

totals. However, where their GWPs are 

high, they may have a large effect on 

those totals. 

In some cases, the proposed additions 

to Table A–1 would help to ensure that 

all Part 98 facilities emitting or 

supplying the identified F–GHGs would 

use consistent GWPs to calculate 

emissions of CO2e. For example, GWPs 

are used in 40 CFR 98.123(c)(1), a 

provision of subpart L of Part 98 

(Fluorinated Gas Production), to 

determine the emission estimation 

method for continuous process vents.16

Under 40 CFR 98.123(c)(1)(v), subpart L 

reporters must use the GWPs in Table 

A–1 to convert F–GHG emissions to 

CO2e for a preliminary estimate of 

emissions. For F–GHGs whose GWPs 

are not listed in Table A–1, subpart L 

reporters must use a default GWP of 

2,000 unless they submit a request to 

use provisional GWPs for those F–GHGs 

following the requirements of 40 CFR 

98.123(c)(1)(vi) and the EPA approves 

the request. Provisional GWPs may be 

used only in the calculations in 40 CFR 

98.123(c)(1) and only by the facilities for 

which they have been approved.17

Therefore, although the EPA may have 

reviewed and substantiated provisional 

GWP values for select F–GHGs for 

certain producers to use in determining 

the emission estimation method for 

continuous process vents under subpart 

L, the provisional GWPs may not be 

used by other Part 98 facilities. 

Including the proposed F–GHGs in 

Table A–1 would reduce burden for 

facilities that may otherwise be required 

to perform stack testing based on the 

default GWP (e.g., if the default GWP 

overstates the radiative efficiency of the 

F–GHG). Additionally, including these 

F–GHGs in Table A–1 would provide 

more accurate reporting than the use of 

the default GWPs under subpart L. 

The proposed F–GHGs include 

F–GHGs for which the EPA has 

previously reviewed scientific 

assessments from requests for 

provisional GWPs, F–GHGs submitted 

by a fluorinated GHG producer with 

suggested GWPs and supporting data 

and analysis on August 21, 2012, and 

F–GHGs for which evaluations of the 

GWPs were performed by the EPA (e.g., 

as part of evaluations associated with 

EPA’s Significant New Alternative 

Policy (SNAP) program), or published in 

peer-reviewed scientific journals. 18

Specifically, the compounds we are 

proposing to add to Table A–1 of 

subpart A include: 

• Seven compounds for which the 

EPA has approved provisional GWPs for 

purposes of the calculations in 40 CFR 

98.123(c)(1). The EPA reviewed 

scientific assessments of the GWPs for 

these F–GHGs as provided with 

provisional GWP requests received from 

Honeywell International (‘‘Honeywell’’) 

and DuPont de Nemours, Inc. 

(‘‘DuPont’’) and published in the 

February 3, 2012 Notice of Data 

Availability (77 FR 5514). The EPA 

approved provisional GWPs for one F– 

GHG for Honeywell, and for six F–GHGs 

for DuPont. The EPA finalized its 

determinations for these compounds on 

February 24, 2012 (see Docket ID No. 

EPA–HQ–OAR–2009–0927–0273). 

Based on EPA’s review of the GWP 

estimation methods for these 

compounds, we are proposing to amend 

Table A–1 to include these seven gases. 

• Four compounds submitted with 

provisional GWP requests for which the 

EPA did not approve provisional GWPs 

(including three F–GHGs for DuPont, 

and one F–GHG for Honeywell). The 

companies submitted scientific data 

supporting the GWPs of these four 

compounds, which was made available 

in the February 3, 2012 Notice of Data 

Availability (77 FR 5514). (see Docket ID 

No. EPA–HQ–OAR–2009–0927–0256 for 

further discussion of the scientific 

assessments reviewed). The EPA did 

evaluate the GWPs of these F–GHGs, but 

not for the purposes of the calculations 

in 40 CFR 98.123(c) because the 

calculated emission rates of these 

chemicals, when using the default GWP, 

did not exceed the 10,000 metric tons 

CO2e threshold and did not meet the 

conditions of 40 CFR 98.123(c)(1)(v). 

The fact that the EPA did not approve 

the GWPs for purposes of the 

calculations in 40 CFR 98.123(c)(1) was 

not due to disagreement with the 

companies’ suggested GWPs. Therefore, 

the EPA is also proposing to amend 

Table A–1 to include these four gases. 

• Ten F–GHGs submitted by DuPont 

on August 21, 2012, with supporting 

data and analysis (see Table 3 of this 

preamble). We are proposing to include 

the ten compounds in Table A–1. For 

each compound, DuPont included peerreviewed scientific data supporting the 

suggested GWP. 

• Five F–GHGs which were identified 

from the EPA’s review of industrial 

gases produced for or used in the 

electronics manufacturing, fluorinated 

gas production, magnesium production, 

electrical equipment manufacture or 

refurbishment, and industrial gas 

supplier source categories and for which 

scientific assessments or other 

documentation of the GWPs were 

identified through the EPA’s SNAP 

Program or peer-reviewed literature. 

These compounds are identified under 

the common names FK–5–1–12 

(NovecTM 612), FK–6–1–12 (NovecTM

774), trans-1-chloro-3,3,3-trifluoroprop1-ene, PFC–6–1–12, and PFC–7–1–18. 

Determination of proposed GWPs. To 

determine the proposed GWPs for each 

compound, the EPA reviewed the 

scientific literature for each compound 

and evaluated the accuracy of the 

estimation methods and assumptions 

used to derive the GWP.19 A detailed 

description of the EPA’s analysis may be 

found in the memorandum, ‘‘GWP 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
19812 Federal Register / Vol. 78, No. 63 / Tuesday, April 2, 2013 / Proposed Rules 

Determinations for Proposed Additional 

F–GHGs for Table A–1’’, Docket ID No 

EPA–HQ–OAR–2012–0934. The 

proposed GWP for each of the 26 

compounds is included in Table 3 of 

this preamble; Table 3 also includes 

how each compound was identified for 

inclusion in Table A–1 of subpart A. 

TABLE 3—PROPOSED F–GHGS WITH GWPS FOR TABLE A–1 

Chemical designation or common name CAS No. Chemical formula Proposed 

GWP 

Origin of compound and GWP assessments 

HFC–1234ze(E) ................................................... 29118–24–9 C3H2F4 6 Approved as provisional GWP for 

Honeywell International (see 

EPA–HQ–OAR–2009–0927– 

0273, February 24, 2012). 

hexafluoropropylene (HFP) ................................. 116–15–4 C3F6 0.25 Approved as provisional GWP for 

DuPont de Nemours (see EPA– 

HQ–OAR–2009–0927–0273, February 24, 2012). 

perfluoromethyl vinyl ether (PMVE) .................... 1187–93–5 CF(CF3)OCF3 3 Approved as provisional GWP for 

DuPont de Nemours (see EPA– 

HQ–OAR–2009–0927–0273, February 24, 2012). 

tetrafluoroethylene (TFE) ..................................... 116–14–3 C2F4 0.02 Approved as provisional GWP for 

DuPont de Nemours (see EPA– 

HQ–OAR–2009–0927–0273, February 24, 2012). 

trifluoro propene (TFP) ........................................ 677–21–4 C3H3F3 3 Approved as provisional GWP for 

DuPont de Nemours (see EPA– 

HQ–OAR–2009–0927–0273, February 24, 2012). 

vinyl fluoride (VF) ................................................ 75–02–5 C2H3F 0.7 Approved as provisional GWP for 

DuPont de Nemours (see EPA– 

HQ–OAR–2009–0927–0273, February 24, 2012). 

vinylidine Fluoride (VF2) ...................................... 75–38–7 C2H2F2 0.9 Approved as provisional GWP for 

DuPont de Nemours (see EPA– 

HQ–OAR–2009–0927–0273, February 24, 2012). 

carbonyl fluoride .................................................. 353–50–4 COF2 2 Submitted with provisional GWP request for DuPont de Nemours, no 

provisional GWP approved (see 

EPA–HQ–OAR–2009–0927– 

0273, February 24, 2012). 

perfluoropropyl vinyl ether ................................... 1623–05–8 C5F10O 3 Submitted with provisional GWP request for DuPont de Nemours, no 

provisional GWP approved (see 

EPA–HQ–OAR–2009–0927– 

0273, February 24, 2012). 

perfluoroethyl vinyl ether ..................................... 10493–43–3 C4F8O 3 Submitted with provisional GWP request for DuPont de Nemours, no 

provisional GWP approved (see 

EPA–HQ–OAR–2009–0927– 

0273, February 24, 2012). 

HFC–1234yf ......................................................... 754–12–1 C3H2F4 4 Submitted with provisional GWP request for Honeywell International, 

no provisional GWP approved 

(see EPA–HQ–OAR–2009–0927– 

0273, February 24, 2012). 

perfluorethyl iodide (2–I) ...................................... 354–64–3 C2F5I 3 Submitted in August 2012 by DuPont de Nemours. 

perfluorbutyl iodide (PFBI, 42–I) ......................... 423–39–2 C4F9I 3 Submitted in August 2012 by DuPont de Nemours. 

perfluorhexyl iodide (6–I) ..................................... 355–43–1 CF3CF2CF2CF2CF2CF2

IC6F13I 

2 Submitted in August 2012 by DuPont de Nemours. 

perfluoroctyl iodide (8–I) ...................................... 507–63–1 C8F17I 2 Submitted in August 2012 by DuPont de Nemours. 

1,1,1,2,2-pentafluoro-4-iodo butane (22–I) .......... 40723–80–6 C4H4F5I 2 Submitted in August 2012 by DuPont de Nemours. 

1,1,1,2,2,3,3,4,4-nonafluoro-6-iodo hexane (42– 

I).

2043–55–2 C6H4F9I 2 Submitted in August 2012 by DuPont de Nemours. 

perfluorobutyl ethene (42–U) ............................... 19430–93–4 C6H3F9 2 Submitted in August 2012 by DuPont de Nemours 

perfluorohexyl ethene (62–U) .............................. 25291–17–2 C8H3F13 1 Submitted in August 2012 by DuPont de Nemours. 

perfluorooctyl ethene (82–U); .............................. 21652–58–4 C10H3F17 1 Submitted in August 2012 by DuPont de Nemours. 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
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20The methods used assumed that these gases 

were well-mixed; this underestimates the 

concentration of O3 and overestimates the 

concentration of OH to which the compound is 

actually exposed. The overestimate of the OH 

concentration has a greater effect on the reaction 

rate and estimated lifetime of the compound. 

21 3M Company. ‘‘3MTM NovecTM 1230 Fire 

Protection Fluid.’’ 2009. Available online at: 

http://multimedia.3m.com/mws/

mediawebserver?mwsId=66666UF6EVsSyXTtlXfyn8

TEEVtQEVs6EVs6EVs6E666666-&fn=prodinfo_

novec1230.pdf. 

22See Docket ID No. EPA–HQ–OAR–2012–0934. 

TABLE 3—PROPOSED F–GHGS WITH GWPS FOR TABLE A–1—Continued 

Chemical designation or common name CAS No. Chemical formula Proposed 

GWP 

Origin of compound and GWP assessments 

1H,1H, 2H,2H-perfluorohexan-1-ol (42–AL) ........ 2043–47–2 C6H5F9O 5 Submitted in August 2012 by DuPont de Nemours. 

FK–5–1–12; NovecTM 612; FK–5–1–12myy2; nPerfluorooctane; Octanedecafluorooctane.756–13–8 CF3CF2C(O)CF(CF3)2 1.8 Published under EPA’s SNAP Program (40 CFR part 82) and identified in manufacturer’s literature. 

FK–6–1–12/NovecTM 774, C7 Fluoroketone ....... 813–44–5 and 

813–45–6 

C7F14O Chemical 

Blend 

1 Published under EPA’s SNAP Program (40 CFR part 82). 

trans-1-chloro-3,3,3-trifluoroprop-1-ene ............... 2730–43–0 C3H2ClF3 7 Published under EPA’s SNAP Program (40 CFR part 82) and identified in peer reviewed literature. 

PFC–6–1–16; Hexadecafluoroheptane ............... 335–57–9 C7F16 7930 Identified in peer reviewed literature. 

PFC–7–1–18; Octadecafluorooctane .................. 307–34–6 C8F18 8340 Identified in peer reviewed literature. 

For the first 11 compounds in Table 

3 (seven with approved provisional 

GWPs and the four without approved 

provisional GWPs), the EPA determined 

that the methods used to estimate the 

GWPs were likely to overestimate the 

GWPs by an order of magnitude or more 

(see Docket ID No. EPA–HQ–OAR– 

2009–0927–0256). These compounds 

are all relatively short-lived, and the 

analyses to determine the GWP for these 

compounds used the simplifying 

assumptions that the compounds are 

well-mixed in the atmosphere. In 

general, the assumption that short-lived 

compounds are well-mixed 

overestimates the radiative forcing of 

these gases and may affect estimates of 

the atmospheric lifetime. Because of this 

simplifying assumption, the proposed 

GWPs are likely to be overestimates. 

However, the EPA has determined that 

the proposed GWPs for these short-lived 

gases represent the most current, peerreviewed, scientific knowledge of the 

radiative properties and lifetimes of 

these gases. For subpart L reporters, the 

proposed GWPs would provide a more 

accurate calculation of CO2e emissions 

than the default GWPs required under 

40 CFR 98.123(a). Furthermore, because 

the GWP of each of these 11 F–GHGs is 

very low (i.e., between 0.02 and 6, as 

shown in Table 3 of this preamble), the 

EPA has determined that the proposed 

GWPs would not significantly 

overestimate source category emissions 

or supply and are acceptable for the 

purposes of calculating emissions under 

Part 98. 

For the ten F–GHGs submitted by 

DuPont on August 21, 2012, the 

radiative efficiency of each compound is 

derived using a constant mixing ratio of 

the compounds in the troposphere (i.e., 

the methods assume that the 

compounds are well-mixed). These 

compounds are all anticipated to be 

short-lived in the atmosphere. 

Therefore, the constant mixing ratio 

likely overestimates the share of these 

compounds that reside higher in the 

atmosphere and consequently 

overestimates the radiative efficiency 

(and GWP). For four of the 10 

compounds, the approach used to 

calculate the atmospheric lifetimes 

likely underestimates the lifetimes of 

these compounds.20 However, the 

radiative efficiency calculation is likely 

to outweigh the underestimated 

lifetimes. The EPA reviewed recent 

research that suggests the approach used 

to determine the radiative efficiency for 

these compounds can result in 

overestimates of the 100-year GWP of 49 

to 233 percent (see ‘‘GWP 

Determinations for Proposed Additional 

F–GHGs for Table A–1,’’ Docket ID No 

EPA–HQ–OAR–2012–0934 for 

additional information on this analysis). 

The available estimates for these GWPs 

are likely upper bounds, because these 

are short-lived, low-GWP gases. We are 

proposing to include the GWPs for these 

ten F–GHGs in Table A–1 of subpart A. 

Because the GWP of each F–GHG is very 

low (i.e., between 1 and 5, as shown in 

Table 3), the EPA has determined that 

the proposed GWPs would not 

significantly overestimate source 

category emissions or supply and are 

acceptable for the purposes of 

calculating emissions under Part 98. 

For the five F–GHGs identified 

through scientific assessments 

published through EPA’s SNAP program 

or in peer-reviewed literature, the EPA 

evaluated the estimation methods used 

to determine the GWP for each 

compound. The EPA’s determination for 

each compound (identified by common 

name) and the proposed GWPs are as 

follows: 

• FK–5–1–12 (NovecTM 612, NovecTM

1230). FK–5–1–12 is a fluorinated 

ketone; it is known under the trade 

name NovecTM 612 when used as a 

magnesium cover gas and as NovecTM

1230 when used as a fire suppression 

agent. Product information provided by 

the manufacturer provides a GWP 

estimate of 1 for a 100-year integration 

using IPCC 2007 calculation methods.21

An analysis of the GWP of FK–5–1–12 

was also performed through EPA’s 

SNAP Program.22 The SNAP analysis 

considered two scientific reports that 

provided estimates of atmospheric 

lifetime and radiative efficiency, and 

determined that the total GWP of FK–5– 

1–12 (integrated over a 100-year time 

horizon and calculated using the IPCC 

approach) would likely have a value 

between 0.6 and 1.8. The total GWP 

comprises a direct value of less than 1 

but greater than zero plus an indirect 

GWP of 0.56 to 0.84, based on 4 to 6 

carbons available for conversion to CO2. 

The EPA is conservatively proposing a 

GWP of 1.8. For the upper-bound value, 

the methods used to evaluate the 

radiative efficiency for FK–5–1–12 

assumed a constant mixing ratio for the 

compound, which likely overestimated 

the radiative efficiency and the GWP. 

Because the proposed GWP of the 

compound is so low, we do not 

anticipate that the proposed value 

would result in substantial overreporting for the magnesium production 

source category. 

• FK–6–1–12 (NovecTM 774, C7 

Fluoroketone). The compound FK–6–1– 

12 (also produced under the trade name 

NovecTM 774), is a blend of two isomers: 

3-pentanone,1,1,1,2,4,5,5,5-octafluoro2,4-bis(trifluoromethyl) and 3- 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
19814 Federal Register / Vol. 78, No. 63 / Tuesday, April 2, 2013 / Proposed Rules 

23See ‘‘Protection of Stratospheric Ozone: 

Determination 27 for Significant New Alternatives 

Policy Program,’’ Docket ID No. EPA–HQ–OAR– 

2012–0934. 

24See ‘‘Protection of Stratospheric Ozone: 

Determination 27 for Significant New Alternatives 

Policy Program,’’ Docket ID No. EPA–HQ–OAR– 

2012–0934. 

25Andersen, M.P.S., E.J.K. Nilsson, O.J. Nielsen, 

M.S. Johnson, M.D. Hurley, and T.J. Wallington. 

2008. Atmospheric chemistry of trans-CF3CH CHCl: 

Kinetics of the gas-phase reactions with Cl atoms, 

OH radicals, and O3. J. Photochem. Photobiol. A: 

Chemistry 199: 92–97. 

26Wang D., Olsen S., Wuebbles D. 2011. 

‘‘Preliminary Report: Analyses of tCFP’s Potential 

Impact on Atmospheric Ozone.’’ Department of 

Atmospheric Sciences. University of Illinois, 

Urbana, IL. September 26, 2011. 

27Wang, D., Wuebbles, D.J., Patten, K.O., and 

Olsen, S.C. In draft. Climate advantages of proposed 

short-lived compounds as replacements for longerlived HCFCs and HFCs. Department of Atmospheric 

Sciences, University of Illinois at UrbanaChampaign, Urbana, Illinois. Draft report, undated. 

28 Ivy, D.J., M. Rigby, M. Baasandorj, J. B. 

Burkholder, and R. G. Prinn. 2012. Global emission 

estimates and radiative impact of C4F10, C5F12, 

C6F14, C7F16 and C8F18. Atmos. Chem. Phys., 12: 

7635–7645. DOI:10.5194/acp–12–7635–2012. 

hexanone,1,1,1,2,4,4,5,5,6,6,6- 

undecafluoro-2-(trifluoromethyl). The 

GWP of FK–6–1–12 was previously 

evaluated and published under EPA’s 

SNAP Program.23 The SNAP analysis 

provided a 100-year integrated GWP of 

approximately 1, therefore, we are 

proposing to include a GWP value of 1 

in Table A–1. The compound also has 

a chemical structure similar to that of 

FK–5–1–12, therefore, we anticipate a 

similar lifetime and GWP for these 

compounds. 

• trans-1-chloro-3,3,3-trifluoroprop-1- 

ene. The compound trans-1-chloro3,3,3-trifluoroprop-1-ene (trade name 

SolsticeTM 1233zd(E)) is a polyurethane 

foam blowing agent useful in 

applications such as thermal insulation 

in appliances and residential and 

commercial buildings. An analysis of 

the GWP of trans-1-chloro-3,3,3- 

trifluoroprop-1-ene was previously 

performed through EPA’s SNAP 

Program.24 As part of the SNAP 

analysis, the EPA considered two 

studies, Anderson et al. (2008) 25 and 

Wang et al. (2011),26 and established a 

GWP of between 4.7 and 7 and an 

atmospheric lifetime of approximately 

26 to 31 days. In its evaluation, the EPA 

has given weight to the peer-reviewed 

analysis by Anderson et al. (2008), 

which calculates a GWP of 7. We are 

also considering research by Wang et al. 

(In draft) 27 which calculates a lifetime 

of 30.5 days and estimates a GWP of 4.7. 

The model used by Wang et al. accounts 

for the shorter lifetime and reduced 

mixing of the trans-1-chloro-3,3,3- 

trifluoroprop-1-ene compound, and may 

provide a more accurate estimate of the 

GWP. Although the latter two of the 

studies cited (from the same author) 

give a GWP of 4.7, the EPA has 

determined that it is more appropriate 

to use the GWP from the first study, as 

it comes from a peer-reviewed journal 

article. Also, consistent with the 

reasoning for choosing possibly upperbound GWPs for other chemicals in 

Table 3 of this preamble, the EPA has 

concluded that using the GWP of 7 

rather than 4.7 would not significantly 

overestimate source category emissions 

or supply and is acceptable for the 

purposes of calculating emissions under 

Part 98. 

• PFC 6–1–16 and PFC 7–1–18. The 

perfluorocarbons (PFCs) C7F16 and C8F18

are used as heat transfer fluids and in 

vapor phase reflow soldering in the 

electronics manufacturing industry. 

There are no previous estimates of the 

GWPs for these gases. Ivy et al. (2012) 28

have recently provided emission 

estimates and measured infrared spectra 

of these PFCs to estimate the GWPs. 

These compounds have an estimated 

atmospheric lifetime of 3,000 years and 

are expected to be well-mixed in the 

atmosphere. Because the expected 

lifetimes of these PFCs are much longer 

than the 100-year time horizon used to 

calculate the GWP, they are relatively 

insensitive to the estimated lifetime. 

Furthermore, the methods and 

assumptions used by Ivy et al. (2012) are 

generally considered reliable for longlived gases. Therefore, we are proposing 

the GWPs for these two compounds as 

presented by Ivy et al., as listed in Table 

3 of this preamble. 

A complete analysis of each of these 

compounds and the proposed GWPs are 

included in the memorandum, ‘‘GWP 

Determinations for Proposed Additional 

F–GHGs for Table A–1,’’ Docket ID No. 

EPA–HQ–OAR–2012–0934. 

Request for additional information. 

The GWPs we are proposing in Table A– 

1 are based on the data available to the 

EPA at the time of this proposed 

rulemaking. We specifically solicit 

comment on the proposed GWPs for the 

26 compounds we are proposing in 

Table A–1, including submittal of 

additional data or analyses that may 

support more accurate estimates of the 

GWP or that support the GWP 

estimation methods that are currently 

provided. 

For commenters providing new 

estimates of GWPs for the proposed 

compounds for inclusion in Table A–1, 

we request that the commenter submit 

the following types of scientific data 

and analyses to support the estimated 

GWP: 

(1) Data and analysis related to the 

low-pressure gas phase infrared 

absorption spectrum of the compound; 

(2) Data and analysis related to 

reaction mechanisms and rates such as 

photolysis and reaction with 

atmospheric components such as 

hydroxyl radicals (OH), ozone (O3), 

carbon monoxide (CO), and water; 

(3) Radiative transfer analyses that 

integrate the lifetime and infrared 

absorption spectrum data to calculate 

the GWP; or, 

(4) Published or unpublished studies 

of the GWP of the compound. 

The EPA intends to review and 

consider additional information 

submitted during the public comment 

period to assess the proposed GWPs and 

consider other accurate estimates of the 

GWP for each compound. We anticipate 

requesting comment on additional 

compounds in a separate action. 

2. Other Technical Corrections and 

Proposed Amendments to Subpart A 

In addition to the proposed 

amendments to global warming 

potentials in Table A–1, we are also 

proposing 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. Additional minor 

corrections are discussed in the Table of 

Revisions to this rulemaking (see Docket 

ID No. EPA–HQ–OAR–2012–0934). 

The EPA is proposing to revise the 

reporting requirements of 40 CFR 

98.3(c)(1). Section 98.3(c)(1) requires 

reporting of the physical address of the 

facility where the emissions occur (not 

the parent company address). Some 

facilities do not have a physical street 

address assigned to them and their 

mailing address is not co-located with 

their facility operations. In order to 

more accurately report the physical 

location of these facilities, the EPA is 

proposing that those without a physical 

address at their operations site provide 

latitude and longitude coordinates 

instead. This proposed addition is not 

intended as an option for any facility 

whose physical address coincides with 

their facility operations. It also is not 

intended for use by suppliers and 

importers and/or exporters covered by 

Part 98, or facilities reporting under 

subpart W in the natural gas distribution 

(40 CFR 98.230(a)(8)) or onshore 

petroleum and natural gas production 

(40 CFR 98.230(a)(2)) industry segments. 

We are proposing to add a 

requirement to 40 CFR 98.3(c)(13) for all 

facilities with a power generating unit to 

report the facility Office of the 

Regulatory Information System (ORIS) 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 78, No. 63 / Tuesday, April 2, 2013 / Proposed Rules 19815 

29Letter from Craig Holt Segall, Sierra Club 

Environmental Law Program, on behalf of the Sierra 

Club, Center for Biological Diversity, Clean Air Task 

Force, Clean Wisconsin, the Kentucky 

Environmental Foundation, the Minnesota Center 

for Environmental Advocacy, and the Natural 

Resources Defense Council to Lisa Jackson, U.S. 

EPA. Petition for Rulemaking To Correct Emission 

Factors in the Mandatory Greenhouse Gas Reporting 

Rule. October 28, 2010. 

code for each power generation unit. 

The proposed amendment would 

facilitate the verification of emissions 

information received by the EPA. The 

EPA is also proposing to add the 

following definition for ORIS code in 40 

CFR 98.6 for clarity, ‘‘ORIS Code’’ 

means the unique identifier assigned to 

each power plant in the National 

Electric Energy Data System (NEEDS). 

The ORIS code is a four digit number 

assigned by the Energy Information 

Administration (EIA) at the U.S. 

Department of Energy to power plants 

owned by utilities.’’ 

We are proposing to add a provision 

to 40 CFR 98.3(c)(11) to include 

instructions for the reporting of a United 

States parent company legal name and 

address. The proposed amendment 

would specify that a facility or supplier 

must use the reporting instructions 

found in e-GGRT when reporting a 

parent company. The proposed 

amendment would facilitate verification 

of the emissions reported by allowing 

the EPA to provide a common naming 

convention through e-GGRT that would 

be used to easily identify parent 

companies and to accurately attribute 

GHG emissions to the correct parent 

companies. Instructions regarding 

reporting of parent company name and 

address have been posted to the docket 

for this action (See docket ID no. EPA– 

HQ–OAR–2012–0934). 

Additionally, we are proposing to 

amend 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). Specifically, we are clarifying the 

timing requirements for approval or 

denial of the automatic 30-day 

extension and any subsequent 

extensions provided in 40 CFR 

98.3(h)(4). The proposed amendments 

would require reporters to submit a 

request for any additional extension 

beyond the 30-day automatic extension 

at least 5 business days prior to the 

expiration of the initial 30-day 

extension. If the request demonstrates 

that it is not practicable to submit the 

data or information needed to resolve a 

potential reporting error following the 

30-day automatic extension, the 

Administrator may approve an 

additional extension request. The 

proposed amendment would provide a 

reasonable timeline for reporters to 

submit extension requests and for the 

EPA’s collection and verification of 

reported data. 

We are proposing to add a definition 

of fluidized bed combustor (FBC) to 40 

CFR 98.6. The definition is necessary to 

be consistent with the proposed 

addition of FBC-specific N2O emission 

factors for coal, waste anthracite (culm), 

and waste bituminous (gob) to Table C– 

2. 

Finally, we are proposing revisions to 

the definitions of three terms in subpart 

A: degasification system, ventilation 

well or shaft, and ventilation system. 

These terms are used only in subpart 

FF, Underground Coal Mines, and are 

proposed to be revised to more closely 

align with common terminology used in 

the coal mining industry. 

B. Subpart C—General Stationary Fuel 

Combustion Sources 

We are proposing revisions to the 

requirements of 40 CFR part 98, subpart 

C (General Stationary Fuel Combustion 

Sources) to clarify the use of the Tier 

methodologies and to update high heat 

value (HHV) and emission factors. The 

more substantive corrections, clarifying, 

and other amendments to subpart C are 

found here. Additional minor 

corrections are discussed in the Table of 

Revisions to this rulemaking (see Docket 

ID No. EPA–HQ–OAR–2012–0934). 

First, we are proposing to amend 40 

CFR 98.33(b)(1) to expand the use of the 

Tier 1 methodology in one situation that 

currently requires the use of the Tier 3 

methodology. Generally, subpart C 

requires the use of the Tier 3 

methodology for combustion units that 

are greater than 250 million Btus per 

hour for all fuels listed in Table C–1, 

and, for fuels not listed in Table C–1 if 

the fuel provides 10 percent or more of 

the annual heat input to the unit. To 

reduce the monitoring burden of 

determining carbon content of Table C– 

1 fuels that are used in relatively small 

amounts annually, we are proposing a 

change to 40 CFR 98.33(b)(1) 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. 

We are proposing changes to Table 

C–1 to update the HHV and emission 

factors for several fuels and to add 

emission factors for culm and gob. The 

EPA received a number of comments 

and questions through the GHGRP Help 

Desk with suggestions for improvements 

to these factors. We researched these 

factors to ensure the most scientifically 

valid values were reflected. An analysis 

of the proposed changes to Table C–1 as 

a result of this research can be found in 

the memorandum ‘‘Review and 

Evaluation of 40 CFR Part 98 CO2

Emission Factors for EPW07072 TO 45,’’ 

available in Docket ID No. EPA–HQ– 

OAR–2012–0934. 

In response to a Petition for 

Rulemaking (‘‘Sierra Club Petition’’),29

the EPA evaluated establishing separate 

(from the parent coal) CO2 emission 

factors for culm and gob in Table C–1. 

The EPA is proposing the addition of 

culm and gob to Table C–1. These 

separate entries have been added to 

clarify that the Table C–1 CO2 emission 

factors for anthracite coal and 

bituminous coal should be used for 

culm and gob, respectively. Because the 

heating value of culm or gob is variable 

and quite different from the parent 

anthracite or bituminous coals, the EPA 

is proposing that the default heating 

values in Table C–1 for anthracite and 

bituminous may not be used for culm 

and gob. The changes to Table C–1 

specify that the HHV for culm or gob 

must be measured according to the Tier 

2 Methodology. Our analysis and 

development of emission factors can be 

found in the memorandum ‘‘Emission 

Factor Updates for Fluidized Bed 

Boilers and Other Revisions to Tables 

C–1 and C–2 of 40 CFR Part 98— 

Summary’’ available in Docket Id. No. 

EPA–HQ–OAR–2012–0934. Because the 

Tier 1 Methodology allows the use of 

default HHVs from Table C–1, we 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
19816 Federal Register / Vol. 78, No. 63 / Tuesday, April 2, 2013 / Proposed Rules 

propose revising 40 CFR 98.33(b)(1) to 

prohibit use of the Tier 1 Methodology 

when estimating the emissions from 

combustion of culm or gob. With these 

revisions and those proposed with 

respect to fluidized bed combustors in 

this Section II.B., infra, we believe that 

we have fully addressed the Petition for 

Rulemaking. 

Table 4 of this preamble shows a 

summary of the proposed Table C–1 

revisions, and major changes are 

explained below. 

TABLE 4—PROPOSED CHANGES TO TABLE C–1 TO SUBPART C—DEFAULT CO2 EMISSION FACTORS AND HIGH HEAT

VALUES FOR VARIOUS TYPES OF FUEL

Current values Proposed values 

Fuel type Default high heat value Default CO2 emission 

factor Default high heat value Default CO2 emission 

factor Coal and coke mmBtu/short ton kg CO2/mmBtu 

Anthracite ................................................ 25.09 ............................ 103.54 .......................... No change ................... 103.69 

Waste Anthracite (Culm) ........................ ...................................... ...................................... See footnote 1 ............. 103.69 

Bituminous .............................................. 24.93 ............................ 93.40 ............................ No change ................... 93.28 

Waste Bituminous (Gob) ........................ ...................................... ...................................... See footnote 1 ............. 93.28 

Subbituminous ........................................ 17.25 ............................ 97.02 ............................ No change ................... 97.17 

Lignite ..................................................... 14.21 ............................ 96.36 ............................ No change ................... 97.72 

Coal Coke [Fuel type changed from 

‘‘coke’’].

24.80 ............................ 102.04 .......................... No change ................... 113.67 

Mixed (Commercial sector) .................... 21.39 ............................ 95.26 ............................ No change ................... 94.27 

Mixed (Industrial coking) ........................ 26.28 ............................ 93.65 ............................ No change ................... 93.90 

Mixed (Industrial sector) ......................... 22.35 ............................ 93.91 ............................ No change ................... 94.67 

Mixed (Electric Power sector) ................ 19.73 ............................ 94.38 ............................ No change ................... 95.52 

Natural gas mmBtu/scf kg CO2/mmBtu .................................

(Weighted U.S. Average) ....................... 1.028 × 10¥3 ............... 53.02 ............................ 1.026 × 10¥3 ............... 53.06 

Petroleum products mmBtu/gallon ............... kg CO2/mmBtu ............. .................................

Used Oil .................................................. 0.135 ............................ 74.00 ............................ 0.138 ............................ No change 

Liquefied petroleum gases (LPG) .......... 0.092 ............................ 62.98 ............................ No change ................... 61.71 

Propane .................................................. 0.091 ............................ 61.46 ............................ No change ................... 62.87 

Propylene ................................................ 0.091 ............................ 65.95 ............................ No change ................... 67.77 

Ethane .................................................... 0.069 ............................ 62.64 ............................ 0.068 ............................ 59.60 

Ethylene .................................................. 0.100 ............................ 67.43 ............................ 0.058 ............................ 65.96 

Isobutane ................................................ 0.097 ............................ 64.91 ............................ 0.099 ............................ 64.94 

Isobutylene ............................................. 0.103 ............................ 67.74 ............................ No change ................... 68.86 

Butane .................................................... 0.101 ............................ 65.15 ............................ 0.103 ............................ 64.77 

Butylene .................................................. 0.103 ............................ 67.73 ............................ 0.105 ............................ 68.72 

Natural Gasoline ..................................... 0.110 ............................ 66.83 ............................ No change ................... 66.88 

Petrochemical Feedstocks ..................... 0.129 ............................ 70.97 ............................ 0.125 ............................ 71.02 

Unfinished Oils ....................................... 0.139 ............................ 74.49 ............................ No change ................... 74.54 

Heavy Gas Oils ...................................... 0.148 ............................ 74.92 ............................ No change ................... No change 

Crude Oil ................................................ 0.138 ............................ 74.49 ............................ No change ................... 74.54 

Other fuels-solid ..................................... mmBtu/short ton kg CO2/mmBtu .................................

Tires ........................................................ 26.87 ............................ 85.97 ............................ 28.00 ............................ No change 

Biomass fuels—solid mmBtu/short ton kg CO2/mmBtu .................................

Wood and Wood Residuals(dry basis) 

[Fuel Type description changed from 

Wood and Wood Residuals].

15.38 ............................ 93.80 ............................ 17.48 ............................ No change 

Solid Byproducts ..................................... 25.83 ............................ 105.51 .......................... 10.39 ............................ No change 

Biomass fuels—gaseous mmBtu/scf kg CO2/mmBtu .

Landfill Gas [Fuel type description 

changed from Biogas (captured methane).

0.841 × 10¥3 ............... 52.07 ............................ 0.485 × 10¥3 ............... No change 

Other Biomass Gases [New Fuel type 

added].

...................................... ...................................... 0.655 × 10¥3 ................ 52.07 

Biomass Fuels—Liquid mmBtu/gallon kg CO2/mmBtu ......................................

Biodiesel ................................................. 0.128 ............................ 73.84 ............................ Deleted Duplicate.

Note: ‘‘No change’’ indicates no changes to the current value. Additional footnotes have been added to the table. 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
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30Letter from Paul Noe, American Forest & Paper 

Association, and Robert Glowinski, American Wood 

Council, to Lisa Jackson, U.S. EPA. Petition for 

Reconsideration of 40 CFR Part 98 Subparts C and 

AA; Petition for Rulemaking To Revise 40 CFR Part 

98 Subparts C and AA; Request for Correction 

Under Information Quality Act. November 16, 2012. 

The changes include a change to the 

HHV for wood and wood residuals. The 

HHV in Table C–1 for Wood and Wood 

Residuals is a wet basis value that 

assumes a moisture content of 12 

percent. GHGRP reporters have 

indicated that they use wood fuel with 

highly variable moisture content, and so 

the existing factor results in calculation 

inaccuracies of CO2 emissions from 

burning this fuel. These reporters have 

requested that the EPA provide HHVs 

for a range of moisture contents for 

wood fuel. In order to address this issue, 

we are proposing an addition to Table 

C–1 for ‘‘Wood and Wood Residuals on 

a dry basis,’’ with a footnote containing 

an equation that can be used to adjust 

the value for any moisture content. 

Reporters can then calculate a HHV for 

use in Equation C–1 using the moisture 

content of their facility specific fuel. We 

are also proposing a change to Table C– 

1 that replaces the one HHV for ‘‘Biogas 

(captured methane)’’ with values for two 

types of biogas: ‘‘Landfill Gas’’ and 

‘‘Other Biomass Gases.’’ The CH4

content of landfill gas (approximately 50 

percent) is typically lower than the CH4

concentration in digester gas 

(approximately 65 percent), and the 

proposed emission factors reflect these 

concentration values. 

Revisions are proposed to the HHV 

and emission factors for the individual 

components of liquid petroleum gases 

(LPG) including propane, propylene, 

ethane, ethylene, isobutane, 

isobutylene, butane, and butylene. Since 

the HHV for these LPGs are presented 

on the basis of million Btu per gallon, 

and these compounds are gases under 

standard conditions, the heating value 

must be presented using a stated 

temperature and pressure. For all LPG 

except ethylene, we are proposing 

estimates of HHV at 60 degrees 

Fahrenheit (°F) and saturation pressure. 

For ethylene, since it cannot be 

liquefied above 48.6°F, we have selected 

a value for HHV that is determined at 

41°F (slightly under the critical 

temperature) and the corresponding 

saturation pressure. The emission 

factors for these compounds have also 

been updated using the proposed HHV 

and the fraction of carbon contained in 

the compound. 

We are proposing a correction to the 

emission factor for coke because it 

appears that the emission factor 

currently in Table C–1 was 

inadvertently listed as the emission 

factor for petroleum coke. We have also 

changed the name in Table C–1 to ‘‘coal 

coke’’ to differentiate this substance 

from ‘‘petroleum coke,’’ which has a 

different HHV and EF. We are also 

proposing updated emission factors for 

the four types of coal and the four listed 

factors for mixed coals based on the 

most recent version of the factors used 

in the Inventory. 

The HHV for the biomass fuel ‘‘solid 

byproducts’’ would be revised to reflect 

the average of the solid byproducts 

consumed by the facilities that reported 

HHV in the 1999 survey conducted by 

the Energy Information Administration. 

The proposed value is presented on a 

wet basis, and is more consistent with 

other biomass fuels. Based on our 

research, we are also proposing minor 

changes to the HHV and/or emission 

factors for the following substances: 

natural gas, used oil, petrochemical 

feedstocks, and tires. Other proposed 

changes to Table C–1 include updates to 

emission factors and HHV based on our 

latest research and to standardize 

conversion factors. These corrections 

are 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). 

We are also proposing to revise 40 

CFR 98.33(e)(3)(iv). The method in 40 

CFR 98.33(e)(3)(iv) for calculating 

biogenic CO2 emissions from municipal 

solid waste (MSW) combustion requires 

the use of a default factor for the 

biogenic share of CO2. We are proposing 

a change to the default factor used to 

determine the annual biogenic CO2

emissions from MSW from 0.6 to 0.55 to 

reflect trends in waste composition. The 

complete analysis of this change can be 

found in the memorandum ‘‘Review and 

Evaluation of 40 CFR Part 98 CO2

Emission Factors for EPW07072 TO 45,’’ 

available in Docket ID No. EPA–HQ– 

OAR–2012–0934. 

The EPA received a Petition for 

Reconsideration and Rulemaking from 

the American Forest & Paper 

Association (AF&PA) and the American 

Wood Council (AWC) on November 16, 

2012 (hereafter referred to as ‘‘AF&PA 

Petition’’).30 The AF&PA Petition 

included a recent study containing new 

methane (CH4) and nitrous oxide (N2O) 

emissions test data in support of a 

request that EPA revise the CH4 and 

N2O emission factors in Subparts AA 

and C for combustion of spent pulping 

liquor and wood residuals. The EPA 

reviewed the basis for the current 

emission factors, integrated the 

emissions test data provided by 

Petitioners with previously available 

data, and is proposing to update the 

spent pulping liquor and wood residual 

combustion emission factors in subparts 

AA and C, respectively. 

Table 5 of this preamble summarizes 

the proposed Table C–2 revisions, and 

major changes are explained below. 

TABLE 5—PROPOSED CHANGES TO TABLE C–2 TO SUBPART C–DEFAULT CH4 AND N2O EMISSION FACTORS FOR

VARIOUS TYPES OF FUEL

Current values Proposed values 

Fuel type Default CH4

emission factor 

Default N2O 

emission factor 

Default CH4

emission factor 

Default N2O 

emission factor 

Coal and Coke (All fuel types in Table C–1) 1

(Footnote Added).

1.1 × 10¥02 ................ 1.6 × 10¥03 ................ 1.1 × 10¥02 ................ 1.6 × 10¥03

Anthracite for FBCs only 2 .............................. N/A ............................. N/A ............................. 1.1 × 10¥02 ................ 1.6 × 10¥01

Waste Anthracite (Culm) for FBCs only 2 ...... N/A ............................. N/A ............................. 1.1 × 10¥02 ................ 4.0 × 10¥01

Bituminous for FBCs only 2 ............................ N/A ............................. N/A ............................. 1.1 × 10¥02 ................ 1.3 × 10¥01

Waste Bituminous (Gob) for FBCs only 2 ...... N/A ............................. N/A ............................. 1.1 × 10¥02 ................ 2.9 × 10¥01

Subbituminous for FBCs only 2 ...................... N/A ............................. N/A ............................. 1.1 × 10¥02 ................ 6.5 × 10¥02

Lignite for FBCs only 2 ................................... N/A ............................. N/A ............................. 1.1 × 10¥02 ................ 1.1 × 10¥01

Fuel Gas ......................................................... N/A ............................. N/A ............................. 3.0 × 10¥03 ................ 6.0 × 10¥04


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19818 Federal Register / Vol. 78, No. 63 / Tuesday, April 2, 2013 / Proposed Rules 

TABLE 5—PROPOSED CHANGES TO TABLE C–2 TO SUBPART C–DEFAULT CH4 AND N2O EMISSION FACTORS FOR

VARIOUS TYPES OF FUEL—Continued 

Current values Proposed values 

Fuel type Default CH4

emission factor 

Default N2O 

emission factor 

Default CH4

emission factor 

Default N2O 

emission factor 

Biomass Fuels—Solid (All fuel types in Table 

C–1, except wood and wood residuals) 

(Added to parenthetical: ‘‘except wood and 

wood residuals’’).

3.2 × 10¥02 ................ 4.2 × 10¥03 ................ 3.2 × 10¥02 ................ 4.2 × 10¥03

Wood and wood residuals ............................. .................................... .................................... 7.2 × 10¥3 ................. 3.6 × 10¥3

Biomass Fuels-Gaseous (All fuel types in 

Table C–1) Changed category from ‘‘Biomass’’.

3.2 × 10¥03 ................ 6.3 × 10¥04 ................ 3.2 × 10¥03 ................ 6.3 × 10¥04

N/A = No current emission factor available. 

1 Use of the default emission factors for the coal and coke category may not be used to estimate emissions from combusting anthracite, waste 

anthracite, bituminous, waste bituminous, subbituminous, or lignite coal burned in an FBC. 2 Use of these default emission factors is required for FBCs burning the specified coal type. 

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. 

Specifically, based on our analysis of 

this emissions test data, we are 

proposing to add a row for wood and 

wood residuals in Table C–2 that 

contains CH4 and N2O emission factors 

addressing those submitted to EPA with 

the AF&PA Petition. We integrated that 

data with previously available 

emissions test data in order to consider 

all of the information available to us in 

developing the new default emission 

factors for wood and wood residuals. 

Our analysis of the test data can be 

found in the memorandum ‘‘Kraft 

Pulping Liquor and Woody Biomass 

Methane (CH4) and Nitrous Oxide (N2O) 

Emission Factor Literature Review’’ 

available in Docket Id. No. EPA–HQ– 

OAR–2012–0934. 

We are also proposing to add coal, 

culm, and gob N2O emission factors to 

Table C–2 specific to fluidized bed 

combustors. As referenced above in 

response to the Sierra Club Petition, the 

EPA reviewed multiple studies that 

indicate that N2O emissions from 

fluidized bed combustors burning coal, 

culm, and gob are significantly higher 

than from conventional combustion 

technologies. The EPA agrees our 

analysis and development of emission 

factors (including a discussion of 

emission factors for culm and gob) can 

be found in the memorandum 

‘‘Emission Factor Updates for Fluidized 

Bed Boilers and Other Revisions to 

Tables C–1 and C–2 of 40 CFR Part 98— 

Summary’’ available in Docket Id. No. 

EPA–HQ–OAR–2012–0934. 

We are proposing to add ‘‘fuel gas’’ to 

Table C–2 of subpart C to address a 

program gap discovered through the 

verification process. Because fuel gas is 

not currently included in Table C–2, 

instructions are included in subparts X 

and Y to use the default CH4 and N2O 

emission factors for ‘‘Petroleum (All fuel 

types in Table C–1)’’ to calculate CH4

and N2O emissions from fuel gas 

combustion. However, for facilities that 

do not report under subpart X or Y, 

there is currently no requirement to 

calculate CH4 and N2O emissions from 

fuel gas combustion. The proposed 

revision addresses this unintentional 

gap. As a result, subpart C reporters 

would be required to report CH4 and 

N2O emissions from fuel gas 

combustion. Fuel gas is defined at 40 

CFR 98.6 as ‘‘gas generated at a 

petroleum refinery or petrochemical 

plant and that is combusted separately 

or in any combination with any type of 

gas.’’ 

C. Subpart H—Cement Production 

We are proposing one revision to the 

reporting requirements of 40 CFR part 

98, subpart H (Cement Production). The 

current Part 98, published on October 

30, 2009, provides that facilities subject 

to subpart H report the monthly cement 

production from each kiln at the facility 

for verification of reported emissions. In 

the preamble to the Technical 

Corrections, Clarifying, and Other 

Amendments to Certain Provisions of 

the Mandatory Greenhouse Gas 

Reporting Rule (75 FR 66434, October 

28, 2010), the EPA stated its intent to 

change the cement production reporting 

requirements under 40 CFR 98.86 to 

require annual, facility-wide cement 

production instead of monthly, kilnspecific cement production (75 FR 

66440). Reporting cement production on 

a kiln-specific basis is inconsistent with 

cement plant manufacturing practices, 

because kilns produce clinker (an 

intermediate product in cement 

manufacturing) and do not make 

cement. Although it was obviously the 

EPA’s intention to revise the rule 

accordingly, inadvertently, this change 

was not reflected in the rule. This 

change is also consistent with the 

requirement in 40 CFR 98.86(b)(3), 

which requires facilities without 

continuous emissions monitoring 

systems (CEMS) to report annual cement 

production at the facility. Therefore, we 

are proposing to amend 40 CFR 

98.96(a)(2) to require reporting of 

facility-wide cement production. 

D. Subpart K—Ferroalloy Production 

We are proposing two corrections to 

subpart K of Part 98 (Ferroalloy 

Production). First, we are proposing to 

revise Equation K–3 of subpart K to 

correct the equation. The equation in 

the current Part 98 does not include a 

conversion factor from kilograms to 

metric tons. Therefore, we are proposing 

to correct Equation K–3 to revise the 

numerical term ‘‘2000/2205’’ to 

‘‘2/2205’’ to account for this conversion. 

Next, we are proposing to amend 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. Per 40 CFR 

98.113(d), ferroalloy production 

facilities are currently required to 

calculate CH4 emissions from each EAF 

used for the production of ferroalloys 

listed in Table K–1. Facilities are 

currently required to report CH4

emissions for EAFs where a CEMS is 

used to measure emissions. However, 

the requirement to report emissions of 

CH4 from EAFs where the carbon mass 

balance procedure is used to measure 

emissions was erroneously omitted from 

the current Part 98. The proposed 

amendments are necessary for 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
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consistent reporting of CH4 emissions 

from all ferroalloy production facilities. 

Because facilities must already monitor 

and calculate emissions of CH4 from 

each EAF, the proposed amendment 

would not impose any additional 

burden on reporters. The proposed data 

reporting element reflects aggregated 

annual information that is currently 

gathered by reporters. 

E. Subpart L—Fluorinated Gas 

Production 

Under subpart L of Part 98 

(Fluorinated Gas Production), the EPA 

is proposing to extend temporary, less 

detailed reporting requirements for 

fluorinated gas producers for an 

additional year. In a final rule published 

on August 24, 2012, the EPA 

promulgated temporary, less detailed 

reporting requirements for reporting 

years 2011 and 2012 (77 FR 51477). As 

discussed in that final rule, this was 

intended to allow the EPA time to 

evaluate concerns raised by the 

producers that EPA release of the more 

detailed reporting required by the 2010 

final rule would reveal trade secrets, 

and to consider how the rule might be 

changed to balance these concerns with 

the need to obtain the data necessary to 

inform the development of future GHG 

policies and programs. The proposed 

extension would require the same less 

detailed reporting for reporting year 

2013 as for reporting years 2011 and 

2012. The extension would allow the 

EPA, as well as stakeholders, to 

consider the various options for 

reporting emissions under subpart L in 

conjunction with EPA’s on-going 

evaluations regarding reporting inputs 

to emission equations for subpart L, 

whose reporting deadline was deferred 

until 2015. Fluorinated gas producers 

and other commenters have often noted 

that whether or not disclosure of a 

particular data element poses 

confidentiality concerns depends on the 

other data that would be required to be 

reported and/or disclosed. The 

extension would allow the various 

potential reporting requirements and 

confidentiality determinations to be 

considered simultaneously. 

F. Subpart N—Glass Production 

We are proposing several clarifying 

revisions to subpart N of Part 98 (Glass 

Production). The more substantive 

corrections, clarifying, and other 

amendments to subpart N are found 

here. Additional minor corrections are 

discussed in the Table of Revisions (see 

Docket ID No. EPA–HQ–OAR–2012– 

0934). 

We are proposing to revise the 

monitoring methods used to measure 

carbonate-based mineral mass-fractions 

to allow for more accurate measurement 

methods and to add flexibility for 

reporters. The current Part 98 requires 

that such measurements are based on 

sampling using ASTM D3682–01 

(Reapproved 2006) Standard Test 

Method for Major and Minor Elements 

in Combustion Residues from Coal 

Utilization Processes 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. 

However, we have determined that 

industry consensus standards that 

specify analysis by X-ray fluorescence 

(e.g., ASTM C25–11 Standard Test 

Methods for Chemical Analysis of 

Limestone, Quicklime, and Hydrated 

Lime and ASTM C1271–99 Standard 

Test Method for X ray Spectrometric 

Analysis of Lime and Limestone) are 

more accurate than ASTM D6349–09, 

which uses inductively coupled plasma 

or ASTM D3682–01, which uses atomic 

absorption. Therefore, we are proposing 

to revise 40 CFR 98.144(b) to specify 

that reporters determining the 

carbonate-based mineral mass fraction 

must use sampling methods that specify 

X-ray fluorescence. We are proposing to 

remove ASTM D6349–09 and ASTM 

D3682–01 from the requirements in 

98.144(b). The proposed amendment 

would allow reporters flexibility in 

choosing a sampling method (since 

multiple X-ray fluorescence methods are 

available) while ensuring that more 

accurate available measurement 

methods are applied. For measurements 

made in the emission reporting year 

2013 or prior years, reporters would 

continue to have the option to use 

ASTM D6349–09 and ASTM D3682–01. 

The EPA is not proposing to have 

reporters revise previously submitted 

annual reports. These facilities would 

have the option, but not be 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 proposing clarifying 

amendments and other corrections to 

Subpart O (HFC–22 Production and 

HFC–23 Destruction); the more 

substantive corrections, clarifying, and 

other amendments to Subpart O are 

found in this section. Additional minor 

corrections to Subpart O are discussed 

in the Table of Revisions (see Docket ID 

No. EPA–HQ–OAR–2012–0934). 

We are proposing to add 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 provisions of 40 CFR 

98.156(c) require facilities that destroy 

HFC–23 to report the concentration 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 

destruction device. However, if the 

concentration during the measurements 

falls below the detection limit of the 

measuring device, the facility will not 

be able to report a specific 

concentration. The proposed sentence 

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. 

H. Subpart P—Hydrogen Production 

We are proposing several clarifying 

revisions to subpart P of Part 98 

(Hydrogen Production). The more 

substantive corrections, clarifying, and 

other amendments to subpart P are 

found here. Additional minor 

corrections are discussed in the Table of 

Revisions (see Docket ID No. EPA–HQ– 

OAR–2012–0934). 

We are proposing to revise 40 CFR 

98.163(b) 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)). If the carbon content 

or molecular weight measurements are 

performed annually, reporters would 

use the annual value as the monthly 

average. If the analyses are performed 

more often than monthly, then the 

reporter would use the arithmetic 

average of these values as the monthly 

average. The term definitions in 

Equations P–1, P–2, and P–3 currently 

refer to the ‘‘results of one or more 

analyses for month n’’; however, the 

monitoring frequencies specified at 40 

CFR 98.163(b)(2), (b)(3) and (b)(4) range 

from weekly to annually, so this 

clarification is necessary to align these 

requirements. Further, we are proposing 

to revise the term definitions in 

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

references to ‘‘one or more analyses’’ 

since multiple analyses in a month are 

not always required, as described above. 

We are also proposing to modify 40 

CFR 98.164(b)(5) to reduce burden by 

adding flexibility to the fuel and 

feedstock analysis requirements, 

consistent with EPA’s original intent 


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and subpart C (40 CFR 98.34(a)(6), 40 

CFR 98.34(b)(4)), and subpart X (40 CFR 

98.244(b)(4)(xiii)). The proposed change 

allows a facility to analyze fuels and 

feedstocks using chromatographic 

analysis, whether continuous or noncontinuous. 

We are proposing to move 

recordkeeping requirements currently 

included in 40 CFR 98.164 (Monitoring 

and QA/QC requirements) to 40 CFR 

98.167 (Records that must be retained). 

Specifically, 40 CFR 98.164(c) and (d) 

will be moved to new paragraphs 40 

CFR 98.167(c) and (d). Finally, we are 

proposing to revise 40 CFR 98.166(a)(2) 

and (a)(3) to remove the requirement to 

report hydrogen and ammonia 

production for all units combined. The 

individual unit production is already 

reported and can be summed to obtain 

the production for all units combined. 

I. Subpart Q—Iron and Steel Production 

We are proposing multiple 

amendments to subpart Q of Part 98 

(Iron and Steel Production) to provide 

clarification for certain provisions and 

calculation methods. The more 

substantive corrections, clarifying, and 

other amendments to subpart Q are 

found here. Additional minor 

corrections are discussed in the Table of 

Revisions (see Docket ID No. EPA–HQ– 

OAR–2012–0934). 

We are proposing to amend the 

definition of the iron and steel 

production source category in subpart 

Q, 40 CFR 98.170, to include direct 

reduction furnaces not co-located with 

an integrated iron and steel 

manufacturing process. Reporters are 

required to report CO2 emissions from 

direct reduction furnaces under 40 CFR 

98.172(c), and it was the EPA’s intent 

for this reporting requirement to cover 

all direct reduction furnaces; however, 

the inclusion of direct reduction 

furnaces not co-located with an 

integrated iron and steel manufacturing 

process was inadvertently excluded 

from 40 CFR 98.170. The proposed 

change corrects that omission. This 

change impacts only one facility 

currently operating in the United States 

and that facility is already reporting 

under Part 98. We do not anticipate this 

change will impose a burden on 

additional existing reporters. 

The EPA is proposing to amend 

Equation Q–5 in subpart Q to account 

for the use of gaseous fuels in EAFs. 

Many EAF operators use supplemental 

natural gas for melting scrap in the 

furnace. One facility that provided input 

to the EPA on this issue meets 

approximately 20 percent of its energy 

requirement with natural gas. Because 

natural gas combustion products can 

constitute a significant portion of CO2

emissions from EAFs, we are proposing 

to modify 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 

proposing to amend 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. 

Additionally, we are proposing to 

revise 40 CFR 98.173(d) to clarify when 

the Tier 4 calculation methodology must 

be used to calculate and report 

combined stack emissions. The 

proposed amendment would clarify that 

the Tier 4 calculation methodology 

would be used (and emissions would be 

reported under subpart C of Part 98) if 

the 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. 

The amendment is necessary to clarify 

that facilities using either shared or 

dedicated CEMS must use the 

appropriate subpart C calculation 

methodology for determining emissions. 

We are also proposing to amend 40 

CFR 98.174(c)(2) by removing the term 

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

furnace exhaust,’’ because 

decarburization vessels are not furnaces. 

We are also proposing to amend 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. Newer and 

more efficient EAFs use the ‘‘Consteel®’’ 

process, which involves continuous, 

rather than batch, scrap feed. Thus, 

‘‘production cycles’’ may be an 

ambiguous term for reporters who 

operate a continuous EAF, and could be 

interpreted to require lengthy test 

periods as a single production cycle 

could extend for several days during 

which steel was continuously tapped. 

Therefore, we are proposing to remove 

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. 

We are proposing to amend 40 CFR 

98.175(a) 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. In 

accordance with 40 CFR 98.174(b)(4), 

reporters do not collect the monthly 

mass or annual carbon content of inputs 

or outputs that contribute less than one 

percent of the total mass of carbon into 

or out of the process. Therefore, 

reporters are not required to estimate 

missing data for these inputs. Similarly, 

we are proposing to amend 40 CFR 

98.176(e) by 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. 

J. Subpart X—Petrochemical Production 

We are proposing changes to subpart 

X of Part 98 (Petrochemical Production). 

In addition, we are providing flexibility 

for reporters and clarifying the 

calculation methodology, monitoring 

and reporting requirements, missing 

data procedures and other provisions 

under the rule. The more substantive 

corrections, clarifying, and other 

amendments to subpart X are found 

here. Additional minor corrections are 

discussed in the Table of Revisions to 

this rulemaking (see Docket ID No. 

EPA–HQ–OAR–2012–0934). 

We are proposing to revise 40 CFR 

98.242(b)(2) to clarify that reporters 

using the mass balance option for a 

petrochemical process are not to report 

emissions from the combustion of 

petrochemical off-gas in any combustion 

unit, regardless of whether or not the 

combustion unit is part of the 

petrochemical process unit. Subpart X 

currently states that emissions of CO2, 

CH4, and N2O from only supplemental 

fuels (i.e., not from the combustion of 

process off-gas) burned in a combustion 

unit are reported under subpart C of Part 

98 (General Stationary Fuel Combustion 

Sources). However, this requirement 

applies only to combustion units that 

are within the petrochemical process 

unit because the definition of 

supplemental fuel applies only to 

combustion within the process unit. 

Reporters may interpret this to mean 

that combustion units not within the 

petrochemical process unit should 

report emissions from combustion of 

petrochemical off-gas. This would lead 

to double counting since these 

emissions are already accounted for in 

the mass balance calculation. The 

proposed amendment would avoid 

possible double counting by specifying 

that emissions from the combustion of 

petrochemical process off-gas in 

combustion units outside the process 

unit also are not to be reported under 

subpart C. 


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We are proposing a change to 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 proposed 

calculation method is consistent with 

the calculation approach for CEMSmonitored sources in subpart C but 

should not increase burden because Tier 

4 units can use the best available 

information to estimate cumulative 

annual heat input (see 40 CFR 

98.33(c)(4)(i), 40 CFR 98.33(c)(4)(ii)(C)). 

The proposed calculation method 

would require reporters to use Equation 

C–10 of subpart C of Part 98. Reporters 

would use the cumulative annual heat 

input from combustion of the off-gas 

(mmBtu) and proposed fuel gas 

emission factors from Table C–2 to 

calculate emissions of CH4 and N2O. 

The proposed fuel gas emission factors 

in Table C–2 are the same as the 

‘‘Petroleum’’ factors previously 

referenced by subpart X, but we 

determined that a separate entry for fuel 

gas is needed for other reasons, as 

described in Section II.B of this 

preamble. 

We are proposing to modify both 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. Subpart X currently requires 

petrochemical manufacturers to 

determine product carbon contents from 

their own analyses. This change would 

provide additional flexibility for sources 

to obtain the carbon content 

measurement, and it is consistent with 

the current option that allows 

petrochemical manufacturers to obtain 

the carbon content of feedstocks from 

feedstock suppliers. 

We are proposing a change to 40 CFR 

98.243(c)(4) for the alternative sampling 

requirements for feedstocks and 

products when the composition is 

greater than 99.5 percent of a single 

compound for reporters using the mass 

balance calculation method. Currently, 

the alternative can only be used during 

periods of normal operation and when 

the product meets specifications. We are 

proposing changes that will allow the 

alternative method to be used during all 

times that the average monthly 

concentration is above 99.5 percent. The 

proposed changes would allow greater 

flexibility for reporters. 

For reporters using the mass balance 

calculation method in 40 CFR 

98.243(c)(5), we are proposing to revise 

definitions for five of the terms in 

Equation X–1. First, we are proposing to 

clarify that the term ‘‘Cg’’ includes 

streams containing CO2 recovered for 

sale or use in another process, which is 

consistent with the current definition of 

the term ‘‘(CCgp)i,n’’. Second, proposed 

changes to the terms ‘‘(Fgf)i,n’’ and 

‘‘(Pgp)i,n’’ would clarify that the inputs 

for gaseous feedstock and products may 

be measured on either a mass basis or 

a volume basis. Finally, we are 

proposing clarifications to the terms for 

molecular weight of gaseous feedstocks 

and products (‘‘(MWf)i’’ and ‘‘(MWp)i’’) 

to specify that molecular weight is to be 

determined monthly, which is 

consistent with the monitoring 

frequency specified in 40 CFR 

98.243(c)(1). 

We are proposing to modify the test 

method description for chromatographic 

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

remove the word ‘‘gas.’’ The proposed 

change would clarify that a 

chromatograph other than a gas 

chromatograph may be used. We are 

also proposing to modify 40 CFR 

98.244(b)(4)(xv) to allow additional 

methods for the analysis of carbon black 

feedstock oils and carbon black 

products. This section of subpart X 

currently specifies that a reporter may 

use an industry standard practice for 

such feedstocks and products. The 

proposed changes would provide 

additional flexibility by also allowing 

the use of a method published by a 

consensus-based standards organization 

(i.e., a published method that is not 

already specifically listed in 

98.244(b)(4)). For clarity, the proposed 

amendments also would list known 

consensus-based standards 

organizations and add a requirement for 

facilities to document the standard 

method that they use in the facility 

monitoring plan required under 40 CFR 

98.3(g)(5). 

We are proposing to add a 

requirement under 40 CFR 98.244(c) to 

clarify the monitoring and quality 

assurance requirements for flares. 

Following implementation of Part 98, 

the EPA received questions concerning 

the monitoring and quality assurances 

requirements for flares because while 

the rule refers to subpart Y for flare 

emission calculation methods, it does 

not specify monitoring and quality 

assurance requirements. As a result, we 

are clarifying the requirements for flares 

to specify that facilities must conduct 

monitoring and quality assurance in 

accordance with 40 CFR 98.254. The 

proposed monitoring requirements for 

flares harmonize subpart X with other 

subparts under Part 98. 

We are proposing to clarify the 

missing data procedures in 40 CFR 

98.245 for missing feedstock and 

product flow rates and missing 

feedstock and product carbon contents. 

This section of subpart X currently 

specifies that reporters are to develop 

substitute values for these parameters 

using the same procedures as for 

missing fuel carbon contents as 

specified in 40 CFR 98.35. The proposed 

amendment clarifies that the procedures 

for missing fuel carbon contents in 40 

CFR 98.35(b)(1) are to be used only for 

missing feedstock and 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 proposing to add 

missing data requirements for missing 

flare data and for missing molecular 

weights for gaseous feedstocks and 

products. The amendment would 

require reporters to develop substitute 

values for missing molecular weights 

using the procedures for missing fuel 

carbon contents as specified in 40 CFR 

98.35(b)(1), and substitute values for 

missing flare data would be developed 

using the procedures in 40 CFR 

98.255(b) and (c). We are proposing 

these additional missing data 

procedures so that reporters do not have 

to contact the EPA individually for 

guidance on how to proceed in the 

absence of instructions in the rule. We 

also expect that these changes will 

promote consistency both among 

subpart X reporters and between subpart 

X reporters and other reporters (e.g., 

subpart Y reporters). 

We are proposing two amendments to 

clarify the reporting requirements of 40 

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

mass balance method. This section of 

subpart X currently requires a reporter 

to report the name of each method listed 

in 40 CFR 98.244 that is used to 

determine a measured parameter. In 

addition, when a method is not listed in 

40 CFR 98.244 (i.e., for flow or mass 

measurements), the reporter is required 

to provide a description of the 

manufacturer’s recommended method. 

The only methods listed in 40 CFR 

98.244 are methods for determining 

carbon content or molecular weight, and 

they are all in paragraph (b)(4) of 40 

CFR 98.244. Thus, one proposed 

amendment to clarify 40 CFR 

98.246(a)(6) would 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). The current 

requirement to provide a description of 

manufacturer’s recommended method 

has been interpreted in various ways, 

and a wide variety of information has 

been provided in reports to date. To 

simplify this reporting requirement, 


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reduce burden, and promote 

consistency among reporters, the second 

proposed change would require 

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). Methods could be 

identified by method number, title, or 

other descriptor. 

We are proposing to revise 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. This 

section of subpart X currently requires 

identification of each combustion unit 

that burned both process off-gas and 

supplemental fuel. Supplemental fuel is 

defined as fuel burned in a 

petrochemical process that is not 

produced within the process itself. 

Thus, the current language in 40 CFR 

98.246(a)(8) requires identification of 

only those combustion units within a 

petrochemical process unit that burn 

off-gas from the process. The purpose of 

the proposed change is to extend this 

requirement to combustion units that 

combust fuel gas generated by the 

petrochemical process but are not part 

of the petrochemical process. This 

additional information is needed to 

allow us to verify correct reporting of 

fuel gas in subpart C. 

We are proposing to revise 40 CFR 

98.246(a)(9) for reporters using the 

alternative to sampling and analysis for 

carbon content as specified in 40 CFR 

98.243(c)(4) of the mass balance 

calculation method. One of the 

proposed changes would clarify the 

units of time to report in (days) for 

periods during which off-specification 

product was produced. A second 

proposed revision would eliminate 

reporting of the volume or mass of offspecification products produced. If a 

facility is complying with 40 CFR 

98.243(c)(4) for a product and produces 

off-specification products so that the 

average monthly purity does not fall 

below 99.5 percent, then the facility 

need not report the amount of offspecification product. However, if the 

average monthly purity does fall below 

99.5 percent, the facility must use the 

carbon content procedures in 40 CFR 

98.243(c)(3) for the off-specification 

product, and must report the amount 

and carbon content of the offspecification product under 40 CFR 

98.246(a)(4). The proposed revision 

would reduce the burden on reporters. 

We are proposing several changes to 

the CEMS reporting requirements in 40 

CFR 98.246(b)(4), (b)(5), and (b)(6) to 

improve the accuracy of emissions 

attributed to subpart X sources, clarify 

requirements, and reduce burden. We 

would revise 40 CFR 98.246(b)(4) to 

specify that for each CEMS monitoring 

location where CO2 emissions from 

either the process or combustion of offgas from the process are measured, the 

facility must provide an estimate of the 

fraction of the total CO2 emissions that 

are attributable to the petrochemical 

process unit, based on engineering 

judgment. Subpart X currently requires 

this reporting for process off-gas 

combustion emissions but not for 

process emissions. We need both to 

correctly determine the quantity of 

CEMS location emissions attributable to 

the petrochemical process unit. We 

would remove the requirements in 40 

CFR 98.246(b)(4) and (b)(5) to report 

CO2, CH4, and N2O emissions from each 

CEMS location because this requirement 

is also specified in 40 CFR 98.36(c)(2), 

which is referenced from 40 CFR 

98.246(b)(2). Similarly, we would 

remove the requirement to report the 

aggregated total emissions from all 

CEMS locations because the EPA will 

calculate sums from the reported values 

for individual CEMS locations, as 

necessary. In 40 CFR 98.246(b)(5) we 

would also remove the requirements to 

report inputs to Equation C–8 because 

we are proposing to replace the 

requirement to use Equation C–8 with a 

requirement to use Equation C–10, as 

noted previously in this section. Instead 

of the Equation C–8 inputs, reporters 

would report the total annual heat input 

for Equation C–10, as required in 40 

CFR 98.35(c)(2). Finally, we are 

proposing to remove the requirement to 

identify each stationary combustion unit 

that burns petrochemical process offgas. We use combustion unit 

identifications to help verify the 

distribution of emissions reported under 

subparts C and X for reporters that use 

the mass balance method. The 

identifications are not needed for 

reporters that use CEMS because all 

emissions from each combustion unit 

that burns process off-gas are reported 

under subpart X. On balance, we expect 

that these changes will reduce the 

reporting burden. 

K. Subpart Y—Petroleum Refineries 

We are proposing changes, technical 

corrections and clarifying amendments 

for subpart Y of Part 98 (Petroleum 

Refineries). The more substantive 

corrections, clarifying, and other 

amendments to subpart Y are found 

here. Additional minor corrections are 

discussed in the Table of Revisions (see 

Docket ID No. EPA–HQ–OAR–2012– 

0934). 

In conjunction with the addition of 

fuel gas to Table C–2 as discussed in 

Section II.B of this preamble, we are 

proposing revisions to subpart Y to 

change the reference to Table C–2 at 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 also 

proposing to revise 40 CFR 98.252(a) to 

remove the reference to the default 

emission factors for ‘‘Petroleum (All fuel 

types in Table C–1)’’ in Table C–2. 

Because the emission factors for 

Petroleum Products and Fuel Gas are 

identical, this will not change the result 

of any emission calculation. 

We are proposing to revise 40 CFR 

98.253(f)(4) and the terms ‘‘FSG’’ and 

‘‘MFc’’ in Equation Y–12 to clarify the 

calculation methods for sulfur recovery 

plants to address both on-site and offsite sulfur recovery plants. We are also 

proposing changes to the reporting 

requirements in 40 CFR 98.256(h) to 

clarify the reporting requirements for 

on-site and off-site units. The proposed 

revisions would clarify the requirements 

that should apply to on-site versus offsite sulfur recovery plants. 

We are proposing to clarify 40 CFR 

98.253(j) regarding when Equation Y–19 

must be used for calculation of CH4 and 

CO2 emissions. The proposed 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 proposing to clarify 

reporting requirements to 40 CFR 

98.256(j) and (k) 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). 

L. Subpart Z—Phosphoric Acid 

Production 

We are proposing an additional 

requirement, minor corrections, and 

clarifications to subpart Z of Part 98 

(Phosphoric Acid Production). 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 Revisions (see 

Docket ID No. EPA–HQ–OAR–2012– 

0934). 

The terminology used in the 

introductory text of 40 CFR 


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31See Table 9 of this preamble for the EPA’s 

proposed data category assignment and 

confidentiality determination for this data element. 

32See the memorandum in the docket titled, 

‘‘Kraft Pulping Liquor and Woody Biomass Methane 

(CH4) and Nitrous Oxide (N2O) Emission Factor 

Literature Review.’’ 

33Available at: http://www.epa.gov/ghgreporting/ 

documents/pdf/archived/tsd/TSD Pulp_and_Paper 

2_11_09.pdf. 

34See the memorandum ‘‘Proposed data category 

assignments and confidentiality determinations for 

new and substantially revised data elements in the 

proposed ‘2013 Revisions to the Greenhouse Gas 

Reporting Rule and Confidentiality Determinations 

for New or Substantially Revised Data Elements’’’ 

(hereafter referred to as ‘‘Confidentiality 

Determinations Memorandum’’) (Docket Id. No. 

EPA–HQ–OAR–2012–0934) for the proposed 

category assignments and confidentiality 

determinations for new and revised data elements. 

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

term ‘‘CO2n,’’ could be interpreted as 

meaning that the method for sampling 

carbon content of rock represented 

direct CO2 emissions from the process, 

which was not the EPA’s intention. 

While the equation calculates CO2

emissions from a process line, the input 

values obtained from the measurements 

of grab samples are CO2 content of the 

rock. Therefore, we are proposing to 

amend 40 CFR 98.263(b)(1)(ii) and the 

description of ‘‘CO2n,i’’ to indicate that 

the sampling method provides CO2

content, and not emissions. 

We are also proposing to revise 40 

CFR 98.266(b) to require that the annual 

report must include the annual 

phosphoric acid production capacity 

(tons), rather than the annual permitted 

phosphoric acid production capacity. 

Through implementation of the rule, the 

EPA has learned that not all facilities 

have a ‘‘permitted’’ production capacity. 

The EPA is proposing to revise this 

requirement to report annual production 

capacity, as opposed to permitted 

production capacity, in the current Part 

98.31 The proposed change 

acknowledges that not all phosphoric 

acid production facilities have a 

permitted production capacity. 

Additionally, not all facilities produce 

to the permitted capacity. This change 

is necessary to ensure that the EPA 

collects consistent annual production 

capacity data and will provide a better 

characterization of the relationship 

between industry production and 

emissions. 

We are also proposing to amend 40 

CFR 98.266 to add a requirement to 

report the number of times missing data 

procedures were used to estimate the 

CO2 content of the phosphate rock. The 

proposed requirement is consistent with 

40 CFR 98.264(b), which allows for 

determination of either inorganic carbon 

content or CO2 content. 

M. Subpart AA—Pulp and Paper 

Manufacturing 

We are proposing changes to subpart 

AA of Part 98 (Pulp and Paper 

Manufacturing) to revise default 

emission factors and clarify the 

information that must be reported. The 

more substantive corrections, clarifying, 

and other amendments to subpart AA of 

Part 98 are discussed in this section. 

Additional minor corrections are 

discussed in the Table of Revisions (see 

Docket ID No. EPA–HQ–OAR–2012– 

0934). 

We are proposing to amend 40 CFR 

98.273(a)(3), 40 CFR 98.276(e) and 

Equation AA–1 to remove the references 

to site-specific emissions factors 

because there are no methods or 

requirements in subpart AA for deriving 

the site-specific GHG emission factors 

for biomass combustion. 

We are proposing revisions to the 

emission factors shown in Tables AA– 

1 and AA–2 to correct format errors that 

occurred in the printing of the rule in 

the CFR. Specifically, in Table AA–1, 

the CH4 and N2O emission factors were 

intended to apply to each fuel. 

However, when printed in the Federal 

Register, lines were added to separate 

each row/fuel, and this format change 

created the appearance that the factors 

apply only to the first fuel listed in the 

table. To correct this error, we are 

proposing to insert the CH4 and N2O 

emission factors for each individual 

fuel. Today’s proposed changes will 

make the rule conform to Tables AA–1 

and AA–2 as they originally were 

proposed in the April 10, 2009 Federal 

Register (74 FR 16692). A similar error 

occurred with Table AA–2. In addition, 

the Kraft Lime Kiln N2O factors were 

inadvertently omitted in the printing of 

Table AA–2; it was intended to be zero 

(0) for all fuels in Table AA–2 (as 

proposed to be amended in the August 

11, 2010 Federal Register (75 FR 

48811)). 

In addition to correcting formatting 

errors, we are proposing revisions to the 

CH4 and N2O emission factors for 

pulping liquor in Table AA–1 based on 

emissions test data made available to us 

for eight U.S. recovery furnaces in the 

AF&PA Petition as discussed above. Our 

analysis of that data confirms that the 

information contained in the AF&PA 

Petition is more robust and relevant for 

U.S. recovery furnaces than the original 

Table AA–1 emission factors which 

were previously adopted from a 

literature review.32

We are also proposing additional 

changes to Table AA–2 to (1) Amend the 

title to remove the reference to fossil 

fuel since the table contains a biogenic 

fuel as well (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 to clarify our intent that 

the emissions factors apply to all grades 

of these fuel types; 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 ancillary lime 

kilns and calciners combusting fuels 

(e.g., propane, used oil, and lubricants) 

that were not previously listed in Table 

AA–2. The Technical Support 

Document for Subpart AA from the final 

Part 98 33 explains that the operating 

temperatures in rotary lime kilns appear 

to be too high for appreciable formation 

of N2O, so an emission factor of zero is 

proposed for N2O from ancillary fuel 

combustion in pulp mill lime kilns. 

We are proposing to amend 40 CFR 

98.276(k) to clarify the EPA’s intent 

regarding the annual pulp and/or paper 

production information that must be 

reported. Since publication of the rule, 

we have received questions from the 

industry about what this requirement 

means and the units of measure to use 

for reporting pulp production. Hence, 

we are proposing to amend the rule to 

clarify that the annual production 

information must consist of the 

production of air-dried, unbleached 

virgin pulp produced onsite during the 

reporting year and the production of 

paper products exiting the paper 

machine(s) during the reporting year, 

prior to application of any off-machine 

coatings.34 Greenhouse gas emissions 

from pulp and paper operations 

reported under subpart AA are 

dependent on the amount of pulp 

produced. Reporting the total annual 

production of air-dried unbleached 

virgin pulp provides a common 

reporting basis for all types of pulp 

mills regardless of production processes 

(e.g., bleaching, secondary fiber pulping, 

and paper making) that happen 

downstream of the virgin pulping 

process where the GHG emissions are 

generated. 

N. Subpart BB—Silicon Carbide 

Production 

We are proposing several revisions to 

subpart BB of Part 98 (Silicon Carbide 

Production). The more substantive 

corrections, clarifying, and other 

amendments to subpart BB of Part 98 

are discussed in this section. Additional 

minor corrections are discussed in the 

Table of Revisions (see Docket ID No. 

EPA–HQ–OAR–2012–0934). 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
19824 Federal Register / Vol. 78, No. 63 / Tuesday, April 2, 2013 / Proposed Rules 

35See http://www.epa.gov/ghgreporting/ 

reporters/subpart/dd.html. 

36See Table 9 of this preamble for the proposed 

category assignments and confidentiality 

determinations for each proposed data element. 

We are proposing to revise 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 proposing to revise 40 CFR 98.283(d) 

to remove the CH4 calculation 

methodology. The current CH4

calculation methodologies in subpart BB 

overestimate the emissions of CH4 from 

silicon carbide facilities because the 

equations do not take into consideration 

the destruction of CH4 emissions. 

Because these emissions are typically 

controlled, emissions from these 

facilities are minimal, and 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 proposing to revise 40 

CFR 98.283 so that CO2 emissions are to 

be calculated and reported for all 

process units and furnaces combined. 

The EPA intended in the final Part 98 

(October 30, 2009) to require reporting 

from all silicon carbide process units 

and production furnaces, as specified in 

40 CFR 98.282. However, 40 CFR 98.283 

states that ‘‘You must calculate and 

report the annual process CO2 emissions 

from each silicon carbide process unit 

or production furnace using the 

procedures in either paragraph (a) or (b) 

of this section.’’ The proposed 

correction would revise 40 CFR 98.283 

for consistency with the reporting 

requirements of 40 CFR 98.286 and 

reduce burden by combining all 

emissions. 

O. Subpart DD—Electrical Transmission 

and Distribution Equipment Use 

We are proposing two substantive 

corrections to subpart DD (Electrical 

Transmission and Distribution 

Equipment Use) in this section. We are 

proposing to revise 40 CFR 98.304(c)(1) 

and (c)(2) to correct the accuracy and 

precision requirements for weighing 

cylinders. In the current Part 98, the 

subpart DD regulatory text for 40 CFR 

98.304(c)(1) and (c)(2) presents the 

required scale accuracies as ‘‘2 pounds 

of the scale’s capacity.’’ The scale 

accuracy requirement for subpart DD 

was intended to be ‘‘2 pounds of true 

weight,’’ as expressed in the ‘‘Technical 

Support Document: Emissions from 

Electric Power Equipment Use’’ and 

‘‘EPA’s Response to Public Comments: 

Subpart DD: Electric Transmission and 

Distribution Equipment Use’’ 35, and the 

preamble to the final Part 98 (74 FR 

56260, October 30, 2009). The proposed 

amendments would make 40 CFR 

98.304(c)(1) and (c)(2) consistent with 

the EPA’s intent. 

P. Subpart FF—Underground Coal 

Mines 

We are proposing multiple 

amendments to subpart FF of Part 98 

(Underground Coal Mines) to 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. Additional 

minor corrections are discussed in the 

Table of Revisions (see Docket ID No. 

EPA–HQ–OAR–2012–0934). 

We are proposing to revise the 

terminology in subpart FF in response 

to questions submitted by reporters. 

Reporters have noted that ventilation 

does not take place through wells, but 

rather mine ventilation system shafts or 

vent holes, and degasification systems 

do not use shafts, but rather wells or gob 

gas vent holes. Reporters have also 

stated that mine ventilation air is not 

flared, rather it is destroyed using a 

ventilation air methane (VAM) oxidizer. 

Therefore we are proposing to revise 

provisions in 40 CFR 98.320(b), 40 CFR 

98.322(b) and (d), 40 CFR 98.323(c), and 

40 CFR 98.324(b) and (c) to adopt 

terminology that more accurately 

reflects industry operations. 

We are also proposing to revise the 

reporting requirements of subpart FF 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.36

The data elements are readily available 

to the reporter and would not require 

additional data collection or monitoring 

or significantly increase the reporting 

burden. The additional data elements 

are included in the proposed revised 40 

CFR 98.326(h), (i), (j), (o), (r), and new 

requirements (t) and (u) and 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 or shaft, the number 

of days the well or shaft was in 

operation during the reporting year, and 

the amount of CH4 routed to each 

destruction device. We are also 

proposing to add a reporting 

requirement (40 CFR 98.326(u)) for the 

reporting mines to provide the Mine 

Safety and Health Administration 

(MSHA) identification. This 

identification number will allow the 

EPA to easily identify the facility for 

verification and comparison of the 

Inventory data with GHGRP data. The 

reporting requirements have also been 

updated to harmonize with changes to 

the calculation methods as itemized in 

the Table of Revisions (see Docket ID 

No. EPA–HQ–2–12–0934). 

Q. Subpart HH—Municipal Solid Waste 

Landfills 

We are proposing multiple revisions 

to 40 CFR part 98, subpart HH 

(Municipal Solid Waste Landfills) to 

clarify equations and amend monitoring 

requirements to reduce burden for 

reporters. The more substantive 

corrections, clarifying, and other 

amendments to subpart HH are 

discussed in this section. Additional 

minor corrections are discussed in the 

Table of Revisions (see Docket ID No. 

EPA–HQ–OAR–2012–0934). 

We are proposing to amend the 

definition of the degradable organic 

carbon (DOC) term for Equation HH–1 to 

indicate that the DOC values for a waste 

type must be selected from Table HH– 

1. When we originally proposed subpart 

HH in April of 2009, Equation HH–1 

applied to both MSW and industrial 

waste landfills. When we finalized 

Subpart HH for MSW landfills only, the 

definition of the DOC term allowed for 

the default value from Table HH–1 or 

measurement data, if available. 

Although we included measurement 

methods for determining site-specific 

DOC values for industrial waste streams 

within Subpart TT, we do not consider 

that these laboratory methods are 

suitable for determining the DOC for 

MSW landfills in subpart HH because of 

the variability and heterogeneity of 

MSW. 

The EPA may take into consideration 

the usage of site-specific DOC values for 

MSW landfills in Equation HH–1 if 

suitable measurement methods are 

available. We specifically request 

comment from reporters who have used 

measurement methods for determining 

DOC. We request that the commenter 

provide information on the type of 

waste streams for which measurement 

methods were used, the analytical 

method used to determine DOC, and 

procedures used to ensure that the 

samples tested were representative of 

the waste stream tested for different 

years. We also note that, if 

measurements of DOC are made for 

different years, the DOC variable in 

Equation HH–1 should be a function of 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 78, No. 63 / Tuesday, April 2, 2013 / Proposed Rules 19825 

37The EPA is proposing category assignments and 

confidentiality determinations for these new and 

revised data elements in the Confidentiality 

Determinations Memorandum (Docket Id. No. EPA– 

HQ–OAR–2012–0934). 

the year the waste is placed in the 

landfill. As currently written, the DOC 

term in Equation HH–1 is a constant for 

a given waste type and is not a function 

of the disposal year. We therefore also 

request comment on the need to revise 

Equation HH–1 and the definition of 

DOC to allow DOC to be a different 

value for different years that a waste is 

placed in the landfill. 

We are proposing to amend the 

definition of the term ‘‘F’’ in Equation 

HH–1 (fraction by volume of CH4 in the 

landfill gas) to further clarify that this 

term should be corrected to zero percent 

(0%) oxygen. Unlike the concentration 

of CH4 in the landfill gas as measured 

for use in Equation HH–4, the term F is 

more accurately defined as the fraction 

of the dissimilated carbon that is 

metabolized to CH4. Some landfill gas 

collection systems may draw ambient 

air into the collected landfill gas, 

thereby diluting the concentration of 

CH4 in the landfill gas. The proposed 

amendment is needed to correct 

measurements of CH4 concentrations 

made in gas collection systems (or 

elsewhere) for ambient air dilution so 

that the resultant value of F more 

closely matches the fraction of degraded 

carbon that is generated as CH4. 

We are also proposing to revise the 

definition of parameter ‘‘N’’ in Equation 

HH–4 and the provisions of 40 CFR 

98.343(b)(2)(i), (ii), (iii)(A), and (iii)(B). 

We received comments from landfill 

owners and operators that the 

requirement to sample CH4

concentrations weekly was burdensome, 

particularly for closed landfills, and 

unnecessary because the CH4

concentrations did not vary appreciably 

over the year. Some landfill owners and 

operators provided EPA with their 

weekly flow and CH4 concentration data 

for the 2011 reporting year for 395 

unique landfills. We reviewed and 

analyzed the data and determined that 

reducing the CH4 concentration 

monitoring frequency from weekly to 

monthly would increase the overall 

uncertainty of a landfill’s CH4 recovery 

from ±8 percent to ±10.5 percent. (See 

‘‘Review of Weekly Landfill Gas 

Volumetric Flow and Methane 

Concentrations,’’ October 18, 2012, in 

Docket ID No. EPA–HQ–OAR–2012– 

0934.) It is reasonable to conclude that 

the on-going annual costs associated 

with monitoring CH4 concentrations 

monthly would be approximately onefourth the cost of monitoring weekly. 

Thus, landfill owners can realize a 

significant savings in their monitoring 

costs while not significantly increasing 

the uncertainty in the calculated CH4

recovery. Based on the data provided by 

the landfill owners and operators and 

our analysis of that data, we are 

proposing to revise the minimum 

monitoring frequency from weekly to 

monthly. 

We are proposing to amend the 

oxidation fraction default value used in 

Equations HH–5, HH–6, HH–7, and HH– 

8 of subpart HH. We received comments 

from landfill owners and operators that 

the oxidation fraction default value of 

10 percent that is required to be used in 

these equations is too low and that 

many landfills exhibit much higher 

oxidation fractions. Over the past 

several years, numerous U.S. landfills 

have been tested to estimate the 

oxidation fraction; the newly tested 

landfills have been predominately 

landfills with gas collection systems and 

clay soil or ‘‘other soil mixture’’ covers. 

We reviewed the oxidation study data 

and analyzed Subpart HH data to 

evaluate various options for revising the 

default oxidation fraction. Based on our 

review, we agree that the 10 percent soil 

oxidation fraction likely underestimates 

the amount of methane oxidized in the 

surface soil layer when the landfill gas 

flow through the soil surface is reduced, 

as is the case for landfills with gas 

collection systems. We considered a 

revised single default oxidation fraction 

or a default oxidation fraction based on 

the type of cover soil used at the 

landfill, but these defaults do not take 

in account the key variable, which is the 

methane flux rate entering the surface 

soil layer. Based on our analysis, we are 

proposing three different default 

oxidation fractions depending on the 

methane flux ‘‘bin,’’ found in new 

proposed Table HH–4. For cases where 

the methane flux is projected to be high 

(greater than 70 grams/m2/day), the 

default oxidation fraction remains as 10 

percent. For cases where the methane 

flux is projected to be low (less than 10 

grams/m2/day), the default proposed 

oxidation fraction is 35 percent. For 

cases with moderate methane flux rates 

(10 to 70 grams/m2/day), the proposed 

default oxidation fraction is 25 percent. 

We are also proposing to add 

requirements in paragraph 98.346(h) 

and paragraphs 98.346(i)(8), (10), and 

(11) for facilities to report the oxidation 

fraction used in each of Equations HH– 

5, HH–6, HH–7, and HH–8.37 We have 

concluded that this binned approach 

provides a more realistic estimate of the 

role of methane oxidation in the surface 

soil on the methane emissions than the 

single default oxidation fraction. We are 

including Table HH–4 to reference these 

values. Table HH–4 also provides a 

calculation method to determine the 

methane flux rate to be used for 

determining the oxidation fraction when 

Equations HH–5, HH–6, HH–7, or HH– 

8 are used. Reporters under subpart TT 

will also use Table HH–4 when 

Equation TT–6 is used to determine the 

methane generation adjusted for 

oxidation. For further information 

regarding our analysis of methane 

oxidation fractions, see ‘‘Review of 

Methane Flux and Soil Oxidation Data’’, 

December 7, 2012, in Docket ID No. 

EPA–HQ–OAR–2012–0934. 

We are also proposing to amend 

Equations HH–6, HH–7, and HH–8 and 

surrounding text to generalize these 

equations in the event that the landfill 

contains multiple landfill gas collection 

system measurement locations and/or 

multiple destruction devices. When 

there is a single landfill gas 

measurement location, these equations 

are identical to the existing equations. 

However, the existing equations were 

inadequate to calculate CH4 emissions at 

landfills with gas collection systems 

that have multiple measurement 

locations and/or multiple destruction 

devices. In addition to the revisions 

proposed to clarify equation term 

definitions when multiple measurement 

locations or destruction devices are 

used, we are also proposing to revise the 

definition of the fDest term for Equation 

HH–6 and HH–8 to clarify that the 

fraction of hours the destruction device 

was operating should be calculated as 

the number of operating hours for the 

device divided by the hours that gas 

flow as sent to the device. 

We are also proposing to amend the 

first sentence in 40 CFR 98.345(c) to 

revise ‘‘in reporting years’’ to ‘‘in the 

reporting year’’ to clarify that the 

missing data procedures are for a 

reporting year and that reporters do not 

need to report substitute data 

information for years prior to the 

current reporting year, thereby reducing 

the burden on reporters. 

Finally, we are proposing to revise 40 

CFR 98.346(d)(1) and (e) to move the 

reporting elements pertaining to the 

methane correction factor (MCF) from 

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

because MCF is not a function of the 

waste type. This amendment eliminates 

the duplicative reporting requirements 

for MCF and its related reporting 

elements (i.e., reporters would no longer 

be required to report this information 

for each waste type). 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
19826 Federal Register / Vol. 78, No. 63 / Tuesday, April 2, 2013 / Proposed Rules 

R. Subpart LL—Suppliers of Coal-based 

Liquid Fuels 

We are proposing multiple revisions 

to 40 CFR part 98, subpart LL (Suppliers 

of Coal-based Liquid Fuels) to clarify 

requirements and amend data reporting 

requirements to reduce burden for 

reporters. This section includes the 

more substantive corrections, clarifying, 

and other amendments to subpart LL. 

Additional minor corrections are 

discussed in EPA’s Table of Revisions 

(see Docket ID No. EPA–HQ–OAR– 

2012–0934). 

To reduce burden, we are proposing 

to remove 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. Reporters would continue to 

report the annual quantities of each 

product or natural gas liquid in metric 

tons or barrels at 40 CFR 98.386(a)(2), 

(a)(6), (a)(14), (b)(2), and (c)(2). We are 

also retaining the requirement to report 

a complete list of methods used to 

measure the annual quantities reported 

for each product or natural gas liquid. 

S. Subpart MM—Suppliers of Petroleum 

Products 

We are proposing several revisions to 

40 CFR part 98, subpart MM (Suppliers 

of Petroleum Products) to clarify 

requirements and amend data reporting 

requirements to reduce burden for 

reporters. This section includes the 

more substantive corrections, clarifying, 

and other amendments to subpart MM. 

Additional minor corrections are 

discussed in the Table of Revisions (see 

Docket ID No. EPA–HQ–OAR–2012– 

0934). 

We are proposing to clarify the 

equation term for ‘‘Producti’’ at 40 CFR 

98.393(a)(2) to exclude those products 

that entered the refinery but are not 

reported under 40 CFR 98.396(a)(2). We 

are proposing harmonizing changes to 

40 CFR 98.394(b) to make the 

equipment calibration requirements for 

petroleum products suppliers consistent 

with other Part 98 calibration 

requirements. The requirements for 

equipment calibration in 40 CFR part 

98, subpart A (General Provisions) allow 

for postponement of calibrations for 

units and processes that operate 

continuously with infrequent outages. 

We are proposing similar provisions be 

incorporated into the subpart MM 

equipment calibration requirements. 

The proposed changes would also 

provide flexibility for reporters meeting 

the equipment calibration requirements. 

As with the proposed changes to 

subpart LL, in order to reduce burden 

for reporters, we are proposing to 

remove 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. Reporters would continue 

to report the annual quantities of each 

petroleum product or natural gas liquid 

in metric tons or barrels at 40 CFR 

98.396(a)(2), (a)(6), (a)(14), (b)(2), and 

(c)(2). We are also retaining the 

requirement to report a complete list of 

methods used to measure the annual 

quantities reported for each product or 

natural gas liquid. 

In order to reduce the recordkeeping 

and reporting burden, the EPA is 

proposing to eliminate the reporting 

requirement for individual batches of 

crude oil feedstocks. The reporting 

requirements for crude oil at 40 CFR 

98.396(a)(20) are proposed to be 

changed to require only the annual 

quantity of crude oil. We are also 

proposing to eliminate the requirement 

to measure the API gravity and the 

sulfur content of each batch of crude oil 

at 40 CFR 98.394(d). We are also 

proposing to remove 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,’’ 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). 

Reporters would still be required to 

maintain all the records required to 

support information contained in the 

reports as specified at 40 CFR 98.397(a). 

We are proposing to include the 

definitions of natural gas liquids (NGL) 

and bulk NGLs in the subpart MM 

definitions at 40 CFR 98.397 to clarify 

the distinction between NGL and bulk 

NGL for reporting purposes under 

subpart MM. ‘‘Natural gas liquids 

(NGLs)’’ for purposes of reporting under 

subpart MM 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. Those subject 

to subpart MM are required to report 

NGLs as the individual differentiated 

product and are not required to conduct 

testing to determine additional 

components (i.e., impurities) that are 

contained within the differentiated 

product. For a mixture, the individual 

components should be reported. For 

example, if a refinery receives a known 

mixture of propane and ethane, the 

refiner must report the quantities of 

propane and ethane individually. 

Undifferentiated NGLs would be 

reported as bulk NGLs for subpart MM. 

We are also proposing to clarify the 

reporting requirements for bulk NGLs 

and NGLs. NGLs should be reported 

either as differentiated NGLs or as bulk 

NGLs. The requirement at 40 CFR 

98.396(a)(22) is proposed to be modified 

to specify that NGLs reported in 40 CFR 

98.396(a)(2) should not be reported 

again in 40 CFR 98.396(a)(22). 

Finally, we are proposing to revise the 

default density and emission factors in 

Table MM–1 for propane, propylene, 

ethane, ethylene, isobutane, 

isobutylene, butane, and butylene. 

Because these compounds are gases 

under standard conditions, the default 

density metric must be presented using 

a stated temperature and pressure. For 

all compounds except ethylene, we are 

proposing estimates of density and 

calculated emission factors at 60 degrees 

F and saturation pressure, the standard 

temperature and pressure conditions 

used by industry. For ethylene, because 

it cannot be liquefied above 48.6°F, we 

have selected as a basis for the values 

of density and emission factor 

conditions at 41°F (slightly under the 

critical temperature) and the 

corresponding saturation pressure. The 

current and proposed values for default 

density and emission factors are 

included in Table 6 of this preamble. 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 78, No. 63 / Tuesday, April 2, 2013 / Proposed Rules 19827 

38The EPA has proposed a data category and 

confidentiality determination for this revised data 

element. See the Confidentiality Determinations 

Memorandum (Docket Id. No. EPA–HQ–OAR– 

2012–0934). 

39We are also proposing to revise the reporting 

requirements in 40 CFR 98.406(b) in order to 

harmonize the reported data with the change to the 

equations in subpart NN. See the Confidentiality 

Determinations Memorandum (Docket Id. No. EPA– 

HQ–OAR–2012–0934) for the proposed category 

assignments and confidentiality determinations for 

new and revised data elements. 

TABLE 6—PROPOSED CHANGES TO TABLE MM–1 TO SUBPART MM OF PART 98–DEFAULT FACTORS FOR PETROLEUM

PRODUCTS AND NATURAL GAS LIQUIDS

Products 

Column A: 

density 

(metric tons/ 

bbl) 

Column C: 

emission factor 

(metric tons 

CO2/bbl) 

Proposed Column A: 

density 

(metric tons/ 

bbl) 

Proposed Column C: 

emission factor 

(metric tons 

CO2/bbl) 

Ethane 3 ............................................................................................................ 0.0866 0.2537 0.0579 0.170 

Ethylene 4 ......................................................................................................... 0.0903 0.2835 0.0492 0.154 

Propane 3 ......................................................................................................... 0.0784 0.2349 0.0806 0.241 

Propylene 3 ....................................................................................................... 0.0803 0.2521 0.0827 0.260 

Butane 3 ............................................................................................................ 0.0911 0.2761 0.0928 0.281 

Butylene 3 ......................................................................................................... 0.0935 0.2936 0.0972 0.305 

Isobutane 3 ....................................................................................................... 0.0876 0.2655 0.0892 0.270 

Isobutylene 3 ..................................................................................................... 0.0936 0.2939 0.0949 0.298

3The density and emission factors for components of LPG determined at 60°F and saturation pressure (LPGs other than ethylene). 4The density and emission factor for ethylene determined at 41°F and saturation pressure. 

T. Subpart NN—Suppliers of Natural 

Gas and Natural Gas Liquids 

The EPA is proposing multiple 

corrections and clarifying amendments 

to the provisions of subpart NN 

(Suppliers of Natural Gas and Natural 

Gas Liquids). The more substantive 

corrections, clarifying, and other 

amendments to subpart NN are 

discussed in this section. Additional 

minor corrections are discussed in the 

Table of Revisions (see Docket ID No. 

EPA–HQ–OAR–2012–0934). 

First, we are proposing to amend 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). For LDCs that operate in 

multiple states, we are proposing to 

clarify that the operations in each state 

are considered a separate LDC. For 

example, if an LDC owns and operates 

pipelines in two adjacent states, the 

LDC is considered two separate entities 

both for the purpose of determining 

applicability and for registering and 

reporting under subpart NN. We are also 

proposing a revision to clarify that 

interstate and intrastate pipelines 

delivering natural gas either directly to 

major industrial users or to farm taps 

upstream of the local distribution 

company inlet are not included in the 

definition of an LDC. The proposed 

changes are harmonizing changes that 

improve the consistency of provisions 

across Part 98. 

We are also proposing to revise 40 

CFR 98.406(b)(7).38 The current subpart 

NN rule requires that LDCs report 

annual volume of natural gas delivered 

to each meter registering supply equal to 

or greater than 460,000 thousand 

standard cubic feet (Mscf) during the 

calendar year. The EPA is proposing a 

change in the calculation and reporting 

requirements that would require that if 

the LDC knows that a series of meters 

serves one particular customer receiving 

a total of greater than 460,000 Mscf 

during the year, the LDC would be 

required to report these deliveries per 

customer rather than per meter. If the 

LDC does not know if the series of 

meters serve a single customer or 

multiple customers, the LDC may 

continue to report deliveries to 

individual meters. Customers that 

receive over 460,000 Mscf 

(approximately 25,000 Mtons CO2) for 

use in combustion are required to report 

emissions under subpart C or subpart D. 

We are proposing the change to 40 CFR 

98.407(b)(7) in order to greatly minimize 

double counting emissions reported 

under subparts C or D and emissions 

that would result from natural gas 

supplied reported under subpart NN 

from facilities that may receive a total of 

over 460,000 Mscf of natural gas 

through several meters. 

The EPA received comments that the 

multiple streams of natural gas included 

in Equation NN–5 may have different 

characteristics (e.g., HHV). Subpart NN 

currently requires the use of a single 

emission factor for all types of gas 

streams accounted for in Equation NN– 

5 (e.g., gas stored, liquefied natural gas 

removed from storage, natural gas 

received from local production). 

Because the characteristics of these 

streams may differ, the EPA agrees that 

emissions associated with the supply of 

natural gas would be more accurately 

calculated using emission factors 

specific to each stream. To allow 

reporters the flexibility to use different 

emission factors for different natural gas 

streams, the EPA is proposing Equation 

NN–5 be replaced with two equations, 

Equations NN–5a and NN–5b. The 

greenhouse gas quantity associated with 

the net amount of natural gas that is 

placed into or removed from storage 

during the year is proposed to be 

calculated using Equation NN–5a. 

Emissions that would result from the 

combustion or oxidation of natural gas 

supplied that bypassed the city gate are 

proposed to be calculated using 

Equation NN–5b. Separating Equation 

NN–5 into two equations does not 

impose additional burden on reporters. 

LDCs already monitor the volume of gas 

placed into or removed from storage 

separately from natural gas that 

bypassed the city gate. Further, LDCs 

may use different emission factors in 

Equations NN–5a and NN–5b, though 

they are not required to. The default 

value may be used. Additionally, we are 

proposing a change to Equation NN–6 

that incorporates the two proposed NN– 

5 equations. With this change, all the 

equation terms resulting in net 

additions to the CO2 quantity are added, 

and terms resulting in decreases to the 

CO2 quantity are subtracted from the 

LDC’s subpart NN total. This change 

will make Equation NN–6 easier to 

understand.39 Finally, the EPA has 

learned that o-grade as well as y-grade 

bulk NGLs are fractionated by facilities 

subject to subpart NN. Additionally, the 

EPA has learned that some fractionators 

strip out only a portion of the bulk NGL 

stream and supply the remaining bulk 

NGL downstream to other fractionators, 

where it is separated into its constituent 

products. Therefore, the EPA is 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
19828 Federal Register / Vol. 78, No. 63 / Tuesday, April 2, 2013 / Proposed Rules 

40See the Confidentiality determinations 

Memorandum (Docket Id. No. EPA–HQ–OAR– 

2012–0934) for the proposed category assignments and confidentiality determinations for new and 

revised data elements. 

proposing revisions to 40 CFR 

98.406(a)(4) to add new reporting 

elements that require reporting of the 

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

types of bulk NGLs received, and the 

quantity not fractionated, but supplied 

downstream.40

We are also proposing changes to the 

HHV and emission factors in Table NN– 

1 and NN–2. As discussed in this 

preamble for subpart C and subpart MM, 

we are proposing to revise the default 

HHV and emission factors for the 

individual components of liquid 

petroleum gases (LPG) including 

propane, ethane, isobutane, and butane. 

These values for Table NN–1 and NN– 

2 are based on the same HHV, density 

and carbon share used for the HHV and 

emission factors in Table C–1 and MM– 

1. Since these compounds are gases 

under standard conditions, the default 

emission factors in Table NN–1 and 

NN–2 (kg CO2 per MMBtu or MT CO2

per barrel) and HHV in Table NN–1 

(MMBtu per barrel) must be presented 

using a density at a stated temperature 

and pressure. For all these LPGs, we are 

proposing calculated values of HHV and 

emission factors using the density of the 

liquid at 60°F and saturation pressure, 

standard temperature and pressure 

conditions used by industry. The 

current and proposed default HHV and 

emission factors are shown in Tables 7 

and 8 of this preamble. 

TABLE 7—PROPOSED CHANGES TO TABLE NN–1 TO SUBPART NN OF PART 98–DEFAULT FACTORS FOR CALCULATION

METHODOLOGY 1 OF THIS SUBPART

Fuel Default high heating value 

factor 

Default CO2

emission factor 

(kg CO2/MMBtu) 

Proposed Default higher 

heating value 1

Proposed Default CO2

emission factor 

(kg CO2/MMBtu) 

Natural Gas ................. 1.028 MMBtu/Mscf ................... 53.02 1.026 MMBtu/Mscf ................... 53.06 

Propane ....................... 3.822 MMBtu/bbl ..................... 61.46 3.84 MMBtu/bbl ....................... 62.87 

Normal butane ............. 4.242 MMBtu/bbl ..................... 65.15 4.34 MMBtu/bbl ....................... 64.77 

Ethane ......................... 4.032 MMBtu/bbl ..................... 62.64 2.85 MMBtu/bbl ....................... 59.60 

Isobutane ..................... 4.074 MMBtu/bbl ..................... 64.91 4.16 MMBtu/bbl ....................... 64.94 

Pentanes plus ............. 4.620 MMBtu/bbl ..................... 70.02 4.62 MMBtu/bbl ....................... 70.02 

1 Conditions for higher heating values presented in MMBtu/bbl are 60°F and saturation pressure. 

TABLE 8—PROPOSED CHANGES 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) 

Proposed 

Default CO2

emission value 

(MT CO2/ 

Unit) 1

Natural Gas .......................................................................... Mscf ...................................................................... 0.055 0.0544 

Propane ................................................................................ Barrel .................................................................... 0.235 0.241 

Normal butane ...................................................................... Barrel .................................................................... 0.276 0.281 

Ethane .................................................................................. Barrel .................................................................... 0.253 0.170 

Isobutane .............................................................................. Barrel .................................................................... 0.266 0.270 

1 Conditions for emission value presented in MT CO2/bbl are 60°F and saturation pressure. 

U. Subpart PP—Suppliers of Carbon 

Dioxide 

We are proposing three substantive 

amendments to subpart PP of Part 98 

(Suppliers of Carbon Dioxide) that are 

described in this section. One additional 

minor correction is discussed in the 

Table of Revisions (see Docket ID No. 

EPA–HQ–OAR–2012–0934). 

We are proposing to amend 40 CFR 

98.423(a)(3)(i) to clarify that both 

capture and extraction facilities may use 

Equation PP–3a to aggregate annual data 

from multiple flow meters. In the 

December 17, 2010 Technical 

Corrections, Clarifying, and Other 

Amendments to the GHG Reporting 

Rule (75 FR 79092), we modified the 

provisions of 40 CFR 98.423(a)(3) to add 

Equation PP–3b to account for situations 

where a CO2 stream is segregated such 

that only a portion is captured for 

commercial application or for injection 

and where a flow meter is used prior to 

the point of segregation; we also 

introduced the two-meter approach for 

facilities with production process units 

that capture a CO2 stream. At that time, 

we made a harmonizing change and redesignated Equation PP–3 to Equation 

PP–3a. However, we inadvertently 

limited the application of equation PP– 

3a to facilities with production 

processes, whereas in the original 

promulgation, Equation PP–3 could be 

used by all facilities (including those 

with production wells) that have 

multiple streams and multiple flow 

meters. In this rulemaking we are 

proposing to amend 40 CFR 

98.423(a)(3)(i) 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, without sacrificing the 

quality of data reported. 

Finally, we are proposing to amend 

the reporting requirements of 40 CFR 

98.426(f)(10) and (f)(11), which require 

reporting the aggregated annual CO2

quantities transferred to enhanced oil 

and natural gas recovery or geologic 

sequestration. The proposed changes 

would 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. 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 78, No. 63 / Tuesday, April 2, 2013 / Proposed Rules 19829 

41The EPA has proposed a data category and 

confidentiality determination for these revised data 

elements. See the Confidentiality Determinations 

Memorandum (Docket Id. No. EPA–HQ–OAR– 

2012–0934). 

42The EPA has proposed a data category and 

confidentiality determination for this revised data 

element. See the Confidentiality Determinations 

Memorandum ‘‘Proposed data category assignments 

and confidentiality determinations for (Docket Id. 

No. EPA–HQ–OAR–2012–0934). 

V. Subpart QQ—Importers and 

Exporters of Fluorinated Greenhouse 

Gases Contained in Pre-Charged 

Equipment or Closed-Cell Foams 

We are proposing multiple revisions 

to 40 CFR part 98, subpart QQ 

(Importers and Exporters of Fluorinated 

Greenhouse Gases Contained in PreCharged Equipment or Closed-Cell 

Foams). The more substantive 

corrections, clarifying, and other 

amendments to subpart QQ are 

discussed in this section. Additional 

minor corrections are discussed in the 

Table of Revisions (see Docket ID No. 

EPA–HQ–OAR–2012–0934). We are 

proposing to correct the equation term 

‘‘St’’ in Equations QQ–1 and QQ–2 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). The proposed 

revision is necessary to ensure that the 

input for each equation is in the correct 

units when the density of F–GHG in the 

foam is used. 

We are proposing to amend an 

example within the definition of 

‘‘closed-cell foam’’ at 40 CFR 98.438. 

The revised text would read ‘‘Closedcell foams include but are not limited to 

polyurethane (PU) foam contained in 

equipment, * * *’’ The EPA is 

proposing this change to clarify that the 

reporting requirements apply to devices 

that contain F–GHGs in closed-cell 

foams even if the device is not an 

‘‘appliance’’ as defined in this section. 

Appliances are defined as devices that 

contain a fluorinated greenhouse gas 

refrigerant. This change clarifies that the 

reporting requirements apply to 

equipment such as water heaters which 

have closed-cell foam but no refrigerant 

charge. Similarly the reporting 

requirements apply to refrigeration and 

air conditioning equipment that contain 

closed-cell foam but not refrigerants that 

are covered by this reporting program. 

As part of this change, we are also 

proposing to replace 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). This clarification does not 

subject any new foams to the reporting 

requirements as subpart QQ currently 

requires the reporting of all fluorinated 

GHG closed-cell foams excluding 

packaging foam. 

We are proposing to revise the 

reporting requirements for 40 CFR 

98.436(a)(6)(iii) and (b)(6)(iii) to match 

the reported data element to the units 

required to be reported. The proposed 

revision is a change from ‘‘mass in 

CO2e’’ to ‘‘density in CO2e.’’ The units 

specified for the data elements in the 

current subpart QQ are kg CO2e/cubic 

foot, and are unchanged in this 

proposal.41

We are proposing to amend the 

definition of ‘‘pre-charged electrical 

equipment component’’ at 40 CFR 

98.438. The EPA is revising the 

definition to include components 

charged with any fluorinated 

greenhouse gas. The current definition 

is limited to components charged with 

SF6 or PFCs. The purpose of this 

revision is to align the definition of a 

component with that of ‘‘pre-charged 

electrical equipment’’ which is defined 

as containing a fluorinated greenhouse 

gas. 

We are also proposing to remove the 

following reporting requirements to 

alleviate burden on reporters: 40 CFR 

98.436(a)(5), (a)(6)(iv), (b)(5), and 

(b)(6)(iv). These provisions require 

reporters to supply the dates on which 

pre-charged equipment or closed-cell 

foams were imported or exported. The 

EPA established these reporting 

requirements to allow the agency to 

compare these data with shipment 

manifest data from Customs and Border 

Protection (CBP). The EPA has since 

learned that the data required under this 

subpart is more specific than the data 

found in the manifests, and has 

determined that the remaining 

information provided by the facilities is 

sufficient for verification purposes. The 

EPA can compare total annual imports 

and exports of appliances with reported 

data without needing date-specific 

information. In addition, the EPA has 

been made aware of the burden created 

by tracking and reporting each shipment 

by date. Many importers and exporters 

do not maintain data that include the 

appliance charge and foam type by date 

of import or export. Some of those that 

do indicated to the EPA that this would 

result in tens of thousands of reports. 

We do not believe that this level of 

specificity is necessary to understand 

the net import and export of fluorinated 

greenhouse gases within appliances and 

closed-cell foams. Given the burden and 

low utility of this data, the EPA is 

proposing to remove these 

requirements. The EPA is also not 

proposing any changes to the 

recordkeeping requirements of 40 CFR 

98.437 as the current requirements do 

not require the records to be organized 

by date in this manner. We have 

determined that the current 

recordkeeping requirements are 

sufficient because they would contain a 

complete record of imports and exports 

without requiring an aggregation of this 

data by date. 

W. Subpart RR—Geologic Sequestration 

of Carbon Dioxide 

We are proposing several 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. Additional 

minor corrections are discussed in the 

Table of Revisions (see Docket ID No. 

EPA–HQ–OAR–2012–0934). 

We are proposing to add 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.42 The addition of this requirement 

improves consistency within subpart 

RR, as it was previously only required 

for facilities using flow meters but not 

containers. This new reporting element 

would be used for verification purposes. 

The proposed data element does not 

require additional data collection or 

monitoring by reporters, and as it is not 

a significant change, would not add 

burden to reporting entities. 

X. Subpart SS—Electrical Equipment 

Manufacture or Refurbishment 

We are proposing 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. Additional 

minor corrections to subpart SS are 

discussed in the Table of Revisions (see 

Docket ID No. EPA–HQ–OAR–2012– 

0934). 

We are proposing to harmonize 40 

CFR 98.453(d) and 40 CFR 98.453(h), 

clarifying the options available to 

estimate the mass of SF6 and PFCs 

disbursed to customers in new 

equipment. The proposed revision does 

not add a new option, but clarifies the 

existing estimation methods for 

reporters under subpart SS. 

The EPA intended to provide four 

options for the calculation of SF6 or 

PFCs charged into equipment or 

containers that are sent to customers; 

these options are based on how the 

reporter determines the mass of SF6 or 

PFCs in equipment or containers. The 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
19830 Federal Register / Vol. 78, No. 63 / Tuesday, April 2, 2013 / Proposed Rules 

43The EPA has proposed a data category and 

confidentiality determination for this revised data 

element. See the Confidentiality Determinations 

Memorandum (Docket Id. No. EPA–HQ–OAR– 

2012–0934). 

four options are monitoring the mass 

flow of the SF6 or PFCs into the new 

equipment or cylinders using a 

flowmeter; weighing containers before 

and after gas from containers is used to 

fill equipment or cylinders; and using 

the nameplate capacity of the 

equipment either by itself or together 

with a calculation of the partial 

shipping charge. 

The proposed changes are designed to 

correct inconsistencies between 

paragraphs so that all options are clearly 

identified as available. We are 

proposing to add 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; these options were inadvertently 

omitted from that paragraph. The 

provisions of 40 CFR 98.453(h) 

currently state that reporters ‘‘must’’ use 

the nameplate capacity of the 

equipment, or calculate the partial 

shipping charge, to determine the mass 

of SF6 or PFCs disbursed to customers 

in new equipment. This is inconsistent 

with the language and intent of 40 CFR 

98.453(d), which was to provide 

facilities multiple options for 

determining the mass disbursed. 

Therefore, we are proposing to revise 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. 

Y. Subpart TT—Industrial Waste 

Landfills 

We are proposing 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. The 

more substantive corrections, clarifying, 

and other amendments to subpart TT 

are discussed in this section. Additional 

minor corrections are discussed in the 

Table of Revisions (see Docket ID No. 

EPA–HQ–OAR–2012–0934). 

We are proposing to revise the 

definition of the term ‘‘DOCF’’ in 

Equation TT–1 when a 60-day anaerobic 

biodegradation test is used. In Equation 

TT–1, ‘‘DOCF’’ is defined as the fraction 

of degradable organic carbon (DOC) that 

is dissimilated to landfill gas. The 

typical assumption is that half of the 

DOC will be anaerobically dissimilated 

and therefore, the default value for 

‘‘DOCF’’ currently used in Equation TT– 

1 is 0.5. However, the 60-day anaerobic 

biodegradation test effectively 

determines the organic carbon content 

that is anaerobically dissimilated, and 

as such, represents the product of the 

terms ‘‘DOCX’’ and ‘‘DOCF’’ within 

Equation TT–1. Therefore, for facilities 

using the 60-day anaerobic 

biodegradation test, it can be assumed 

that all of the measured DOC will be 

dissimilated (as it was during the test), 

so that ‘‘DOCF’’ is 1. We are therefore 

proposing that the DOCF have a default 

value of 1.0 for facilities using the 60- 

day anaerobic biodegradation test. 

We are also proposing similar 

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. The DOC value 

from Equation TT–7 is then used as an 

input to Equation TT–1 for that waste 

stream. Consistent with our proposed 

revision of the ‘‘DOCF’’ term in Equation 

TT–1, ‘‘DOCF’’ equals 1 when DOC is 

determined using the 60-day anaerobic 

biodegradation test. As such the ‘‘1/ 

DOCF’’ term in Equation TT–7 must 

equal to 1, so there is no need to include 

this term in the Equation TT–7. 

We are also proposing to delete the 

term ‘‘1/(MCDcontrol/MCcontrol)’’ from 

Equation TT–7. This term was 

erroneously included to correct the 

measured value of the DOC (i.e., 

MCDsample/Msample) for the recovery of 

the control substrate. However, after 

further review, the EPA determined that 

the recovery of the control substrate is 

only used to ensure quality control of 

the anaerobic biodegradation test (i.e., to 

verify that the inoculum or sludge from 

an anaerobic sludge digester used in the 

test is in fact biologically active) and is 

therefore not appropriate to include as 

a correction term in this equation. 

We are proposing to revise 40 CFR 

98.464(b) and (c) to broaden the 

provisions to determine volatile solids 

concentration for historically managed 

waste streams for the purposes of 40 

CFR 98.460(c)(2)(xii) (exemption as an 

inert waste) so that they may also be 

used for determining a site-specific DOC 

value for historically managed waste 

streams. When we added the 60-day 

anaerobic biodegradation test in the 

2011 Technical Corrections, Clarifying, 

and Other Amendments (76 FR, 73886; 

November 2011), we had not considered 

the impact of those amendments to this 

section. We did not intend to prevent 

facilities from using the 60-day 

anaerobic biodegradation test for similar 

waste streams for determining if a waste 

stream is inert. Furthermore, if a facility 

tests a similar waste stream and the 

waste stream is not inert, we did not 

intend to prevent the facility from using 

that result as the DOC value for their 

waste stream for purposes of calculating 

CH4 generation and ultimately reporting 

GHG emissions. The proposed 

amendments expand the provisions of 

this section to determining a sitespecific DOC value for historically 

managed waste streams both to assess 

whether the waste stream qualifies as an 

inert waste and to use in Equation TT– 

1 (even when the waste stream does not 

qualify as inert). 

We are proposing to amend 40 CFR 

98.466(b)(1) to clarify that the number of 

waste streams for which Equation TT– 

1 is used includes the number of ‘‘Inert’’ 

waste streams disposed of in the 

landfill.43 Although ‘‘Inert’’ waste 

streams have a DOC of 0 and therefore 

do not contribute to the facility’s CH4

generation, 40 CFR 98.463(a) clearly 

requires the owner or operator to 

‘‘Apply Equation TT–1 of this section 

for each waste stream disposed of in the 

landfill * * *’’ Therefore, an owner or 

operator of an industrial waste landfill 

that is required to report the emissions 

must apply Equation TT–1 to their inert 

waste streams and include these inert 

waste streams in the number reported in 

40 CFR 98.466(b)(1). 

As part of the 2011 Technical 

Corrections, Clarifying, and Other 

Amendments (76 FR, 73886), we 

amended Equation TT–4 to become 

Equation TT–4a and added Equation 

TT–4b for the calculation of historical 

waste disposal quantities. However, we 

neglected to amend the reporting 

requirements specific to Equations TT– 

4a and TT–4b in 40 CFR 98.466(c)(4). 

We also noted that the reporting 

elements associated with Equations TT– 

4a or TT–4b were not waste-stream 

specific and therefore did not need to be 

reported for each waste stream as 

indicated by the introduction in 40 CFR 

98.466(c). In order to eliminate 

duplicative reporting requirements and 

to clarify the reporting requirements 

when using Equations TT–4a or TT–4b, 

we are proposing several amendments 

to 40 CFR 98.466(c). First, we are 

proposing to revise the introductory text 

in 40 CFR 98.466(c) to read ‘‘Report the 

following historical waste information’’ 

rather than ‘‘For each waste stream 

identified in paragraph (b) of this 

section, report the following 

information.’’ Second, we are proposing 

to move the reporting of the decay rate 

(k) from paragraph (c)(1) to a new 

paragraph (b)(5) as this reporting 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 78, No. 63 / Tuesday, April 2, 2013 / Proposed Rules 19831 

44The EPA is proposing data category 

assignments and confidentiality determinations for 

the new and substantially revised data elements in 

the Confidentiality Determinations Memorandum 

(Docket Id. No. EPA–HQ–OAR–2012–0934). 

45The EPA has proposed a data category and 

confidentiality determination for the revised data 

elements of 40 CFR 98.466(h). See the 

Confidentiality Determinations Memorandum 

(Docket Id. No. EPA–HQ–OAR–2012–0934). 

element is more correctly categorized 

under ‘‘waste characterization and 

modeling information’’; we are 

specifically indicating that the reporting 

of the decay rate (k) must be made for 

each waste stream (as it was previously). 

Third, we are proposing to clarify that 

the reporting elements for paragraphs 

(c)(2) and (c)(3) are for each waste 

stream (as they were under previously). 

Fourth, we are proposing to clarify that 

the reporting elements for Equation TT– 

4 are specific to reporters using 

Equation TT–4a; these reporting 

elements would be reported once for the 

facility’s landfill rather than for each 

waste stream. Fifth, we are proposing to 

add a new paragraph (c)(5) to this 

section to delineate the reporting 

requirements for reporters using 

Equation TT–4b; these reporting 

elements would also be reported once 

for the facility’s landfill rather than for 

each waste stream. We are also 

proposing to amend 40 CFR 98.466(d)(3) 

to read ‘‘For each waste stream, the 

degradable organic carbon * * *’’ rather 

than ‘‘The waste stream’s degradable 

organic carbon * * *’’ to clarify that 

these reporting elements must be 

reported for each waste stream. 44

To harmonize with the proposed 

changes to subpart HH, and in order to 

more accurately reflect the amount of 

methane oxidized in the surface soil 

layer of industrial waste landfills, we 

are proposing to amend the oxidation 

fraction default value (‘‘OX’’) in 

Equation TT–6. Reporters would be 

referred to newly proposed Table HH– 

4 to determine the value for ‘‘OX’’ to be 

used in Equation TT–6. Please see 

Section II.Q of this preamble for more 

detailed explanation. 

In addition to adding reporting of the 

oxidation factor used, we are also 

proposing clarification of the reporting 

requirements for CH4 generation 

adjusted for oxidation for industrial 

waste landfills with gas collection 

systems. Under 40 CFR 98.463(b)(1), we 

require all industrial waste landfills 

reporting under Subpart TT to calculate 

their CH4 generation, adjusted for 

oxidation, from the modeled CH4 (GCH4

from Equation TT–1) using Equation 

TT–6. For landfills without gas 

collection systems, we then require the 

reporting of the result of this equation 

in 40 CFR 98.466(g)(1), which is also the 

annual CH4 emissions from these 

landfills. For landfills with gas 

collection systems, we require the 

reporting of the requirements in 

paragraphs 40 CFR 98.466(a) through (f) 

in addition to 40 CFR 98.346(i). In the 

cross-reference to 40 CFR 98.346(i) we 

inadvertently required facilities to 

report, under 40 CFR 98.346(i)(8), their 

CH4 generation adjusted for oxidation 

based using Equation HH–5 rather than 

Equation TT–6. While these equations 

appear identical, the modeled CH4

generation term is defined as the result 

of the Equation HH–1 in Equation HH– 

5 rather than the result of Equation TT– 

1 as in Equation TT–6. We never 

intended to have industrial waste 

landfills that have gas collection 

systems to calculate their modeled CH4

generation using Equation HH–1 (with 

its default DOC and k parameter values 

associated with MSW) rather than using 

Equation TT–1 (with default DOC and k 

parameter values for industrial wastes). 

To provide improved clarity in the 

reporting of CH4 generation adjusted for 

oxidation for industrial waste landfills 

with gas collection systems, we are 

therefore proposing to amend 40 CFR 

98.466(h) to read ‘‘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; and (3) All information 

required under 40 CFR 98.346(i)(1) 

through (7) and 40 CFR 98.346(i)(9) 

through (12).’’ 45

Finally, we are proposing changes to 

Table TT–1 of subpart TT of Part 98. 

During implementation of Part 98, a 

question arose regarding the default 

value for pulp and paper wastes 

questioning whether the 2006 IPCC 

Guidelines recommended value of 0.09 

instead should be used for wastewater 

sludges. We reviewed the 2006 IPCC 

Guidelines as well as laboratory test 

data results for pulp and paper 

wastewater sludges provided by NCASI 

(see memorandum ‘‘Calculations 

documenting the greenhouse gas 

emissions from the pulp and paper 

industry’’ from R.A. Miner, NCASI, to B. 

Nicholson, RTI International, dated May 

21,2008, in Docket ID No. EPA–HQ– 

OAR–2012–0934). Based on the 

available data, we agree that the 

industrial sludge default value for DOC 

of 0.09 appears to provide a more 

accurate estimate of the DOC than the 

generic industry defaults currently 

provided in the rule. Consequently, we 

are proposing to revise Table TT–1 to 

include the DOC default value of 0.09 

for ‘‘Industrial Sludge.’’ 

We are also proposing to revise the 

titles of the industry specific categories 

in Table TT–1 to note that these 

industry specific parameters apply to 

the industry waste streams ‘‘(other than 

sludge).’’ The addition of the new 

default DOC value for industrial sludge 

in Table TT–1 also requires the addition 

of corresponding k-values. The 2006 

IPCC Guidelines do not provide default 

k-values for industrial wastes (sludge or 

otherwise); the IPCC Waste Model (a 

spreadsheet tool to help implement the 

2006 IPCC Guidelines for landfills) uses 

the same k-values for industrial wastes 

as for bulk MSW. While it is anticipated 

that sludge generated by different 

industries will have different decay 

rates (and therefore different k-values), 

we have very little data by which to 

determine industry-specific k-values for 

the new default ‘‘Industrial Sludge’’ 

waste type. The k-values for ‘‘Other 

Industrial Solid Waste’’ waste type in 

Table TT–1 were selected based on 

country-specific default k-values for 

bulk MSW in U.S. landfills following 

the general default assumptions used in 

the IPCC Waste Model. These same kvalues (0.02, 0.04, and 0.06 for dry, 

moderate, and wet climates, 

respectively) are being proposed as the 

default k-values for the new ‘‘Industrial 

Sludge’’ waste type for the same reasons 

(i.e., based on country-specific default 

k-values for bulk MSW in U.S. landfill 

following general default assumptions 

used in the IPCC Waste model). We 

specifically request comment from 

reporters on these proposed k-values 

and we further request that the 

commenters provide any applicable data 

to support comments. 

Z. Subpart UU—Injection of Carbon 

Dioxide 

We are proposing technical 

amendments to 40 CFR part 98, subpart 

UU (Injection of Carbon Dioxide) to 

clarify provisions and improve 

verification of reported GHG data. The 

more substantive corrections, clarifying, 

and other amendments to subpart UU 

are discussed in this section. Additional 

minor corrections are discussed in the 

Table of Revisions for this rulemaking 

(see Docket ID No. EPA–HQ–OAR– 

2012–0934). 

The EPA is proposing to add 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) to aid 


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46The EPA has proposed category assignments 

and confidentiality determinations for new and 

revised data elements in the Confidentiality 

Determinations Memorandum (Docket Id. No. EPA– 

HQ–OAR–2012–0934). 

47 Id. 

48The sole exception is Subpart L, under which 

the requirement to report these F–GHGs on a mass 

basis is deferred for reporting years 2011 and 2012 

(and 2013, under this proposal), but reporters are 

required to keep records of the data and 

calculations used to estimate aggregate emissions in 

CO2e for the entire facility (77 FR 51477, August 24, 

2012). 

the agency in verification of data 

reported under subpart UU and to allow 

the EPA to understand the nature of the 

CO2 injection operations for the 

purposes of data analysis to inform 

policy development.46 We do not 

anticipate that this change would 

significantly increase burden for 

reporters. 

We are also proposing to add a 

requirement for facilities to report the 

standard or method used to calculate 

the parameters for CO2 received in 

containers. This new reporting element 

will be used for verification purposes.47

The proposed data element does not 

require additional data collection or 

monitoring from reporters, and as it is 

not a significant change, will not add 

burden to reporting entities. 

AA. Other Technical Corrections 

In addition to the corrections, 

clarifying, and other amendments 

proposed in Sections II.A through II.Z of 

this preamble, we are proposing minor 

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

II of Part 98. The proposed 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. 

III. Schedule for the Proposed 

Amendments 

A. When would the proposed 

amendments become effective? 

The EPA is planning to address the 

comments on these proposed changes 

and publish any final amendments 

before the end of 2013. This section 

describes when the proposed 

amendments would become effective for 

existing reporters and new facilities that 

could be required to report as a result 

of the proposed amendments to Table 

A–1 of subpart A. This section also 

discusses proposed amendments to 

subpart A for the use of best available 

monitoring methods (BAMM) by new 

reporters and for options considered for 

revising emissions estimates due to the 

change in GWPs for 2010, 2011, and 

2012 reports previously submitted by 

existing reporters. 

1. Existing Reporters 

We have determined that it would be 

feasible for existing reporters to 

implement the proposed changes for the 

2013 reporting year because these 

changes are consistent with the data 

collection and calculation 

methodologies in the current rule. The 

proposed revisions primarily provide 

additional clarifications or flexibility 

regarding the existing regulatory 

requirements, would not add new 

monitoring requirements, and would 

not substantially affect the information 

that must be collected. Where 

calculation equations are proposed to be 

modified, the changes clarify equation 

terms or simplify the calculations and 

do not require any additional data 

monitoring. The owners or operators are 

not required to actually submit 

reporting year 2013 reports until March 

31, 2014, which is several months after 

we expect a final rule based on this 

proposal to be finalized, thus providing 

an opportunity for reporters to adjust to 

any finalized amendments. 

We are proposing that existing 

GHGRP reporters begin using the 

updated GWPs in Tables A–1 for their 

reporting year 2013 annual reports, 

which must be submitted by March 31, 

2014. In keeping with the March 15, 

2012 UNFCCC decision, the Inventory 

submitted to the UNFCCC in 2015 must 

use AR4 GWP values (see Section 

II.A.1.a of this preamble). Development 

of the 2015 Inventory will rely in part 

on data from the GHGRP reports 

submitted in 2014 to supplement the 

top-down national estimate. Existing 

GHGRP reporters would also begin 

calculating facility GHG emissions or 

supply using the proposed GWPs for the 

additional F–GHGs discussed in Section 

II.A.1.c of this preamble for their 

reporting year 2013 annual reports. The 

proposed amendments would pose a 

minimal burden to existing reporters. 

Part 98 already requires that existing 

reporters report these F–GHGs in metric 

tons of chemical emitted or supplied.48

Therefore, facilities are already 

collecting information on emissions and 

supply for these substances, and in 

some cases have provided GWP 

estimates for these compounds. 

Furthermore, the proposed amendments 

only provide a factor to convert 

emissions to CO2e, and do not change 

the type of data collected. The EPA also 

does not anticipate that the proposed 

GWPs would require any existing 

reporters to report under new subparts; 

such a reporter, if one exists, would not 

be required to report for any past years 

under any subparts for which the 

reporter’s emissions newly exceed a 

reporting threshold. Therefore, we 

anticipate that there is no significant 

burden for existing reporters to use the 

proposed GWP values for reporting year 

2013. 

In some cases we are proposing 

revisions to reporting requirements to 

clarify requirements or to make 

harmonizing changes within a subpart 

or between subparts under Part 98. The 

EPA anticipates that the proposed 

reporting requirements are either 

already being collected by reporters or 

would be readily available to reporters. 

For example, we are revising reporting 

requirements to 40 CFR part 98, subpart 

A to include additional data for 

identification purposes, such as the 

latitude and longitude for facilities 

without a physical address, or the ORIS 

code for power generation units (an 

identifier assigned by the Energy 

Information Administration). In the case 

of 40 CFR part 98, subpart K (Ferroalloy 

Production), we are proposing to add a 

requirement to report the annual 

process CH4 emissions (in metric tons) 

from each EAF where the carbon mass 

balance procedure is used to measure 

emissions. This reporting requirement is 

an aggregate of data that is currently 

being monitored from each EAF. 

Similarly, under 40 CFR part 98, subpart 

Y (Petroleum Refineries), we are 

clarifying the reporting requirements by 

adding a provision to specify that when 

the process vent calculation method 

using Equation Y–19 is used to calculate 

emissions for asphalt blowing 

operations or delayed coking units, the 

facility must report the information 

required under 40 CFR 98.256(l)(5), 

which are the reporting requirements for 

process vents. This is a clarification of 

the reporting parameters required when 

an alternate calculation methodology is 

used. In the case of 40 CFR part 98, 

subpart Z (Phosphoric Acid 

Production), we are proposing to require 

reporting of the number of times 

missing data procedures were used to 

estimate CO2 content. Because the 

proposed changes to these subparts 

would not require new monitoring or 

data collection but could be determined 

from existing monitoring and 

recordkeeping, the EPA has determined 

that it would be feasible to include these 


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new reporting requirements in 2013 

reports. 

In the case of subpart N (Glass 

Production), we are proposing to revise 

the monitoring methods used to 

measure carbonate-based mineral massfractions to allow for more accurate 

measurement methods and to add 

flexibility for reporters. The proposed 

amendments would specify that 

reporters determining the carbonatebased mineral mass fraction must use 

sampling methods that specify X-ray 

fluorescence, instead of the current 

methods that use inductively coupled 

plasma or atomic absorption. For 

measurements made in the emission 

reporting year 2013 or prior years, 

reporters would continue to have the 

option to use the current monitoring 

methods in Part 98. This change would 

allow reporters flexibility in choosing a 

sampling method (since multiple X-ray 

fluorescence methods are available) 

while ensuring that more accurate 

available measurement methods are 

applied in future reporting years. These 

facilities would have the option, but not 

be required, to use the newly proposed 

option for the reporting year 2013 

reports submitted to the EPA in 2014. 

In some cases, we are proposing to 

require reporting of additional data 

elements to improve verification of the 

reported GHGs emitted or supplied. For 

example, for 40 CFR part 98, subpart FF 

(Underground Coal Mines), we are 

proposing to substantiate the data 

collected for identification of each well 

and shaft by adding a requirement to 

report the start date and close date of 

each well or shaft and the number of 

days the well or shaft was in operation 

during the reporting year. In the case of 

subpart UU (Injection of Carbon 

Dioxide), we are proposing to require 

reporting of the purpose of CO2

injection, whether the facility received a 

Research and Development project 

exemption from reporting under subpart 

RR of Part 98 for the reporting year, and 

the start and end dates of the 

exemption, if applicable. The proposed 

changes would not significantly burden 

reporters or affect reporting year 2013 

reports because this information is 

expected to be readily available to 

reporters as part of their standard 

recordkeeping and would not require 

additional monitoring or recordkeeping 

for 2013 reports. 

In the case of 40 CFR part 98, subpart 

NN (Suppliers of Natural Gas and 

Natural Gas Liquids), we are proposing 

a change to Equation NN–5 to better 

reflect actual operating conditions. We 

are proposing to replace Equation NN– 

5 with two equations, NN–5a and NN– 

5b, with harmonizing changes to 

Equation NN–6. The proposed equations 

would allow for the use of different 

emission factors for natural gas that is 

stored and for natural gas that bypasses 

the city gate, such as natural gas 

received from local production. We are 

proposing harmonizing changes to the 

reporting requirements to specify the 

quantity of gas that bypasses the city 

gate and the net quantity of gas that is 

placed into or withdrawn from onsystem storage during the reporting 

year. The proposed changes do not 

substantially revise the calculation 

methodology, but are changes that 

would provide more accurate GHG 

estimates in situations where the LDC 

receives several different streams of 

natural gas with different 

characteristics. Furthermore, the 

proposed changes do not revise the 

information that must be collected for 

recordkeeping or reporting. Therefore, 

we have concluded that under the 

proposed amendments, existing sources 

could use the same information that 

they have been collecting under the 

current Part 98 and readily available 

information for each subpart to 

determine applicability and to calculate 

and report GHG emissions for reporting 

year 2013. 

The EPA specifically seeks comment 

on the conclusion that it is appropriate 

to implement these amendments and 

incorporate the requirements in the data 

reported to the EPA by March 31, 2014. 

Further, we specifically seek comment 

on whether there are specific subparts 

or amendments for which this timeline 

may not be feasible or appropriate due 

to the nature of the proposed changes or 

the way in which data have been 

collected thus far. We request that 

commenters provide specific examples 

of how and why the proposed 

implementation schedule would not be 

feasible. 

2. New Reporters 

As a result of the proposed 

amendments to the GWPs in Table A– 

1 of subpart A, some facilities that were 

never previously required to report 

under Part 98 may be required to report 

(see Section V.A of this preamble). 

Given that a final rule based on this 

proposed rule would not be finalized 

until the second half of 2013, we have 

determined that it would not be feasible 

for these new facilities to acquire, 

install, and calibrate monitoring 

equipment, collect data, and implement 

these changes for reporting year 2013. 

Therefore, we are proposing that new 

reporters who would be required to 

report under Part 98 as a result of the 

proposed changes to Table A–1 would 

begin collecting data on January 1, 2014 

for the 2014 reporting year. New 

reporters would be required to submit 

their first reports, covering the 2014 

reporting year, on March 31, 2015. The 

intended schedule (including 

publication of any final rule by the end 

of 2013) would allow time for new 

reporters to acquire, install, and 

calibrate monitoring equipment for the 

2014 reporting year. 

We are also proposing to add 

provision 40 CFR 98.3(l) to subpart A to 

allow new reporters who would be 

required to report as a result of the 

proposed new or revised GWPs 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. The EPA understands that 

because any final rule based on this 

proposal likely would not be 

promulgated until the fall of 2013, 

facilities that do not already have the 

monitoring systems required by the rule 

in place might not have time to install 

and begin operating them by January 1, 

2014. Therefore, we are proposing that 

reporters be allowed to use BAMM 

during the January 1, 2014 to March 31, 

2014 time period without formal request 

to the EPA. Reporters would 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 

60 days after the effective date of the 

final rule. The EPA anticipates granting 

approval for BAMM no later than 

December 31, 2014. The EPA has 

concluded that the time period allowed 

under this schedule (including the 

provision for facility-specific requests) 

is reasonable and will allow facilities 

that do not currently have the required 

monitoring systems sufficient time to 

begin implementing the monitoring 

methods required by the rule. The 

proposed schedule would allow 

approximately six months to prepare for 

data collection, which is consistent with 

existing BAMM provisions provided 

under subpart A of Part 98. By allowing 

the additional time, many facilities may 

also be able to install any necessary 

equipment during other planned (or 

unplanned) process unit downtime, 

thus avoiding process interruptions. 

B. Options Considered for Revision and 

Republication of Emissions Estimates 

for Prior Year Reports 

The EPA is proposing to 

independently recalculate revised CO2e 

emissions from the 2010, 2011, and 

2012 reporting year emissions or supply 

for each facility using the revised GWPs 

in Table A–1. We considered two 


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49For reporters using the e-GGRT web forms, the 

system currently automatically applies the GWP 

values in Table A–1 of subpart A to reported facility 

emissions (metric tons) to convert emissions to 

CO2e, according to the requirements of Subpart A 

(General Provisions). 

50For reporters using the XML schema to submit 

annual GHG reports, reporters would apply the 

revised GWP values in Table A–1 of subpart A in 

their submitted XML reports to recalculate emission 

or supply estimates, following the XML reporting 

instructions provided through e-GGRT. For these 

reporters, the system would validate the CO2e 

estimates provided in the XML report against 

automatically calculated e-GGRT values, using the 

revised GWPs in Table A–1. 

51As discussed later in the preamble, we propose 

to assign certain new or substantially revised data 

elements to the ‘‘inputs to emission equations’’ 

category but do not propose confidentiality 

determinations for these data elements. 

options for revising the CO2e emission 

estimates from annual reports for 

reporting years 2010, 2011, and 2012 

using the proposed GWP values in Table 

A–1. Revision of CO2e emission 

estimates in reports for years 2010, 

2011, and 2012, either by reporters or by 

the EPA, would allow for the 

comparison of emission data submitted 

for those reporting years with data 

submitted in 2013 and future reporting 

years and ensure that published annual 

GHG reports are based on a common 

metric. This would allow the EPA and 

the public to more efficiently analyze 

changes in GHG emissions and industry 

trends in a time series. 

Option 1: Under this option, which is 

not preferred by EPA, reporters who 

have submitted annual reports for the 

reporting years 2010, 2011, and 2012 

would be required to resubmit their 

prior year reports using the revised 

GWPs. Under this option, reporters 

would use the built-in calculation 

methods in the EPA’s Electronic 

Greenhouse Gas Reporting Tool (eGGRT) to convert reported quantities of 

GHGs to CO2e per the requirements of 

40 CFR 98.2(b)(4).49 To adjust prior year 

reports, the system would recalculate 

facility GHG emissions using the revised 

GWP values in Table A–1, yielding a 

new CO2e for each GHG in the annual 

report.50 Reporters would then recertify 

and sign the reports as required by 40 

CFR 98.4(e) and resubmit the reports 

through e-GGRT. 

The proposed revised GWP values in 

Table A–1 will likely result in changes 

to the CO2e estimates of GHGs emitted 

or supplied in previous reporting years. 

In most cases, this will result in higher 

estimates of CO2e emitted or supplied, 

rather than lower estimates. Reporters 

may desire to review and certify the 

revised emission estimates prior to data 

publication by the EPA. So we have 

included this option for comment. This 

option would give reporters greater 

control over the republication of their 

data, and emission or supply totals 

would be certified by reporters. 

However, this option would present an 

additional burden on reporters. The 

EPA calculates that existing reporters 

would incur a total one-time cost of $3.5 

million for resubmittal and 

recertification of 2010, 2011, and 2012 

reports. This represents a one-time cost 

for 2010 reporters of $347 per facility for 

the resubmittal of 2010, 2011, and 2012 

reports, and a cost of $231 per facility 

for 2011 reporters for the resubmittal of 

2011 and 2012 reports. In addition, the 

EPA recognizes that some facilities may 

no longer be required to report under 

Part 98 or may have ceased operations. 

Obtaining revised emissions estimates 

from these facilities could be difficult; 

therefore, the EPA may not be able to 

revise the complete data set for prior 

reporting years. For these reasons, the 

EPA does not prefer this option. 

Option 2: The EPA would 

independently recalculate revised CO2e 

emissions from the 2010, 2011, and 

2012 reporting year emissions or supply 

for each facility using the revised GWPs 

in Table A–1. Under this scenario, 

through e-GGRT, each reporter would be 

able to see the EPA’s revision of its 

emission or supply totals in previously 

submitted 2010, 2011, and 2012 reports 

before that information is publically 

available. However, although the 

reporter would be able to view the 

estimate, the reporter would not be able 

to comment on or change the revised 

estimate. The EPA would 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. While the 

calculation is very straightforward for 

most reporters, because subpart L 

reporters have not reported the specific 

compounds that make up their 

emissions, there could be some 

uncertainty associated with the 

revisions to subpart L emission data if 

option 2 is selected. 

This option would allow the EPA to 

publish revised emission and supply 

totals without increasing burden on 

reporters. This option would remove the 

need for reporters to resubmit and 

recertify revised reports. However, 

Option 2 would not give reporters the 

opportunity to provide feedback on 

their individual revised emissions or 

supply totals, or allow them to certify 

the amended totals at any point before 

or after republication. As reporters 

would be unable to submit revised 

emission estimates or comment on the 

estimation methods used to calculate 

the updated CO2e totals, they would 

have less control over the revised data. 

Although Option 1 would give reporters 

more input in the revised emission or 

supply totals provided to the public, we 

do not anticipate that the benefits of 

requiring data resubmission and 

certification would justify the increased 

burden on reporters discussed above. 

Option 2 would not present any 

additional burden for reporters. Option 

2 would allow the EPA to publish 

revised emission and supply totals for 

all facilities which submitted a report 

for 2010, 2011, and 2012, including 

facilities which have ceased operations 

or which are no longer required to 

report. This approach would allow the 

EPA to reconstruct the complete data set 

for prior year reports for comparison to 

data reported for 2013 and future years. 

In light of these considerations, the EPA 

prefers Option 2. The EPA seeks 

comment on the two options. 

Specifically, we request comment on the 

need for review and certification of 

revised emission estimates by reporters 

and whether revised calculations 

prepared by the EPA, as proposed in 

Option 2, would be sufficient for 

publication. 

IV. Confidentiality Determinations 

A. Overview and Background 

In this notice we are proposing 

confidentiality determinations for the 

new or substantially revised reporting 

data elements (i.e., the data required to 

be reported would change under the 

proposed revision) in the proposed 

subpart rule amendments, except for 

inputs to equations.51 For information 

on the history of confidentiality 

determinations for Part 98 data 

elements, see the following notices: 

• 75 FR 39094, July 7, 2010; hereafter 

referred to as the ‘‘July 7, 2010 CBI 

proposal.’’ Describes the data categories 

EPA developed for the Part 98 data 

elements. 

• 76 FR 30782, May 26, 2011; 

hereafter referred to as the ‘‘2011 Final 

CBI Rule.’’ Assigned data elements to 

data categories and published the final 

CBI determinations for the data 

elements in 34 Part 98 subparts, except 

for those data elements that were 

assigned to the ‘‘Inputs to Emission 

Equations’’ data category. 

• 77 FR 48072, August 13, 2012, 

hereafter referred to as ‘‘2012 Final CBI 

Determinations Rule.’’ Finalized 

confidentiality determinations for data 

elements to be reported under nine 

subparts I, W, DD, QQ, RR, SS, UU; 

except for those data elements that are 

inputs to emission equations, and 

finalized confidentiality determinations 

for new data elements added to subparts 


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52See, e.g., 77 FR 48072 (August 13, 2012) and 

77 FR 51477 (August 24, 2012). 

53Proposed determination is not needed for two 

data elements proposed for subpart Y (40 CFR 

98.256(j)(10) and 40 CFR 98.256(k)(6)), because they 

refer to an existing data element (40 CFR 

98.256(l)(5)) for which a CBI determination has 

already been finalized. 

II and TT in the November 29, 2011 

Technical Corrections Notice (76 FR 

73886). 

• 77 FR 51477, August 24, 2012; 

hereafter referred to as the ‘‘2012 

Technical Corrections and Subpart L 

Confidentiality Determinations.’’ 

Finalized confidentiality determinations 

for new data elements added to subpart 

L. 

In this action, the EPA is proposing 

confidentiality determinations for new 

or substantially revised data elements. 

The new and substantially revised data 

elements result from the proposed 

corrections, clarifying, and other 

amendments that are described in 

Section II of this preamble. These 

proposed confidentiality determinations 

would be finalized based on public 

comment. The EPA currently plans to 

finalize these determinations at the 

same time the proposed rule 

amendments described in Sections II 

and III of this preamble are finalized. 

We are not proposing new 

confidentially determinations for data 

reporting elements that may be 

minimally revised for clarification or to 

correct insignificant errors, where the 

change does not require an additional or 

different data element to be reported. 

The final confidentiality determinations 

the EPA has previously made for these 

data elements are unaffected by this 

proposed amendment and continue to 

apply. 

B. Approach to Proposed Confidentiality 

Determinations for New or Substantially 

Revised Data Elements 

In this action, we are proposing to add 

or substantially revise data reporting 

requirements in subparts A, H, K, X, Y, 

Z, AA, FF, HH, NN, QQ, RR, TT, and 

UU. We propose to assign each of the 

newly proposed or substantially revised 

data elements in these subparts to one 

of the direct emitter or supplier data 

categories created in the 2011 Final CBI 

Rule (76 FR 30782, May 26, 2011). In 

the 2011 Final CBI Rule, the EPA made 

categorical confidentiality 

determinations for data elements 

assigned to eight direct emitter data 

categories and eight supplier data 

categories. For two direct emitter data 

categories, ‘‘Unit/Process ‘Static’ 

Characteristics that Are Not Inputs to 

Emission Equations’’ and ‘‘Unit/Process 

Operating Characteristics that Are Not 

Inputs to Emission Equations,’’ the EPA 

determined in the 2011 Final CBI Rule 

that the data elements assigned to those 

categories are not emission data but did 

not make categorical CBI 

determinations. Rather, the EPA made 

CBI determinations for individual data 

elements assigned to these two data 

categories. Similarly, for three supplier 

data categories, ‘‘GHGs Reported,’’ 

‘‘Production/Throughput Quantities and 

Composition,’’ and ‘‘Unit/Process 

Operating Characteristics,’’ the EPA 

determined in the 2011 Final CBI Rule 

that the data elements assigned to those 

categories are not emission data but did 

not make categorical CBI 

determinations; instead the EPA made 

CBI determinations for individual data 

elements assigned to these two data 

categories. In subsequent amendments 

to Part 98,52 the EPA assigned each new 

or substantially revised data element to 

an appropriate data category created in 

the 2011 Final CBI Rule and applied the 

categorical confidentiality 

determination if one was established in 

the 2011 Final CBI Rule. If a data 

element was assigned to one of the two 

direct emitter or three supplier data 

categories identified above that do not 

have categorical determinations, the 

EPA made individual CBI 

determinations. With respect to data 

elements for which the revisions did not 

change the type of data to be reported, 

their categorical assignments and 

confidentiality determinations (whether 

categorical or individual 

determinations) are not affected by this 

proposed amendment and therefore 

remain unchanged. The EPA did not 

make final confidentiality 

determinations for data elements 

assigned to the inputs to emission 

equations category either in the 2011 

Final CBI rule or any subsequent Part 98 

rulemaking. We are following the same 

approach in this proposed rule. 

Specifically, we are proposing to assign 

new or substantially revised data 

elements in the proposed amendments 

to the appropriate direct emitter or 

supplier data category.53 For new or 

substantially revised data elements 

being assigned to categories with 

categorical confidentiality 

determinations, we propose to apply the 

categorical determinations made in the 

2011 Final CBI Rule to the assigned data 

elements. For new or substantially 

revised reporting elements assigned to 

the ‘‘Unit/Process ‘Static’ Characteristics 

that Are Not Inputs to Emission 

Equations’’ and the ‘‘Unit/Process 

Operating Characteristics that Are Not 

Inputs to Emission Equations’’ direct 

emitter data categories or the ‘‘Unit/ 

Process Operating Characteristics’’ 

supplier data categories, consistent with 

our approach toward data elements 

previously assigned to these data 

categories, we propose that these data 

elements are not emission data, and are 

making individual CBI determinations 

for the data elements in these categories. 

Please see the memorandum titled 

‘‘Proposed data category assignments 

and confidentiality determinations for 

new and substantially revised data 

elements in the proposed ‘2013 

Revisions to the Greenhouse Gas 

Reporting Rule and Confidentiality 

Determinations for New or Substantially 

Revised Data Elements’ ’’ 

(‘‘Confidentiality Determinations 

Memorandum’’) in Docket EPA–HQ– 

OAR–2012–0934 for a list of the 

proposed new or substantially revised 

data elements, their proposed category 

assignments, and their proposed 

confidentiality determinations (whether 

categorical or individual) except for 

those assigned to the inputs to equations 

category. Section IV.C of this preamble 

discusses the proposed CBI 

determinations and supporting rationale 

for individual data elements. 

C. Proposed Confidentiality 

Determinations for Individual Data 

Elements in Two Direct Emitter Data 

Categories and Two Supplier Data 

Categories 

The EPA is proposing individual CBI 

determinations for 16 data elements 

assigned to the ‘‘Unit/Process ‘Static’ 

Characteristics that Are Not Inputs to 

Emission Equations’’, ‘‘Unit/Process 

Operating Characteristics that Are Not 

Inputs to Emission Equations’’ direct 

emitter data categories and the 

‘‘Production/Throughput Quantities and 

Composition’’ and ‘‘Unit/Process 

Operating Characteristics’’ supplier data 

categories. (There are no new data 

elements proposed to be assigned to the 

‘‘GHGs Reported’’ supplier data 

category.) These data elements consist 

of three new data elements in the direct 

emitter subpart FF and eight in the 

supplier subpart UU. We are also 

proposing individual CBI 

determinations for five substantially 

revised data elements in the subparts Z, 

NN, TT, and QQ. Table 9 of this 

preamble provides the category 

assignment and proposed rationale for 

the proposed determinations. 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
19836 Federal Register / Vol. 78, No. 63 / Tuesday, April 2, 2013 / Proposed Rules 

TABLE 9—DATA ELEMENTS PROPOSED TO BE ASSIGNED TO DATA CATEGORIES WITHOUT CATEGORICAL DETERMINATIONS

AND PROPOSED CBI DETERMINATIONS (SUBPARTS Z, NN, FF, QQ, TT, AND UU) 

Citation 

New or 

revised 

data element 

Data element Rationale for the proposed CBI determination 

Data Elements Proposed To Be Assigned to the ‘‘Unit/process Static Characteristics That Are Not Inputs to Emission Equations’’ 

Direct Emitter Data Category 

98.266(b) ............... Revised .... Annual phosphoric acid production 

capacity.

We are not proposing a determination for this data element at this 

time. This data element is being revised from ‘‘permitted production 

capacity’’ to ‘‘production capacity’’. As discussed in the 2011 Final 

CBI Rule (76 FR 30782), the EPA reviewed available capacity information in the ‘‘Unit/process Static Characteristics that Are Not Inputs 

to Emission Equations’’ data category and determined that these 

data elements may not be publically available for all facilities and 

may be competitively sensitive. Revising the current data element to 

‘‘production capacity’’ would require reporting of actual production 

capacity in lieu of permitted production capacity. Although this information in some cases is publicly available (e.g., Title V permits, 

NEI), this data may still be competitively sensitive for other facilities. 

No determination is being proposed at this time; case-by-case determinations will be made when necessary. 

Data Elements Proposed To Be Assigned to the ‘‘Unit/process Operating Characteristics That Are Not Inputs to Emission Equations’’ 

Direct Emitter Data Category 

98.326(r)(2) ........... New ......... Start date of each well and shaft ... We are proposing that these data elements are not emission data and 

not CBI. These proposed data elements would provide additional 

identification and descriptive information for each well or shaft. 

98.326(r)(2) ........... New ......... Close date of each well and shaft..

98.326(r)(3) ........... New ......... Number of days each well or shaft 

was in operation during the reporting year.

These data elements reveal general information about the operating 

characteristics of the reporting facility and would be assigned to the 

‘‘Unit/process Operating Characteristics that Are Not Inputs to Emission Equations’’ data category. We are proposing that these data 

elements not be considered CBI because they characterize the total 

operation period of each well or shaft. None of these data elements 

reveal information regarding the production characteristics or production rates of any individual well or shaft. Furthermore, these data elements are generally publicly available. For example, facilities currently report shaft operating periods to the Mine and Safety Health 

Administration (MSHA). Additionally, facilities are often required to 

report well operation periods to state agencies for other regulatory 

purposes. Therefore, these data elements are not anticipated to be 

sensitive information and public disclosure of these data elements is 

not likely to cause substantial competitive harm to the reporting facility. 

98.466(b)(1) ........... Revised .... The number of waste streams for 

which Equation TT–1 is used.

We are proposing that this data element is not emission data and not 

CBI. This data element is being revised to include ‘‘inert’’ waste 

streams. The addition of ‘‘inerts’’ to the reporting requirement clarifies that inert waste streams must be reported in the total number of 

waste streams used to calculate modeled CH4 generation, which 

may change the value reported. This data element does not disclose 

any information about the design or operating characteristics of production processes, historical production volumes, or any other production related information about the landfill that competitors could 

use to discern sensitive information. Therefore we are proposing a 

determination of ‘‘not emission data and not CBI’’. 

Data Elements Proposed To Be Assigned to the ‘‘Production/Throughput Quantities and Composition’’ Supplier Data Category 

98.406(b)(2) ........... Revised .... LDCs: Annual volume of natural 

gas placed into storage.

We are proposing that this data element is not CBI. The change to this 

data element is proposed in order to harmonize the reported data 

with the change to the equations in subpart NN. The change clarifies 

that the volume to be reported is the volume referenced as Fuel1 in 

the Equation NN–5a. The volume reported is not expected to change 

as a result of the proposed revision. As discussed in the 2011 Final 

CBI Rule, the EPA does not consider LDC-level production/throughput data as CBI because many of the same data elements are already collected and released annually by the Energy Information Administration (EIA). Therefore, we are proposing that the data element 

is not CBI. 


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TABLE 9—DATA ELEMENTS PROPOSED TO BE ASSIGNED TO DATA CATEGORIES WITHOUT CATEGORICAL DETERMINATIONS

AND PROPOSED CBI DETERMINATIONS (SUBPARTS Z, NN, FF, QQ, TT, AND UU)—Continued 

Citation 

New or 

revised 

data element 

Data element Rationale for the proposed CBI determination 

98.436(a)(6)(iii) ...... Revised .... If the reporter does not know the 

identity and the mass of the F– 

GHGs within the closed cell 

foam: For closed cell foams that 

are not imported inside of equipment, the density in CO2e of the 

F–GHGs in the foam.

We are proposing that these data elements are CBI. These data elements were previously assigned to the ‘‘Production/Throughput 

Quantities and Composition’’ data category and assigned a ‘‘CBI’’ 

determination in the 2012 Final CBI Determinations Rule. The proposed change to these data elements is a correction to match the 

reported data element to the units required to be reported. The 

change proposed is a change from ‘‘mass in CO2e’’ to ‘‘density in 

CO2e’’. The units specified for the data element are kg CO2e/cubic 

foot, and are unchanged in this proposal. These data elements reveal importer- and exporter-level production information (density of 

the fluorinated gas within the foam) and the disclosure of these data 

elements would likely cause substantial harm to the competitive positions of businesses reporting these data. Therefore, we are proposing to assign these elements to the ‘‘Production/Throughput 

Quantities and Composition’’ data category and a determination that 

the data element is CBI. 

98.436(a)(6)(iii) ...... Revised .... If the reporter does not know the 

identity and the mass of the F– 

GHGs within the closed cell 

foam: For closed cell foams that 

are not exported inside of equipment, the density in CO2e of the 

F–GHGs in the foam. 

Data Elements Proposed To Be Assigned to the ‘‘Unit/Process Operating Characteristics’’ Supplier Data Category 

98.476(e)(1) ........... New ......... Whether the facility received a Research and Development project 

exemption from reporting under 

40 CFR part 98, subpart RR for 

the reporting year.

These data elements reveal general information about the operating 

characteristics of the reporting facility and are proposed to the ‘‘Unit/ 

Process Operating Characteristics’’ supplier data category. We are 

proposing that these data elements are not CBI. These proposed 

data elements are based on the compliance requirements for R&D 

facilities under subpart RR that are not considered sensitive information by the EPA. We are proposing that these data elements are 

non-CBI because they would not reveal any information about production quantities, process, or specific R&D projects that could 

cause competitive harm, but only provide information about whether 

the facility received an approved exemption from other subpart-specific requirements under Part 98 and the duration of the exemption. 

98.476(e)(1) ........... New ......... If you received a Research and Development project exemption 

from reporting under 40 CFR part 

98, subpart RR for the reporting 

year, the start date of the exemption. 

98.476(e)(1) ........... New ......... If you received a Research and Development project exemption 

from reporting under 40 CFR part 

98, subpart RR for the reporting 

year, the end date of the exemption. 

98.476(e)(2) ........... New ......... 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 the reporting year.

The proposed data elements would reveal general information about 

the operating characteristics of the reporting facility and would be assigned to the ‘‘Unit/Process Operating Characteristics’’ supplier data 

category, which contain similar data elements. We are proposing that 

these data elements are not CBI. The proposed data elements would 

provide additional information on the purpose of the CO2 injection on 

a facility-wide basis. The proposed data elements would not reveal 

any specific information about the quantities of CO2 received or injected at specific wells or information about the production that could 

cause competitive disadvantage. We are proposing that these data 

elements are not considered CBI because they do not reveal any detailed information that is likely to cause competitive harm if publicly 

released. 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
19838 Federal Register / Vol. 78, No. 63 / Tuesday, April 2, 2013 / Proposed Rules 

TABLE 9—DATA ELEMENTS PROPOSED TO BE ASSIGNED TO DATA CATEGORIES WITHOUT CATEGORICAL DETERMINATIONS

AND PROPOSED CBI DETERMINATIONS (SUBPARTS Z, NN, FF, QQ, TT, AND UU)—Continued 

Citation 

New or 

revised 

data element 

Data element Rationale for the proposed CBI determination 

98.476(e)(3) ........... New ......... 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 the reporting year.

98.476(e)(4) ........... New ......... 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 the reporting year.

98.476(e)(5) ........... New ......... Whether the facility includes a well 

or group of wells where a CO2

stream was injected for a purpose other than those listed in 

(e)(1)through (4) of 40 CFR 

98.476.

98.476(e)(5) ........... New ......... The purpose of the injection, if you 

injected CO2 for a purpose of 

than those listed in paragraph 

(e)(1) through (4) of 40 CFR 

98.476.

D. Proposed New Inputs to Emission 

Equations 

As discussed in Section IV.C of this 

preamble, the EPA is proposing category 

assignment for the new and 

substantially revised data elements. As 

shown in the Confidentiality 

Determinations Memorandum (see 

Docket Id. No. EPA–HQ–OAR–2012– 

0934), the EPA is proposing to assign 13 

new data elements to the ‘‘inputs to 

emission equations category’’: Two in 

subpart FF, five in subpart HH, and six 

in subpart TT. The EPA had previously 

deferred the reporting deadlines for 

inputs to emissions equations until 

March 2013 for some data elements and 

March 2015 for others to allow EPA 

sufficient time to conduct an ‘‘in-depth 

evaluation of the potential impact from 

the release of inputs to equations’’ (76 

FR 53057 and 53060, August 25, 2011); 

(77 FR 48072, August 13, 2012). We are 

not proposing to defer the reporting of 

these 13 data elements. The EPA has 

conducted an evaluation of these inputs 

following the process outline in the 

memorandum ‘‘Process for Evaluating 

and Potentially Amending Part 98 

Inputs to Emission Equations’’ (Docket 

ID EPA–HQ–OAR–2010–0929), which 

accompanied the Final Deferral Rule (76 

FR 53057). This evaluation is 

summarized in the memorandum 

‘‘Summary of Evaluation of ‘Inputs to 

Emission Equations’ Data Elements 

Proposed to be Added with the 2013 

Revisions to the Greenhouse Gas 

Reporting Rule.’’ (See Docket ID No. 

EPA–HQ–OAR–2012–0934.) Because 

the EPA has completed the above 

mentioned evaluation for these 13 data 

elements, EPA does not see a need to 

defer their reporting. Accordingly, 

under this proposed amendment, these 

data elements would be reported in 

2014 along with the rest of the proposed 

changes. 

E. Request for Comments on Proposed 

Category Assignments and 

Confidentiality Determinations 

For the CBI component of this 

rulemaking, we are soliciting comment 

on the following specific issues. First, 

we specifically seek comment on the 

proposed data category assignment for 

each of the new or substantially revised 

data elements in the proposed 

amendments to subparts A, H, K, X, Y, 

Z, AA, FF, HH, NN, QQ, RR, TT, and 

UU. 

If you believe that the EPA has 

improperly assigned certain new or 

substantially revised data elements in 

these subparts to any of the data 

categories established in the 2011 Final 

CBI Rule, please provide specific 

comments identifying which of the new 

data elements may be mis-assigned 

along with a detailed explanation of 

why you believe them to be incorrectly 

assigned and in which data category you 

believe they belong. In addition, if you 

believe that a data element should be 

assigned to one of the five categories 

that do not have a categorical 

confidentiality determination, please 

also provide specific comment along 

with detailed rationale and supporting 

information on whether such data 

element does or does not qualify as CBI. 

We seek comment on the proposed 

confidentiality status of the new or 

substantially revised data elements in 

the direct emitter data categories ‘‘Unit/ 

Process ‘Operating’ Characteristics that 

Are Not Inputs to Emission Equations’’ 

and ‘‘Unit/Process ‘Static’ 

Characteristics that Are Not Inputs to 

Emission Equations’’ and the supplier 

data categories ‘‘Production/Throughput 

Quantities and Composition’’ and 

‘‘Unit/Process Operating 

Characteristics.’’ By proposing 

confidentiality determinations prior to 

data reporting through this proposal and 

rulemaking process, we provide 

potential reporters an opportunity to 

submit comments, in particular 

comments identifying data they 

consider sensitive and their rationales 

and supporting documentation; this 

opportunity is the same opportunity 

that is afforded to submitters of 

information in case-by-case 

confidentiality determinations. In 

addition, it provides an opportunity to 

rebut the Agency’s proposed 

determinations prior to finalization. We 

will evaluate the comments on our 

proposed determinations, including 

claims of confidentiality and 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 78, No. 63 / Tuesday, April 2, 2013 / Proposed Rules 19839 

information substantiating such claims, 

before finalizing the confidentiality 

determinations. Please note that this 

will be reporters’ only opportunity to 

substantiate a confidentiality claim. 

Upon finalizing the confidentiality 

determinations of the data elements 

identified in this rule, the EPA will 

release or withhold these data in 

accordance with 40 CFR 2.301, which 

contains special provisions governing 

the treatment of Part 98 data for which 

confidentiality determinations have 

been made through rulemaking. 

When submitting comments regarding 

the confidentiality determinations we 

are proposing in this action, please 

identify each individual proposed new 

or revised data element you do or do not 

consider to be CBI or emission data in 

your comments. Please explain 

specifically how the public release of 

that particular data element would or 

would not cause a competitive 

disadvantage to a facility. Discuss how 

this data element may be different from 

or similar to data that are already 

publicly available. Please submit 

information identifying any publicly 

available sources of information 

containing the specific data elements in 

question. Data that are already available 

through other sources would likely be 

found not to qualify for CBI protection. 

In your comments, please identify the 

manner and location in which each 

specific data element you identify is 

publicly available, including a citation. 

If the data are physically published, 

such as in a book, industry trade 

publication, or federal agency 

publication, provide the title, volume 

number (if applicable), author(s), 

publisher, publication date, and 

International Standard Book Number 

(ISBN) or other identifier. For data 

published on a Web site, provide the 

address of the Web site and the date you 

last visited the Web site and identify the 

Web site publisher and content author. 

If your concern is that competitors 

could use a particular data element to 

discern sensitive information, 

specifically describe the pathway by 

which this could occur and explain how 

the discerned information would 

negatively affect your competitive 

position. Describe any unique process or 

aspect of your facility that would be 

revealed if the particular proposed new 

or revised data element you consider 

sensitive were made publicly available. 

If the data element you identify would 

cause harm only when used in 

combination with other publicly 

available data, then describe the other 

data, identify the public source(s) of 

these data, and explain how the 

combination of data could be used to 

cause competitive harm. Describe the 

measures currently taken to keep the 

data confidential. Avoid conclusory and 

unsubstantiated statements, or general 

assertions regarding potential harm. 

Please be as specific as possible in your 

comments and include all information 

necessary for the EPA to evaluate your 

comments. 

V. Impacts of the Proposed Rule 

This section of the preamble examines 

the costs and economic impacts of the 

proposed rulemaking and the estimated 

economic impacts of the rule on affected 

entities, including estimated impacts on 

small entities. 

A. Impacts of the Proposed 

Amendments to Global Warming 

Potentials 

There are two primary reasons that 

Part 98 requires direct emitters and 

suppliers of GHGs to use the GWP 

values in Table A–1 to subpart A to 

calculate emissions (or supply) of GHGs 

in CO2e. The first is to help determine 

whether the facility meets a CO2e-based 

threshold and is required to report 

under Part 98. The second is to help 

calculate total facility emissions for 

submittal in the annual report. A change 

to the GWP for a GHG will change the 

calculated emissions (in CO2e) of that 

gas. Therefore, the proposed 

amendments could affect both the 

number of facilities required to report 

under Part 98 and the quantities of 

GHGs reported. 

For most GHGs whose GWPs we are 

proposing to amend, the proposed AR4 

GWP values are greater than the GWP 

values in the current Table A–1. 

Therefore, the proposed amendments 

would likely result in higher reported 

emissions of CO2e for facilities that emit 

these gases. Although the proposed 

amendments would result in an increase 

in reported emissions for many facilities 

that currently submit a report, using the 

proposed GWPs would have no effect on 

the cost of monitoring and 

recordkeeping and, therefore, no 

significant impact for reporters. 

For the additional F–GHGs and 

associated GWPs we are proposing to 

include in Table A–1, we do not 

anticipate significant impacts for 

existing reporters. Per 40 CFR 98.3(c), 

facilities are required to report annual 

CO2e emissions or supply, using 

Equation A–1, for each GHG with a 

GWP in Table A–1. The proposed 

amendments to subpart A would require 

Part 98 reporters to include emissions of 

the new F–GHGs in Table A–1 (in CO2e) 

in their facility totals in their annual 

reports. With the addition of the new F– 

GHGs, we expect the quantities of CO2e 

reported to increase for reporters that 

previously emitted, produced, imported, 

or exported the proposed compounds 

and reported the annual quantities 

(metric tons) of these gases in their 

2010, 2011, or 2012 reports, but who 

were not required to include the 

calculated CO2e emissions for these 

gases in determining annual emissions 

of CO2e for their annual report. Because 

these reporters are already required to 

meet monitoring, recordkeeping, and 

reporting requirements for calculating 

the quantity of the proposed F–GHGs in 

metric tons, additional costs to report 

CO2e using the GWPs are expected to be 

insignificant. 

Equation A–1 is also used to 

determine whether the rule applies to 

direct emitters and suppliers in certain 

source categories where the 

applicability of the GHG reporting rule 

is based on a threshold quantity of 

GHGs that is either generated, emitted, 

imported, or exported over a calendar 

year, expressed in CO2e. For some direct 

emitters or suppliers in these source 

categories, calculating CO2e using the 

proposed GWP values would result in 

higher emissions or supply that might 

newly exceed the reporting threshold. 

These facilities would then be required 

to begin reporting under Part 98 in 2014 

(see Section III.A.2 of this preamble), 

with the associated monitoring, 

recordkeeping, and reporting costs. 

If finalized, the proposed 

amendments to Table A–1 would result 

in a collective increase in annual 

reported emissions from all subparts of 

more than 104 million metric tons CO2e 

(a 1.4 percent increase in current 

emissions), which the EPA has 

concluded more accurately reflects the 

estimated radiative forcing from the 

emissions reported under Part 98. The 

increase would include 4.8 million 

metric tons CO2e from an estimated 184 

additional facilities that would be newly 

required to report under Part 98 based 

on the new and 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 Table 10 of this 

preamble. 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
19840 Federal Register / Vol. 78, No. 63 / Tuesday, April 2, 2013 / Proposed Rules 

TABLE 10—SUMMARY OF ESTIMATED IMPACTS ON REPORTED EMISSIONS DUE TO PROPOSED REVISIONS TO TABLE A–1 

FOR PART 98 SUBPARTS

Subpart Number of existing 

reporters 

Total reported emissions or 

supply for existing reporters 

prior to proposed amendments (non-biogenic) 

(metric tons CO2e/year) 

Number of estimated 

new reporters 

Estimated incremental reported 

emissions or supply 

for new reporters 

(metric tons CO2e/ 

year) 

Estimated change in reported source category 

emissions or supply due to 

proposed amendments 

(metric tons CO2e/year) 

2010 Reporters 

C ............. 4,211 619,572,472 0 0 112,339 

D ............. 1,263 2,231,408,653 0 0 293,276 

E ............. 2 4,397,310 0 0 (170,218) 

F ............. 9 4,298,897 0 0 283,040 

G ............. 22 13,596,985 0 0 0 

H ............. 97 42,734,686 0 0 2,657 

K ............. 10 2,240,907 0 0 1,743 

N ............. 103 2,061,679 0 0 0 

O ............. 5 6,351,797 0 0 1,682,955 

P ............. 101 31,261,120 0 0 10 

Q ............. 123 27,094,226 0 0 (21) 

R ............. 12 588,209 0 0 0 

S ............. 70 15,566,816 0 0 174 

U ............. 19 122,663 0 0 0 

V ............. 36 11,990,739 0 0 (464,158) 

X ............. 63 9,445,122 0 0 11,973 

Y ............. 145 55,751,060 0 0 100,695 

Z ............. 13 1,080,913 0 0 0 

AA ........... 110 7,562,923 0 0 50,408 

BB ........... 1 122,466 0 0 2,141 

CC .......... 4 1,221,863 0 0 0 

EE ........... 7 1,447,634 0 0 0 

GG .......... 6 730,209 0 0 0 

HH .......... 1,202 107,000,000 57 1,560,000 2,787,153 

MM .......... 155 2,493,881,410 0 0 0 

NN .......... 476 909,000,000 0 0 0 

OO .......... 167 254,554,000 3 75,000 44,060,000 

2011 Reporters 

I ............... 94 5,622,570 4 18,076 1,052,905 

L .............. 14 10,600,000 0 0 1,060,000 

T ............. 11 1,067,000 0 0 (37,213) 

W ............ 2,786 337,000,000 99 2,572,881 41,136,821 

DD .......... 141 10,320,000 0 0 (474,979) 

FF ........... 114 33,823,404 0 0 6,442,553 

II .............. 244 5,845,000 2 59,500 1,172,833 

JJ a .......... 0 0 0 0 0 

LL ............ 0 0 0 0 0 

PP ........... 99 33,500,000 0 0 0 

QQ .......... 108 21,907,182 0 0 1,915,000 

RR .......... 10 7,162,885 0 0 0 

SS ........... 10 814,128 0 0 (37,470) 

TT ........... 200 13,700,000 19 520,000 3,129,524 

UU .......... 92 48,735,442 0 0 0 

Total 12,355 7,385,182,369 184 4,805,457 104,114,139 

aThere are no reporters for subpart JJ of Part 98 because the EPA will not be implementing subpart JJ due to a Congressional restriction prohibiting the expenditure of funds for this purpose. 

Additional reporters would be 

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 would 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 other 36 subparts. We do not 

anticipate that the proposed revisions 

would reduce the number of reporters 

that meet CO2e thresholds for any 

subpart. The change in reported 

emissions or supply from each subpart 

are summarized in Sections V.A.1 of 

this preamble. 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 (see 

Docket ID No. EPA–HQ–OAR–2012– 

0934). 

The total cost of compliance for the 

additional expected reporters is $3.9 

million for the first year and $1.2 

million per year for subsequent years. 

The annual costs for the additional 

reporters is an approximate increase of 

1.2 percent above the current reporters 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
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cost of compliance with Part 98. The 

expected costs of the proposed 

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? 

The EPA evaluated the number of 

reporters affected by the proposed 

amendments by examining the 2010 and 

2011 reporters that are already affected 

under Part 98. For the number of 

affected facilities, the EPA examined 

available e-GGRT data from the 2010 

reporting year and summary data that 

were developed to support the current 

Part 98 to determine the number of 

existing affected facilities. We then 

evaluated the number of additional 

facilities that could be required to report 

under each subpart by determining what 

additional facilities could exceed Part 

98 source category thresholds. Affected 

subparts that might have additional 

reporters due to the proposed new or 

revised GWPs are those that meet all of 

the following criteria: (1) The subpart 

has a reporting threshold that is based 

on CO2e; (2) the subpart requires 

reporting of emissions or supply of F– 

GHG, CH4, or N2O, (other than 

combustion related emissions, which 

are a small percentage of total 

combustion emissions); and (3) the EPA 

estimates that there are some facilities 

in the source category that did not 

previously exceed the threshold. The 

EPA analyzed the applicability of these 

criteria to each subpart; the subparts 

that met these three criteria and could 

have new reporters as a result of the 

proposed changes to Table A–1 were 

subparts I, T, W, HH, II, OO, and TT. 

In order to determine the number of 

additional reporters expected under 

these subparts, we used data from 

industry surveys and publicly available 

data sources to compile a list of 

facilities that could be affected in each 

subpart. Combined with source-specific 

data, we used these facility lists to 

estimate the change in facility emissions 

or supply using the proposed new and 

revised GWPs and to identify the 

additional facilities in each subpart that 

could meet a CO2e-based threshold. 

Following this review, the EPA 

determined that there would likely be 

no new reporters from the magnesium 

production source category (subpart T). 

The EPA determined the estimated 

increases in reported emissions for each 

subpart by examining the available data 

for 2010 and 2011 reporters. For existing 

facilities submitting an initial annual 

report for reporting year 2010, the 

increase in calculated emissions from 

each facility was estimated by adjusting 

the reported GHG mass emissions to 

CO2e using the proposed AR4 GWP 

values. For existing facilities required to 

submit an initial annual report for 

reporting year 2011, we estimated CO2e 

emissions and supply using data that 

was developed to support the original 

rule, such as the subpart-specific 

technical support documents. 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 (see Docket ID No. EPA–HQ– 

OAR–2012–0934). 

2. How were the costs of this proposed 

rule estimated? 

The compliance costs associated with 

the proposed amendments were 

determined for those additional 

reporters who would be required to 

submit an annual report under Part 98 

if the proposed amendments to Table 

A–1 were finalized. The total 

compliance costs for additional 

reporters are estimated to be $3.9 

million for the first year and $1.2 

million for subsequent years (2011 

dollars). 

Costs for additional reporters are 

summarized in Table 11 of this 

preamble, which presents the first-year 

and subsequent-year costs for each 

source category. 

TABLE 11—COST IMPACTS OF PROPOSED 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 88,900 88,900 

W—Petroleum & Natural Gas Systems ...................................................................................... 99 3,400,000 860,000 

HH—Municipal Solid Waste Landfills .......................................................................................... 57 309,700 137,500 

II—Industrial Wastewater ............................................................................................................. 2 10,300 10,300 

OO—Industrial GHG Suppliers .................................................................................................... 3 10,500 10,500 

TT—Industrial Waste Landfills ..................................................................................................... 19 118,600 87,300 

Total ...................................................................................................................................... 184 3,938,000 1,194,500 

To estimate the cost impacts for 

additional reporters, the EPA used the 

methodologies from the subpart-specific 

regulatory impacts analyses from the 

original GHG reporting rule and 

updated the cost information to 2011 

dollars. In general, we determined total 

reporting costs for each subpart by 

assigning model facility costs to 

individual affected facilities in each 

industry sector. Labor costs were 

determined for monitoring, 

recordkeeping, and reporting according 

to the rule requirements. Capital costs 

for monitoring equipment were also 

estimated for each model facility. The 

total cost for each subpart was 

determined by multiplying the model 

facility cost by the number of affected 

facilities. 

For existing reporters that have 

submitted an annual report for reporting 

year 2010 or 2011, there would be no 

significant cost impacts resulting from 

the proposed amendments to Table A– 

1; using the proposed GWPs would not 

affect the cost of monitoring and 

recordkeeping and would 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. 


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B. Additional Impacts of the Proposed 

Technical Corrections and Other 

Amendments 

The proposed corrections also 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. In general, 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. Although we 

have added a few new reporting 

provisions to select source categories, 

the data we are proposing to collect is 

expected to be readily available to 

reporters; in most cases, it would 

already have been recorded and would 

not require additional monitoring or 

monitoring equipment for existing 

reporters. Additionally, the proposed 

confidentiality determinations for new 

or revised data elements would not 

affect whether and how data are 

reported and therefore, would 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). 

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) 

proposes to clarify or change specific 

provisions in the Greenhouse Gas 

Reporting Rule, including amending 

Table A–1 of Subpart A to incorporate 

new and revised GWPs, and (2) 

proposes 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 proposed 

amendments. The EPA prepared an 

analysis of the potential compliance 

costs associated with the proposed 

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 

$1,195,000 ($2011). The highest costs 

are anticipated for 99 facilities affected 

by subpart W, Petroleum and Natural 

Gas Systems, ($860,000), and 57 

facilities affected by subpart HH, 

Municipal Solid Waste Landfills 

($137,500). New facilities required to 

report under subparts I, II, OO, and TT 

would incur a combined cost of 

$197,000. The proposed confidentiality 

determinations for new and 

substantially revised data elements do 

not increase the existing compliance 

costs. The compliance costs associated 

with the proposed 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 

This action does not impose any new 

information collection burden. This 

action proposes amended GWP values 

in subpart A and other corrections and 

harmonizing revisions, and proposes 

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 proposed amendments. 

These proposed amendments and 

confidentiality determinations do not 

make any substantive changes to the 

reporting requirements in any of the 

subparts for which amendments are 

being proposed. The proposed 

amendments to subpart A include 

revision of GWPs in Table A–1 of 

subpart A. As discussed in Section V of 

this preamble, the proposed 

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 potential 

compliance costs associated with the 

proposed amendments to Table A–1 in 

the Impacts Analysis (see Docket ID No. 

EPA–HQ–OAR–2012–0934). 

Other proposed amendments to 

subpart A include adding requirements 

that provide reporters instruction 

regarding reporting of location, 

ownership, and facility identification 

(i.e., reporting of ORIS codes). The 

remaining proposed changes also 

include revising and adding definitions. 

The proposed revisions are 

clarifications or require reporting of 

information that facilities are expected 

to have readily available (e.g., latitude 

and longitude of the facility, ORIS code 

for each power generating unit), and are 

not expected to result in significant 

burden for reporters. 

The proposed amendments to the 

reporting requirements in the source 

category-specific 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 

proposed amendments are clarifications 

or corrections to existing reporting 

requirements. For example, for subpart 

H, the EPA is proposing to require 

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 proposing to include 

reporting requirements for data that are 

already collected by reporters. For 

instance, for subpart RR, the EPA is 

proposing to add 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 proposed data element does 

not require additional data collection or 

monitoring from reporters, and is not a 

significant change. 

The EPA is also proposing changes 

that would reduce the reporting burden. 

For example, for subpart BB (Silicon 

Carbide Production), the EPA is 

proposing to remove the requirement for 

facilities to report CH4 emissions from 

silicon carbide process units or 

furnaces. Additionally, the EPA is 

proposing to amend 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). The Office of Management and 

Budget (OMB) has previously 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. 


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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 impacts 

of this proposed 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-forprofit enterprise which is independently 

owned and operated and is not 

dominant in its field. 

After considering the economic 

impacts of today’s proposed rule on 

small entities, I certify that this action 

will not have a significant economic 

impact on a substantial number of small 

entities. The small entities directly 

regulated by this proposed rule are 

small businesses. We have determined 

that up to 37 small municipal solid 

waste landfills, representing up to a 

.03% increase in regulated businesses in 

this industry, will experience an impact 

of .02 to .60% of revenues; up to 3 

suppliers of industrial GHGs, 

representing up to a .02% increase in 

regulated businesses in this industry, 

will experience an impact of .02 to .14% 

of revenues; and that up to 19 industrial 

waste landfills (primarily co-located 

with food processing facilities), 

representing up to a .19% increase in 

regulated businesses in this industry, 

will experience an impact of .01 to .48% 

of revenues. 

Although this proposed 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 this rule 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 the mandatory GHG 

reporting rule and maintains an ‘‘open 

door’’ policy for stakeholders to help 

inform the EPA’s understanding of key 

issues for the industries. 

We continue to be interested in the 

potential impacts of the proposed rule 

amendments on small entities and 

welcome comments on issues related to 

such impacts. 

D. Unfunded Mandates Reform Act 

(UMRA) 

The proposed 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 

proposed rule amendments and 

confidentiality determinations are not 

subject to the requirements of section 

202 and 205 of the UMRA. 

This 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 

proposed rule amends specific 

provisions in subpart A, General 

Provisions, to reflect global warming 

potentials that have been published by 

the IPCC and to propose global warming 

potentials for certain fluorinated 

greenhouse gases. 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. 

These proposed 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 

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 

proposed 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 the 

EPA and state and local governments, 

we specifically solicit comment on this 

proposed action from state and local 

officials. 

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 proposed 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 

Concerning Regulations 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 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
19844 Federal Register / Vol. 78, No. 63 / Tuesday, April 2, 2013 / Proposed Rules 

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 proposed rulemaking does not 

involve the use of any new technical 

standards, but allows for greater 

flexibility for reporters to use consensus 

standards where they are available. 

Therefore, the EPA is not considering 

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 

proposed rule will not have 

disproportionately high and adverse 

human health or environmental effects 

on minority or low-income populations 

because it does not affect the level of 

protection provided to human health or 

the environment because it is a rule 

addressing information collection and 

reporting procedures. 

List of Subjects 40 CFR Part 98 

Environmental protection, 

Administrative practice and procedure, 

Greenhouse gases, Suppliers, Reporting 

and recordkeeping requirements. 

Dated: March 8, 2013. 

Bob Perciasepe, 

Acting Administrator. 

For the reasons stated in the 

preamble, title 40, chapter I, of the Code 

of Federal Regulations is proposed to be 

amended as follows: 

PART 98—[AMENDED] 

■ 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). 

§ 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 

location 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. 

* * * * * 

(11) * * * 

(viii) The facility or supplier must 

refer to the reporting instructions of the 

electronic GHG reporting tool regarding 

standardized conventions for the 

naming of a parent company. 

* * * * * 

(13) ORIS code for each power 

generation unit that has been assigned 

an ORIS code by the Energy Information 

Administration. 

* * * * * 

(h) * * * 

(4) Notwithstanding paragraphs (h)(1) 

and (h)(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 

(h)(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 (h)(2) within 75 days. The 

Administrator will approve the 

extension request if the request 

demonstrates that it is not practicable to 

collect and process the data needed to 

resolve potential reporting errors 

identified pursuant to paragraphs (h)(1) 

or (h)(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—(1) General. Starting with 

reporting year 2013, facilities and 

suppliers must use the revised GWPs in 

Table A–1 of this subpart, Global 

Warming Potentials, for calculating 

CO2e emissions for determining 

applicability to this part and for 

calculating CO2e emissions in annual 

GHG reports. 

(2) Special provision for reporting 

year 2013. A facility or supplier that 

was not subject to a subpart of part 98 

for reporting year 2012, but becomes 

subject to a subpart of this part 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 

for reporting year 2013. Such facilities 

or suppliers must start monitoring and 

collecting GHG data in compliance with 

this part starting on January 1, 2014, and 

submit an annual greenhouse gas report 

for reporting year 2014 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 


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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 April 2, 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. 

(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 definitions of 

‘‘Fluidized Bed Combustor (FBC)’’ and 

‘‘ORIS 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’’. 

§ 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. 

* * * * * 

Fluidized Bed Combustor (FBC) 

means a combustion technology (e.g., a 

fluidized bed boiler) where the 

maximum steady-state temperature 

reached within the combustor 

(excluding periods of startup, 

shutdown, and malfunction) during the 

combustion of solid fuels (e.g., coal, tire 

derived fuel, wood and wood residuals, 

agricultural byproducts, coke, 

municipal solid waste, or mixtures of 

such fuels) is less than or equal to 1,900 

degrees Fahrenheit. 

* * * * * 

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. 

* * * * * 

ORIS code means the unique 

identifier assigned to each power plant 

in the National Electric Energy Data 

System (NEEDS). The ORIS code is a 

four-digit number assigned by the 

Energy Information Administration 

(EIA) at the US Department of Energy to 

power plants owned by utilities. 

* * * * * 

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. 

* * * * * 

■ 4a. Table A–1 to Subpart A is revised 

to read as follows: 


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19846 Federal Register / Vol. 78, No. 63 / Tuesday, April 2, 2013 / Proposed Rules 

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 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

HFE–449s1 (HFE–7100) Chemical blend .................... 163702–07–6 

163702–08–7 

C4F9OCH3(CF3)2CFCF2OCH3 ...................................... 297 

HFE–569sf2 (HFE–7200) Chemical blend ................... 163702–05–4 

163702–06–5 

C4F9OC2H5(CF3)2CFCF2OC2H5 .................................... 59 

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

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

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

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


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Federal Register / Vol. 78, No. 63 / Tuesday, April 2, 2013 / Proposed Rules 19847 

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.) 

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

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

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

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

HFC–1234ze b ............................................................... 29118–24–9 C3H2F4 .......................................................................... 6 

hexafluoropropylene (HFP) b ........................................ 116–15–4 C3F6 .............................................................................. 0.25 

perfluoromethyl vinyl ether (PMVE) b ........................... 1187–93–5 CF(CF3)OCF3 ............................................................... 3 

tetrafluoroethylene (TFE) b ............................................ 116–14–3 C2F4 .............................................................................. 0.02 

trifluoro propene (TFP) b ............................................... 677–21–4 C3H3F3 .......................................................................... 3 

vinyl fluoride (VF) b ....................................................... 75–02–5 C2H3F ............................................................................ 0.7 

vinylidiene fluoride (VF2) b ............................................ 75–38–7 C2H2F2 .......................................................................... 0.9 

carbonyl fluoride b ......................................................... 353–50–4 COF2 ............................................................................. 2 

perfluoropropyl vinyl ether b .......................................... 1623–05–8 C5F10O .......................................................................... 3 

perfluoroethyl vinyl ether b ............................................ 10493–43–3 C4F8O ........................................................................... 3 

HFC–1234yf b ................................................................ 754–12–1 C3H2F4 .......................................................................... 4 

perfluorethyl iodide (2–I) b ............................................. 354–64–3 C2F5I ............................................................................. 3 

perfluorbutyl iodide (PFBI, 42–I) b ................................ 423–39–2 C4F9I ............................................................................. 3 

perfluorhexyl iodide (6–I) b ............................................ 355–43–1 CF3CF2CF2CF2CF2CF2IC6F13I ...................................... 2 

perfluoroctyl iodide (8–I) b ............................................. 507–63–1 C8F17I ............................................................................ 2 

1,1,1,2,2-pentafluoro-4-iodo butane (22–I) b ................. 40723–80–6 C4H4F5I ......................................................................... 2 

1,1,1,2,2,3,3,4,4-nonafluoro-6-iodo hexane (42–I) b ..... 2043–55–2 C6H4F9I ......................................................................... 2 

perfluorobutyl ethene (42–U) b ...................................... 19430–93–4 C6H3F9 .......................................................................... 2 

perfluorohexyl ethene (62–U) b ..................................... 25291–17–2 C8H3F13 ......................................................................... 1 

perfluorooctyl ethene (82–U) b ...................................... 21652–58–4 C10H3F17 ....................................................................... 1 

1H,1H, 2H,2H-perfluorohexan-1-ol (42–AL) b ............... 2043–47–2 C6H5F9O ....................................................................... 5 

FK–5–1–12 Perfluoroketone; FK–5–1–12myy2; nPerfluorooctane; Octanedecafluorooctane b.756–13–8 CF3CF2C(O)CF(CF3)2 ................................................... 1.8 

C7 Fluoroketone, Novec 774/FK–6–1–12 .................... 813–44–5 and 

813–45–6 

C7F14O Chemical Blend ............................................... 1 

trans-1-chloro-3,3,3-trifluoroprop-1-ene b ...................... 2730–43–0 C3H2ClF3 ....................................................................... 7 

Hexadecofluoroheptane b (PFC–6–1–12) ..................... 335–57–9 C7F16 ............................................................................. 7930 

octadecafluorooctane b (PFC–7–1–18) ......................... 307–34–6 C8F18 ............................................................................. 8340 

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. 

bThe GWP for this compound was not provided in the version of Table A–1 to subpart A of part 98 published on October 30, 2009. 

NA—Not available. 

■ 4b. Table A–6 is amended by revising 

the entries for 98.346(d)(1) and 

98.346(e) 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. 

* * * * * * * 

Subpart C—[AMENDED] 

■ 5. Section 98.33 is amended by: 

■ a. Adding paragraphs (b)(1)(viii) and 

(ix). 

■ b. Revising paragraphs (b)(3)(ii)(A), 

(e)(1)(ii), and (e)(3)(iv)(B). 

§ 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 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
19848 Federal Register / Vol. 78, No. 63 / Tuesday, April 2, 2013 / Proposed Rules 

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. 

(ix) May not be used for the 

combustion of waste coal (i.e., waste 

anthracite (culm) and waste bituminous 

(gob)). 

* * * * * 

(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. 

* * * * * 

(3) * * * 

(iv) * * * 

(B) Multiply the result from paragraph 

(e)(3)(iv)(A) of this section by the 

appropriate default factor to determine 

the annual biogenic CO2 emissions, in 

metric tons. For MSW, use a default 

factor of 0.55 and for tires, use a default 

factor of 0.20. 

* * * * * 

■ 6. Section 98.36 is amended by 

revising paragraph (b)(3) and the next to 

last sentence of paragraph (c)(3) 

introductory text to read as follows: 

§ 98.36 Data reporting requirements. 

* * * * * 

(b) * * * 

(3) Maximum rated heat input 

capacity of the unit, in mmBtu/hr. 

* * * * * 

(c) * * * 

(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.* * * 

* * * * * 

■ 7. Tables C–1 and C–2 to Subpart C 

are 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 

Waste Anthracite (Culm) .......................................................................................... See footnote 1 ........................................ 103 .69 

Bituminous ................................................................................................................ 24.93 ....................................................... 93 .28 

Waste Bituminous (Gob) .......................................................................................... See footnote 1 ........................................ 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 

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)2 ........................................................................... 0.092 ....................................................... 61 .71 

Propane 2 .................................................................................................................. 0.091 ....................................................... 62 .87 

Propylene 2 ............................................................................................................... 0.091 ....................................................... 67 .77 

Ethane 2 .................................................................................................................... 0.068 ....................................................... 59 .60 

Ethanol ...................................................................................................................... 0.084 ....................................................... 68 .44 

Ethylene 3 .................................................................................................................. 0.058 ....................................................... 65 .96 

Isobutane 2 ................................................................................................................ 0.099 ....................................................... 64 .94 

Isobutylene 2 ............................................................................................................. 0.103 ....................................................... 68 .86 

Butane 2 .................................................................................................................... 0.103 ....................................................... 64 .77 

Butylene 2 .................................................................................................................. 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 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 78, No. 63 / Tuesday, April 2, 2013 / Proposed Rules 19849 

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 

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 4 ....................................................... 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 5 ................................................................................................................. 1.388 × 10¥3 .......................................... 59 .00 

Biomass fuels—solid mmBtu/short ton kg CO2/mmBtu 

Wood and Wood Residuals(dry basis)6 ................................................................... 17.48 ....................................................... 93 .80 

Agricultural Byproducts ............................................................................................. 8.25 ......................................................... 118 .17 

Peat .......................................................................................................................... 8.00 ......................................................... 111 .84 

Solid Byproducts ....................................................................................................... 10.39 ....................................................... 105 .51 

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 

1Provisions of the rule referencing ‘‘default HHVs from Table C–1’’ do not apply to culm and gob. The HHV for culm and gob must be determined according to the procedures specified in the Tier 2 Calculation Methodology. 2The HHV for components of LPG determined at 60 °F and saturation pressure with the exception of ethylene. 3Ethylene HHV determined at 41 °F (5 °C) and saturation pressure. 4 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. 5 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. 6 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. 

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 ................................................................................................ 1.1 × 10¥02 1.6 × 10¥03

Anthracite for FBCs only 2 ............................................................................................................................... 1.1 × 10¥02 1.6 × 10¥01

Waste Anthracite (Culm) for FBCs only 2 ........................................................................................................ 1.1 × 10¥02 4.0 × 10¥01

Bituminous for FBCs only 2 .............................................................................................................................. 1.1 × 10¥02 1.3 × 10¥01

Waste Bituminous (Gob) for FBCs only 2 ........................................................................................................ 1.1 × 10¥02 2.9 × 10¥01

Subbituminous for FBCs only 2 ........................................................................................................................ 1.1 × 10¥02 6.5 × 10¥02

Lignite for FBCs only 2 ..................................................................................................................................... 1.1 × 10¥02 1.1 × 10¥01

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


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19850 Federal Register / Vol. 78, No. 63 / Tuesday, April 2, 2013 / Proposed Rules 

TABLE C–2 TO SUBPART C—DEFAULT CH4 AND N2O EMISSION FACTORS FOR VARIOUS TYPES OF FUEL—Continued 

Fuel type 

Default CH4

emission factor 

(kg CH4/mmBtu) 

Default N2O 

emission factor 

(kg N2O/mmBtu) 

Wood and wood residuals ............................................................................................................................... 7.2 × 10¥3 3.6 × 10¥3

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

1 Use of the default emission factors for the coal and coke category may not be used to estimate emissions from combusting anthracite, waste 

anthracite, bituminous, waste bituminous, subbituminous, or lignite coal burned in an FBC. 2 Use of these default emission factors is required for FBCs burning the specified coal type. 

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] 

■ 8. Section 98.53 is amended by: 

■ a. Revising paragraph (b)(3) and 

paragraph (d) introductory text. 

■ b. Revising paragraph (e) and 

Equation E–2. 

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

‘‘AF’’ of Equation E–3a. 

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

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

‘‘AFN’’ of Equation E–3b. 

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

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

§ 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. 

* * * * * 

(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’’). 

* * * * * 

■ 9. 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] 

■ 10. 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’’. 

§ 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) * * * 


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* * * * * 

j = Total number of ammonia processing 

units. 

* * * * * 

■ 11. 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 or monthly waste recycle 

stream quantity, you must determine the 

best available estimate(s) of the 

parameter(s), based on all available 

process data. 

■ 12. 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 (a)(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] 

■ 13. Section 98.86 is amended by 

revising paragraph (a)(2) to read as 

follows: 

§ 98.86 Data reporting requirements. 

* * * * * 

(a) * * * 

(2) Annual facility cement 

production. 

* * * * * 

Subpart K—[AMENDED] 

■ 14. 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. 

* * * * * 

■ 15. 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] 

■ 16. 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] 

■ 17. 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. 

§ 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. 

* * * * * 

■ 18. Section 98.144 is amended by 

revising paragraph (b) to read as follows: 

§ 98.144 Monitoring and QA/QC 

requirements. 

* * * * * 


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(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). 

* * * * * 

■ 19. Section 98.146 is amended by 

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

(b)(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. 

* * * * * 

■ 20. Section 98.147 is amended by 

revising paragraph (b)(5) to read as 

follows: 

§ 98.147 Records that must be retained. 

* * * * * 

(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] 

■ 21. 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. 

§ 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. 

* * * * * 

■ 22. 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. 

* * * * * 

■ 23. 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] 

■ 24. Section 98.163 is amended by: 

■ a. Revising paragraph (b) introductory 

text. 

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

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

■ c. Revising the parameters ‘‘Fdstkn’’ 

and ‘‘CCn’’ of Equation P–2. 

■ d. Revising the parameters ‘‘Fdstkn’’ 

and ‘‘CCn’’ of Equation P–3. 

§ 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 

(b)(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 of the gaseous fuel or 

feedstock used in month n (scf (at 

standard conditions of 68 °F and 

atmospheric pressure) of fuel or 

feedstock). 

CCn = Average carbon content of the gaseous 

fuel and 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). 

* * * * * 

(2) * * * 

* * * * * 

Fdstkn = Volume of the liquid fuel or 

feedstock used in month n (gallons of 

fuel or feedstock). 

CCn = Average carbon content of the liquid 

fuel or feedstock, for month n (kg carbon 

per gallon 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). 

* * * * * 

■ 25. Section 98.164 is amended by: 

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

and (b)(5) introductory text. 

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

§ 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). 


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(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). 

* * * * * 

■ 26. Section 98.166 is amended by 

revising paragraphs (a)(2) and (a)(3) 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. 

* * * * * 

■ 27. 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 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] 

■ 28. 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 

colocated 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 colocated 

with an integrated iron and steel 

manufacturing process. * * * 

■ 29. 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 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). 

§ 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). 

* * * * * 


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(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. 

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 


tkelley on DSK3SPTVN1PROD with PROPOSALS2EN02AP13.017</MATH> EP02AP13.002</MATH>
Federal Register / Vol. 78, No. 63 / Tuesday, April 2, 2013 / Proposed Rules 19855 

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). 

■ 30. Section 98.174 is amended by 

revising the last sentence of paragraph 

(b)(1), and revising paragraph (c)(2), to 

read as follows: 

§ 98.174 Monitoring and QA/QC 

requirements. 

* * * * * 

(b) * * * 

(1) * * * Determine the mass rate of 

fuels using the procedures for 

combustion units in § 98.34. 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 

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. 

* * * * * 

■ 31. 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). 

* * * * * 

■ 32. 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: 

* * * * * 

■ 33. 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] 

■ 34. 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). 

* * * * * 

■ 35. 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. 

■ 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. 

■ 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 to read as 

follows: 

§ 98.193 Calculating GHG emissions. 

* * * * * 

(a) If all lime kilns meet the 

conditions specified in § 98.33(b)(4)(ii) 

or (b)(4)(iii), you must calculate and 

report under this subpart the combined 

process and combustion CO2 emissions 

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 

(b)(2)(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: 

* * * * * 


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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. 

* * * * * 

■ 36. Section 98.194 is amended by: 

■ a. Revising paragraph (a). 

■ b. Revising paragraph (b). 

■ c. Revising paragraph (c) introductory 

text. 

§ 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 

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. 

* * * * * 

■ 37. Section 98.195 is amended by 

revising paragraph (a). 

§ 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. 

* * * * * 

■ 38. Section 98.196 is amended by 

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

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

(b)(10), (b)(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] 

■ 39. 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. 

* * * * * 

■ 40. Section 98.223 is amended by: 

■ a. Revising paragraphs (b) 

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

introductory text, and (e). 

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

‘‘DF’’, and ‘‘AF’’ of Equation V–3a. 

■ c. Revising paragraph (g)(2) 

introductory text. 

■ d. Revising parameters ‘‘EN2Ot’’, 

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

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

V–3b. 

■ e. Revising paragraph (g)(3) 

introductory text. 

■ f. Revising parameters ‘‘EN2Ot’’, 

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

‘‘FCN’’ of Equation V–3c. 

■ g. Revising parameter ‘‘EN2Ot’’ of 

Equation V–3d. 

■ h. Revising paragraph (i). 

§ 98.223 Calculating GHG emissions. 

* * * * * 

(b) You must conduct an annual 

performance test for each nitric acid 

train according to paragraphs (b)(1) 

through (b)(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 


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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), (d)(2), or (d)(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. 

* * * * * 

(g) * * * 

(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). 

■ 41. 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 (c)(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. 

■ 42. Section 98.226 is amended by: 

■ a. Revising paragraph (a) and 

paragraph (n) introductory text. 

■ b. Adding and reserving paragraph (o). 

■ c. Revising paragraph (p). 

§ 98.226 Data reporting requirements. 

* * * * * 

(a) Nitric Acid train identification 

number. 

* * * * * 

(n) If you requested Administrator 

approval for an alternative method of 

determining N2O emissions under 

§ 98.223(a)(2), each annual report must 

also contain the information specified in 

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

section for each nitric acid production 

facility. 

* * * * * 

(o) [Reserved] 

(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 X—[AMENDED] 

■ 43. 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 


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emissions under subpart C of this part 

(General Stationary Fuel Combustion 

Sources) by following the requirements 

of subpart C for all fuels, except 

emissions from burning petrochemical 

process off-gas in any combustion 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. 

* * * * * 

■ 44. Section 98.243 is amended by: 

■ a. Revising paragraph (b). 

■ b. Revising paragraphs (c)(3) and 

(c)(4). 

■ c. Revising the parameters ‘‘Cg’’, 

‘‘(Fgf)i, n’’, ‘‘(Pgp)i, n’’, and ‘‘(MWp)i’’ of 

Equation X–1. 

■ d. Removing the parameter ‘‘(MWf)I’’ 

of Equation X–1 and adding parameter 

‘‘(MWf)i, n’’ in its place. 

■ e. Revising paragraph (d)(3)(i). 

§ 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 (b)(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/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/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). 

* * * * * 

■ 45. Section 98.244 is amended by: 

■ a. Revising the last sentence of 

paragraph (b)(4) introductory text, and 

paragraphs (b)(4)(xiii), (b)(4)(xiv), and 

(b)(4)(xv)(A). 

■ b. Adding paragraph (c). 

§ 98.244 Monitoring and QA/QC 

requirements. 

* * * * * 

(b) * * * 

(4) * * * Analyses conducted in 

accordance with methods specified in 

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

this 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). 

* * * * * 


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

(d), conduct monitoring and QA/QC for 

flares in accordance with § 98.254. 

■ 46. 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). 

■ 47. Section 98.246 is amended by: 

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

(a)(9), (a)(11) introductory text, (b)(2), 

(b)(4), and (b)(5). 

■ b. Removing and reserving paragraphs 

(b)(5)(i) through (iv), and (b)(6). 

■ c. Revising paragraph (c)(4). 

§ 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 

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) If you comply with the alternative 

to sampling and analysis specified in 

§ 98.243(c)(4), the number of days 

during which off-specification product 

was produced, and if applicable, the 

date of any process change that reduced 

the composition to less than 99.5 

percent. 

* * * * * 

(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. 

* * * * * 

(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 § 98.36(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 is 

attributable to 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. 

(i) [Reserved] 

(ii)[Reserved] 

(iii) [Reserved] 

(iv)[Reserved] 

(6) [Reserved] 

* * * * * 

(c) * * * 

(4) Name and annual quantity of each 

feedstock (metric tons). 

* * * * * 

48. Section 98.247 is amended by 

revising paragraphs (b) introductory text 

and (b)(2) 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 (b)(4) of this section. 

* * * * * 

(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. 

* * * * * 

■ 49. 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] 

■ 50. 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. 

■ 51. Section 98.253 is amended by: 

■ a. Revising the parameter ‘‘EmFCH4’’ 

to Equation Y–4 and ‘‘EmFN2O’’ to 

Equation Y–5. 

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

and (f)(4) introductory text. 

■ c. Revising parameters ‘‘FSG’’ and 

‘‘MFc’’ to Equation Y–12. 

■ d. Revising paragraphs (j) introductory 

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

introductory text. 

§ 98.253 Calculating GHG emissions. 

* * * * * 

(b) * * * 

(2) * * * 

* * * * * 

EmFCH4 = Default CH4 emission factor for 

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


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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 for off-site for sulfur recovery 

(scf/year). 

* * * * * 

MFC = Mole fraction of carbon in the sour gas 

fed to the sulfur recovery plant or the 

four gas feed sent for 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 the 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 is 

considered to be controlled and is 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 (m)(2) of this section. 

* * * * * 

■ 52. Section 98.256 is amended by: 

■ a. Revising paragraphs (f)(6), (h) 

introductory text, (h)(2), (h)(3), (h)(4), 

(h)(5), and (h)(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). 

§ 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 

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). 

* * * * * 


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(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. 

(5) [Reserved] 

(6) [Reserved] 

(7) [Reserved] 

* * * * * 

Subpart Z—[AMENDED] 

■ 53. 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). 

* * * * * 

■ 54. 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. 

* * * * * 

■ 55. Section 98.265 is amended by 

adding introductory text and revising 

paragraph (a) 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. 

* * * * * 

■ 56. Section 98.266 is amended by 

revising paragraphs (a), (b), (d), (f)(5), 

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

§ 98.266 Data reporting requirements. 

* * * * * 

(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). 

* * * * * 

■ 57. 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] 

■ 58. 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). 

* * * * * 

■ 59. 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) Annual production of pulp and/or 

paper products produced (metric tons) 

as follows: 

(1) Report the total annual production 

of unbleached virgin pulp produced 


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onsite during the reporting year in airdried 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. 

(i) Do not include secondary fiber 

repulped for paper production in the 

virgin pulp production total. 

(ii) You must report a positive (nonzero) value for pulp production unless 

your pulp mill did not operate during 

the reporting year. 

(2) Report the total annual production 

of paper products exiting the paper 

machine(s), prior to application of any 

off-machine coatings, in air-dried metric 

tons per year. If you operate multiple 

paper machines, report the sum (total) 

of the air-dried metric tons of paper 

produced during the reporting year for 

all paper machines at the mill. 

■ 60. Tables AA–1 and AA–2 are 

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) 

CO2

a 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. 

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 NAa .............................. NAa. 

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

aEmission factors for kraft calciners are not available. 

Subpart BB—[AMENDED] 

■ 61. 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. 

* * * * * 

■ 62. 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. 

■ d. Removing paragraph (d). 

§ 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). 

* * * * * 

■ 63. 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 (b)(8) of this section for all 

silicon carbide process units or 

production furnaces combined: 

* * * * * 

Subpart DD—[AMENDED] 

■ 64. Section 98.304 is amended by 

revising paragraphs (c)(1) and (c)(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 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
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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] 

■ 65. Section 98.320 is amended by 

revising paragraphs (b)(1) and (b)(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). 

* * * * * 

■ 66. 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). 

* * * * * 

■ 67. Section 98.323 is amended by: 

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

‘‘(fH2O)’’, and ‘‘P’’ of Equation FF–2. 

■ b. Revising paragraphs (a)(2) and 

(b)(1). 

■ c. Revising Equation FF–3 and 

parameters ‘‘Vi’’, ‘‘MCFi’’, ‘‘Pi’’, and 

‘‘(fH2O)’’ of Equation FF–3. 

■ d. Removing parameter ‘‘(CH4D)’’ of 

Equation FF–4 and adding parameter 

‘‘(CH4D)i,j’’ in its place. 

■ e. Revising paragraph (c) introductory 

text and Equation FF–6. 

§ 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 methane 

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 

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– 


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19864 Federal Register / Vol. 78, No. 63 / Tuesday, April 2, 2013 / Proposed Rules 

1 or Equation FF–4 of this section, as 

applicable. 

* * * * * 

(1) * * * 

* * * * * 

■ 68. Section 98.324 is amended by 

revising paragraphs (b) introductory 

text, (c)(2), and parameter ‘‘CCH4’’ of 

Equation FF–9 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. 

* * * * * 

(d) * * * 

(2) * * * 

(iii) * * * 

* * * * * 

CCH4 = Methane (CH4) concentration in the 

gas (volume %) for use in Equations FF– 

1 and FF–3 of this subpart. 

* * * * * 

■ 69. Section 98.326 is amended by 

revising paragraphs (a), (f), (h), (i), (j), 

(o), and (r), and adding paragraphs 

(r)(1), (r)(2), (r)(3), (t), and (u) 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 

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 and shaft, 

including paragraphs (r)(1) through 

(r)(3) of this section: 

(1) Indication of whether the well or 

shaft 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 or shaft. 

(3) Number of days the well or shaft 

was in operation during the reporting 

year. 

* * * * * 

(t) Quarterly CH4 routed to each 

destruction device or offsite transfer 

point used in Equation FF–5 of this 

subpart (metric tons). 

(u) Mine Safety and Health 

Administration (MSHA) identification 

for this coal mine. 

Subpart HH—[AMENDED] 

■ 70. Section 98.343 is amended by: 

■ a. Revising the parameters ‘‘DOC’’ and 

‘‘F’’ of Equation HH–1. 

■ b. Revising Equation HH–4 and the 

parameters ‘‘N’’ and ‘‘0.0423’’ of 

Equation HH–4. 

■ 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 at paragraph (c)(1). 

■ e. Revising paragraphs (c)(3)(i) and 

(c)(3)(ii). 

§ 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 percent oxygen); 

otherwise, use the default of 0.5. 

* * * * * 

(b) * * * 

(1) * * * 


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* * * * * 

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. 

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 

destroyed in a back-up flare (or similar 

device) or if the gas is transported off-site 

for destruction, use fDest= 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. 


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19866 Federal Register / Vol. 78, No. 63 / Tuesday, April 2, 2013 / Proposed Rules 

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 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 

destroyed in a back-up flare (or similar 

device) or if the gas is transported off-site 

for destruction, use fDest = 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. 

■ 71. 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 (e)(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 

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 

shall also be recorded, and the technical 

basis for these estimates shall be 

provided. 

■ 72. 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. 

■ 73. Section 98.346 is amended by 

revising paragraphs (d)(1), (e), (h), (i)(5), 

(i)(8), (i)(10), (i)(11), and (i)(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 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. 


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(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 an 

indication of whether a back-up 

destruction device is present at the 

landfill, the annual operating hours for 

the primary destruction device, the 

annual operating hours for the back-up 

destruction device (if present), and the 

destruction efficiency used (percent). 

* * * * * 

(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. 

■ 74. 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. 

* * * * * 

■ 75. Table HH–1 to Subpart HH is 

amended by revising the entry for ‘‘OX’’ 

as follows: 

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.

................

****

* 

■ 76. 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 

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 

TABLE HH–2 TO SUBPART HH OF

PART 98—U.S. PER CAPITA WASTE

DISPOSAL RATES—Continued 

Year 

Waste per 

capita 

ton/cap/yr 

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 

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 

■ 77. 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

If your methane flux ratea for 

the reporting year is: 

Use this 

landfill 

methane 

oxidation 

raction: 

Less than 10 grams per 

square meter per day (g/ 

m2/d) ................................. 0.35 

10 to 70 g/m2/d ..................... 0.25 

Greater than 70 g/m2/d ........ 0.10 

aMethane 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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19868 Federal Register / Vol. 78, No. 63 / Tuesday, April 2, 2013 / Proposed Rules 

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, for application with 

Equation HH–6 only, the greater of the 

modeled methane generation rate in 

reporting year from Equation HH–1 of 

this subpart 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] 

■ 78. Section 98.353 is amended by 

revising the parameters ‘‘fDest_1’’ and 

‘‘fDest_2’’ of Equation II–6 to read as 

follows: 

§ 98.353 Calculating GHG emissions. 

* * * * * 

(d) * * * 

(2) * * * 

* * * * * 

fDest1 = 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. 

* * * * * 

fDest2 = 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] 

■ 79. Section 98.386 is amended by: 

■ a. Removing and reserving paragraphs 

(a)(1) and (a)(5). 

■ b. Revising paragraph (a)(4), (a)(8), 

(a)(9)(v), and (a)(11)(v). 

■ c. Removing and reserving paragraph 

(a)(13). 

■ d. Revising paragraphs (a)(14), (a)(15) 

and (a)(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), 

(d)(2), and (d)(3) to 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) * * * 

(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. 

* * * * * 

(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 


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Federal Register / Vol. 78, No. 63 / Tuesday, April 2, 2013 / Proposed Rules 19869 

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 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] 

■ 80. Section 98.393 is amended by: 

■ a. Revising the parameter ‘‘Producti’’ 

to Equation MM–1 in paragraph (a)(1). 

■ b. Revising the parameter ‘‘Producti’’ 

to Equation MM–1 in paragraph (a)(2). 

■ c. Revising paragraphs (h)(1) 

introductory text and (h)(2) introductory 

text. 

§ 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. 

* * * * * 

■ 81. 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 and reserving paragraph 

(d). 

§ 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. 

* * * * * 

■ 82. Section 98.395 is amended by: 

■ a. Revising paragraph (a) introductory 

text. 

■ b. Revising paragraph (b). 

■ c. Removing paragraph (c). 

§ 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. 

■ 83. Section 98.396 is amended by: 

■ a. Removing and reserving paragraph 

(a)(1). 

■ b. Revising paragraph (a)(4). 

■ c. Removing and reserving paragraph 

(a)(5). 

■ d. Revising paragraphs (a)(8), (a)(9) 

introductory text, (a)(9)(iii), (a)(9)(v), 

(a)(10) introductory text, (a)(11) 

introductory text, and (a)(11)(iii). 

■ e. Removing and reserving paragraph 

(a)(13). 

■ f. Revising paragraphs (a)(15) and 

(a)(18). 

■ g. Revising paragraphs (a)(20), (a)(21) 

and (a)(22). 

■ h. Removing paragraph (a)(23). 

■ i. Removing and reserving paragraph 

(b)(1). 

■ j. Revising paragraphs (b)(2), (b)(4), 

(b)(5) introductory text, and (b)(6) 

introductory text. 

■ k. Removing and reserving paragraph 

(c)(1). 

■ l. Revising paragraph (c)(4), (c)(5) 

introductory text, (c)(6) introductory 

text, (d)(2), and (d)(3). 

§ 98.396 Data reporting requirements. 

* * * * * 

(a) * * * 

(1) [Reserved] 

* * * * * 

(4) Each standard method or other 

industry standard practice used to 

measure each quantity reported in 

paragraph (a)(2) of this section. 

(5) [Reserved] 

* * * * * 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
19870 Federal Register / Vol. 78, No. 63 / Tuesday, April 2, 2013 / Proposed Rules 

(8) Each standard method or other 

industry standard practice used to 

measure each quantity reported in 

paragraph (a)(6) of this section. 

(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. 

* * * * * 

(13) [Reserved] 

* * * * * 

(15) Each standard method or other 

industry standard practice used to 

measure each quantity reported in 

paragraph (a)(14) of this section. 

* * * * * 

(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) In addition to the information 

required by § 98.3(c), each importer 

shall report all of the following 

information at the corporate level: 

(1) [Reserved] 

(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. 

* * * * * 

(4) Each standard method or other 

industry standard practice used to 

measure each quantity reported in 

paragraph (b)(2) of this section. 

(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) * * * 

(1) [Reserved] 

* * * * * 

(4) Each standard method or other 

industry standard practice used to 

measure each quantity reported in 

paragraph (c)(2) of this section. 

(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 

paragraphs (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. 

■ 84. 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. 

* * * * * 

■ 85. 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’’. 

§ 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. 

■ 86. 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. 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
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TABLE MM–1 TO SUBPART MM OF PART 98—DEFAULT FACTORS FOR PETROLEUM PRODUCTS AND NATURAL GAS

LIQUIDS1 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 

* * * * * * * 

Ethane3 .................................................................................................................................................... 0.0579 79.89 0.170 

Ethylene4 ................................................................................................................................................. 0.0492 85.63 0.154 

Propane3 .................................................................................................................................................. 0.0806 81.71 0.241 

Propylene3 ............................................................................................................................................... 0.0827 85.63 0.260 

Butane3 .................................................................................................................................................... 0.0928 82.66 0.281 

Butylene3 ................................................................................................................................................. 0.0972 85.63 0.305 

Isobutane3 ................................................................................................................................................ 0.0892 82.66 0.270 

Isobutylene3 ............................................................................................................................................. 0.0949 85.63 0.298 

* * * * * * * 

1 In the case of products blended with some portion of biomass-based fuel, the carbon share in Table MM–1 of this subpart represents only the 

petroleum-based components. 2Products that are derived entirely from biomass should not be reported, but products that were derived from both biomass and a petroleum 

product (i.e., co-processed) should be reported as the petroleum product that it most closely represents. 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] 

■ 87. 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. 

* * * * * 

■ 88. Section 98.403 is amended by: 

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

Equation NN–2. 

■ b. Revising paragraphs (b)(1) 

introductory text and (b)(2)(i). 

■ c. Revising parameters ‘‘CO2k’’ and 

‘‘Fuel’’ to Equation NN–4. 

■ d. Revising paragraph (b)(3). 

■ e. Revising paragraph (b)(4). 

■ f. Revising paragraph (c)(2) 

introductory text. 

■ g. Revising parameter ‘‘CO2’’ to 

Equation NN–8. 

§ 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 endusers registering a supply equal to or 

greater than 460,000 Mscf per year, use 

Equation NN–4 of this section and the 

default values for the CO2 emission 

factors found in Table NN–2 of this 

subpart. 

(ii) * * * 

* * * * * 

CO2 k = Annual CO2 mass emissions that 

would result from the combustion or 

oxidation of natural gas delivered to each 

end-user that receives a supply equal to 

or greater than 460,000 Mscf per year 

(metric tons). 

Fuel = Total annual volume of natural gas 

supplied to this end-user, if known, 

otherwise, the annual volume supplied 

to this meter (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 

used, provided it is developed using 

methods outlined in § 98.404. 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
19872 Federal Register / Vol. 78, No. 63 / Tuesday, April 2, 2013 / Proposed Rules 

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 (a)(2) 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). 

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 

end-user that receives a supply equal to 

or greater than 460,000 Mscf per year as 

calculated in paragraph (b)(2) of this 

section (metric tons). 

CO2l = Annual CO2 mass emissions that 

would result from the combustion or 

oxidation of 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). 

(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). 

* * * * * 

■ 89. 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), 

(d)(1), and (d)(2). 

■ d. Adding paragraph (d)(3). 

§ 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 end-user’s meter(s). Where an enduser is known to have more than one 

meter located at their facility, 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 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 end-user. 

(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 


tkelley on DSK3SPTVN1PROD with PROPOSALS2EP02AP13.031</GPH> EP02AP13.032</GPH> EP02AP13.033</GPH>
Federal Register / Vol. 78, No. 63 / Tuesday, April 2, 2013 / Proposed Rules 19873 

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. 

■ 90. Section 98.405 is amended by 

removing and reserving paragraph (c)(3). 

■ 91. Section 98.406 is amended by: 

■ a. Revising paragraph (a)(4). 

■ b. Revising paragraphs (a)(7), (b)(2), 

and (b)(3). 

■ c. Removing and reserving paragraph 

(b)(4). 

■ d. Revising paragraphs (b)(5), (b)(7), 

(b)(9), and (b)(12) introductory text. 

§ 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). 

(4) [Reserved] 

(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 enduser facility that received from the LDC 

deliveries equal to or greater than 

460,000 Mscf during the calendar year, 

if known; otherwise, report 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. 

* * * * * 

(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 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 the end-user, 

or the quantity delivered to a specific 

meter. 

* * * * * 

■ 92. 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: 

* * * * * 

■ 93. Tables NN–1 and NN–2 to subpart 

NN are 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 value1

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. 

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. 


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Subpart PP—[AMENDED] 

■ 94. 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. 

* * * * * 

■ 95. Section 98.426 is amended by 

revising paragraphs (b)(4)(i), (b)(4)(ii), 

(f)(10), and (f)(11) to read as follows: 

§ 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 CO2 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] 

■ 96. Section 98.433 is amended by 

revising the parameter ‘‘St’’ of Equation 

QQ–1 and Equation QQ–2 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). 

* * * * * 

■ 97. 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. 

■ 98. Section 98.436 is amended by: 

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

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

(b)(6)(ii), and (b)(6)(iii). 

Removing and reserving paragraphs 

(a)(5), (a)(6)(iv), (b)(5), and (b)(6)(iv). 

§ 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. 

(5) [Reserved] 

(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. 

(iv) [Reserved] 

* * * * * 

(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. 

(5) [Reserved] 

(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. 

(iv) [Reserved] 

* * * * * 

■ 99. 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] 

■ 100. Section 98.443 is amended by: 

■ a. Revising the parameter ‘‘Sr,p’’ of 

Equation RR–2 at paragraph (a)(2). 


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■ b. Revising paragraph (d)(3) 

introductory text. 

■ c. Revising the parameter ‘‘CO2FI’’ of 

Equation RR–12. 

§ 98.443 Calculating CO2 geologic 

sequestration. 

* * * * * 

(a) * * * 

(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) * * * 

(3) To aggregate production data, you 

must sum the mass of all of the CO2

separated at each gas-liquid separator in 

accordance with the procedure specified 

in Equation RR–9 of this section. You 

must assume that the total CO2

measured at the separator(s) represents 

a percentage of the total CO2 produced. 

In order to account for the percentage of 

CO2 produced that is estimated to 

remain with the produced oil or other 

fluid, you must multiply the quarterly 

mass of CO2 measured at the 

separator(s) by a percentage estimated 

using a methodology in your approved 

MRV plan. If fluids containing CO2 from 

injection wells covered under this 

source category are produced and not 

processed through a gas-liquid 

separator, the concentration of CO2 in 

the produced fluids must be measured 

at a flow meter located prior to 

reinjection or reuse using methods in 

§ 98.444(f)(1). 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. 

■ 101. 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] 

■ 102. Section 98.453 is amended by: 

■ a. Revising paragraph (d). 

■ b. Revising paragraph (h). 

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

Equation SS–6. 

§ 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. 

* * * * * 

■ 103. 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] 

■ 104. 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). 

* * * * * 

■ 105. Section 98.463 is amended by: 

■ a. Revising the parameter ‘‘DOCF’’ of 

Equation TT–1. 

■ b. Removing the parameter ‘‘Fx’’ of 

Equation TT–1 and adding in its place 

the parameter ‘‘F’’. 

■ c. Revising Equation TT–4b. 

■ d. Revising the parameter ‘‘OX’’ of 

Equation TT–6. 

§ 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) * * * 

* * * * * 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
19876 Federal Register / Vol. 78, No. 63 / Tuesday, April 2, 2013 / Proposed Rules 

* * * * * 

(b) * * * 

(1) * * * 

* * * * * 

OX = Oxidation fraction from Table HH–4 of 

subpart HH of this part. 

* * * * * 

■ 106. Section 98.464 is amended by: 

■ a. Revising paragraph (b) introductory 

text. 

■ b. Revising Equation TT–7. 

■ c. Removing the parameters ‘‘DOCF’’, 

‘‘MCDcontrol’’, and ‘‘MCcontrol’’ of Equation 

TT–7. 

■ d. Revising paragraph (c). 

§ 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 but 

was not received during the first 

reporting year 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 (c)(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 

(b)(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. 

* * * * * 

■ 107. 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). 

§ 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: 

(1) [Reserved] 

(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; and 

(3) All information required under 40 

CFR 98.346(i)(1) through (i)(7) and 40 

CFR 98.346(i)(9) through (i)(12). 

■ 108. Section 98.467 is revised to read 

as follows: 


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Federal Register / Vol. 78, No. 63 / Tuesday, April 2, 2013 / Proposed Rules 19877 

§ 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 

(c)(2)(xiii) or used to determine waste 

stream-specific DOCX values for use in 

Equation TT–1 of this subpart. 

■ 109. 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 climatea] 

(yr thnsp; minus;1) 

k 

[moderate 

climatea] 

(yr minus;1) 

k 

[wet climatea] 

(yr minus;1) 

Food Processing (other than sludge) ............................................................. 0.22 0.06 0.12 0.18 

Pulp and Paper (other than sludge) ............................................................... 0.20 0.02 0.03 0.04 

Wood and Wood Product (other than 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 

* * * * * * * * * 

a The 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. 

(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. 

Subpart UU—[AMENDED] 

■ 110. Section 98.473 is amended by 

revising: 

■ a. The parameter ‘‘D’’ of Equation 

UU–2 in paragraph (a)(2). 

■ b. The parameter ‘‘Sr,p’’ of Equation 

UU–2 in paragraph (b)(2). 

§ 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). 

* * * * * 

■ 111. Section 98.476 is amended by: 

■ a. Revising paragraph (b)(5). 

■ b. Adding paragraph (e). 

§ 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. 2013–06093 Filed 4–1–13; 8:45 am] 

BILLING CODE 6560–50–P 


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