6560.50

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 98

[EPA-HQ-OAR-2011-0147; FRL-]

RIN 2060-AQ85

Mandatory Reporting of Greenhouse Gases

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

SUMMARY: EPA is proposing to amend specific provisions in 

the Mandatory Reporting of Greenhouse Gases Rule to correct 

certain technical and editorial errors that have been 

identified since promulgation and to clarify or propose 

amendments to certain provisions that have been the subject 

of questions from reporting entities. These proposed 

changes include additional information to clarify 

compliance obligations, correct data reporting elements so 

they more closely conform to the information used to 

perform emission calculations, and make other corrections 

and amendments. EPA has received petitions for 

reconsideration on some of these subparts. EPA is still 

considering these petitions, and the issues raised in the 

petitions are not discussed or addressed in this action. 
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DATES: Comments. Comments must be received on or 

before [INSERT THE DATE 45 DAYS AFTER PUBLICATION OF THIS 

PROPOSED RULE IN THE FEDERAL REGISTER]. 

Public Hearing. EPA does not plan to conduct a public 

hearing unless requested. To request a hearing, please 

contact the person listed in the following FOR FURTHER 

INFORMATION CONTACT section by [INSERT DATE 7 DAYS AFTER 

DATE OF PUBLICATION OF THIS PROPOSED RULE IN THE FEDERAL 

REGISTER]. If requested, the hearing will be conducted on 

[INSERT DATE 15 DAYS AFTER DATE OF PUBLICATION OF THIS 

PROPOSED RULE IN THE FEDERAL REGISTER], in the Washington, 

DC area. EPA will provide further information about the 

hearing on its webpage if a hearing is requested.

ADDRESSES: You may submit your comments, identified 

by Docket ID No. EPA-HQ-OAR-2011-0147 by any of the 

following methods:

 Federal eRulemaking Portal: 

http://www.regulations.gov. Follow the online 

instructions for submitting comments.

 E-mail: MRR_Corrections@epa.gov. Include Docket ID No. 

EPA-HQ-OAR-2011-0147 [and/or RIN number] in the 

subject line of the message.

 Fax: (202) 566–9744.

 Mail: Environmental Protection Agency, EPA Docket 

Center (EPA/DC), Mailcode 2822T, Attention Docket ID 

No. EPA-HQ-OAR–2011-0147, 1200 Pennsylvania Avenue, 

NW., Washington, DC 20004.

 Hand/Courier Delivery: EPA Docket Center, Public 

Reading Room, EPA West Building, Room 3334, 1301 
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Constitution Avenue, NW., Washington, DC 20004. Such 

deliveries are only accepted during the Docket’s 

normal hours of operation, and special arrangements 

should be made for deliveries of boxed information.

Instructions: Direct your comments to Docket ID No. 

EPA–HQ–OAR–2011-0147, 2011 Technical Corrections, 

Clarifying and Other Amendments to Certain Provisions of 

the Mandatory Reporting of Greenhouse Gases Rule. 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. Do not submit information that you consider to 

be CBI or otherwise protected through 

http://www.regulations.gov or e-mail. The 

http://www.regulations.gov website is an “anonymous access” 

system, which means EPA will not know your identity or 

contact information unless you provide it in the body of 

your comment. If you send an e-mail comment directly to 

EPA without going through http://www.regulations.gov your 

e-mail address will be automatically captured and included 

as part of the comment that is placed in the public docket 

and made available on the Internet. If you submit an 
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electronic comment, EPA recommends that you include your 

name and other contact information in the body of your 

comment and with any disk or CD–ROM you submit. If EPA 

cannot read your comment due to technical difficulties and 

cannot contact you for clarification, EPA may not be able 

to consider your comment. Electronic files should avoid 

the use of special characters, any form of encryption, and 

be free of any defects or viruses.

Docket: All documents in the docket are listed in the 

http://www.regulations.gov index. Although listed in the 

index, some information is not publicly available, e.g., 

CBI or other information whose disclosure is restricted by 

statute. Certain other material, such as copyrighted 

material, will be publicly available only in hard copy. 

Publicly available docket materials are available either 

electronically in http://www.regulations.gov or in hard 

copy at the Air Docket, EPA/DC, EPA West 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), 
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Environmental Protection Agency, 1200 Pennsylvania Ave., 

NW, Washington, DC 20460; telephone number: (202) 343-9263; 

fax number: (202) 343-2342; e-mail address: 

GHGReportingRule@epa.gov. For technical information, 

please go to the Greenhouse Gas Reporting Rule Program 

website 

http://www.epa.gov/climatechange/emissions/ghgrulemaking.ht

ml. To submit a question, select Rule Help Center, 

followed by Contact Us. To obtain information about the 

public hearing or to register to speak at the hearing, 

please go to 

http://www.epa.gov/climatechange/emissions/ghgrulemaking.ht

ml. Alternatively, contact Carole Cook at 202–343–9263. 

Worldwide Web (WWW). In addition to being available 

in the docket, an electronic copy of this proposal will 

also be available through the WWW. Following the 

Administrator's signature, a copy of this action will be 

posted on EPA's Greenhouse Gas Reporting Program website at 

http://www.epa.gov/climatechange/emissions/ghgrulemaking.ht

ml.

SUPPLEMENTARY INFORMATION:

Additional Information on Submitting Comments: To 

expedite review of your comments by Agency staff, you are 

encouraged to send a separate copy of your comments, in 
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addition to the copy you submit to the official docket, to 

Carole Cook, U.S. EPA, Office of Atmospheric Programs, 

Climate Change Division, Mail Code 6207–J, Washington, DC, 

20460, telephone (202) 343-9263, e-mail address:

GHGReportingRule@epa.gov.

Regulated Entities. The Administrator determined that 

this action is subject to the provisions of Clean Air Act 

(CAA) section 307(d). See CAA section 307(d)(1)(V) (the 

provisions of section 307(d) apply to “such other actions 

as the Administrator may determine”). These are proposed 

amendments to existing regulations. If finalized, these 

amended regulations would affect owners or operators of 

certain industrial gas suppliers and direct emitters of 

GHGs. 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

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.

Underground Coal 

Mines

212113 Underground anthracite coal mining 

operations.

212112 Underground bituminous coal mining 

operations.

Electrical 

Transmission and 

Distribution 

Equipment Use 

221121 Electric bulk power transmission 

and control facilities.
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Category NAICS Examples of affected 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.

Suppliers of 

Industrial GHGs

325120 Industrial gas production 

facilities.

Geologic 

Sequestration of 

Carbon Dioxide

N/A CO2 geologic sequestration projects

Industrial Waste 

Landfills

562212 Solid waste landfills.

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.

221320 Sewage treatment facilities.

Table 1 of this preamble is not intended to be 

exhaustive, but rather lists the types of facilities or 

suppliers that EPA is now aware could be potentially 

affected by the reporting requirements. Other types of 

facilities and suppliers 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 
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the sections related to suppliers and direct emitters of 

GHGs. If you have questions regarding the applicability of 

this action to a particular facility or supplier, consult 

the person listed in the preceding FOR FURTHER INFORMATION 

CONTACT Section.

Acronyms and Abbreviations. The following acronyms 

and abbreviations are used in this document.

acf actual cubic feet

AGR acid gas removal

ASTM American Society for Testing and Materials

BAMM best available monitoring methods

CAA Clean Air Act

CBI confidential business information

CEMS continuous emissions monitoring system

CFC chlorofluorocarbon

CFR Code of Federal Regulations

CH4 methane

CO2 carbon dioxide

DOC degradable organic carbon

EF emission factor

e-GGRT electronic-GHG Reporting Tool

EPA U.S. Environmental Protection Agency

FR Federal Register

GHG greenhouse gas

GHGRP Greenhouse Gas Reporting Program

HCFC hydrochlorofluorocarbon

kg kilograms

kg/ft3 kilograms per cubic foot

mcf methane correction factor

MMscf million standard cubic feet

MRV monitoring, reporting and verification
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MSHA Mine Safety and Health Administration

MtCO2e metric tons carbon dioxide equivalent

N2O nitrous oxide

NAICS North American Industry Classification System

NOAA National Oceanic and Atmospheric Administration

NTTAA National Technology Transfer and Advancement Act

OMB Office of Management and Budget

PFCs perfluorocarbons

psia pounds per square inch absolute

RFA Regulatory Flexibility Act

SF6 sulfur hexafluoride

U.S. United States

UMRA Unfunded Mandates Reform Act of 1995

TABLE OF CONTENTS 

I. Background

A. How is this preamble organized?

B. Background on This Action

C. Legal Authority

D. How would these amendments apply to 2012 reports?

II. Technical Corrections and Other Amendments

A. Subpart A – General Provisions

B. Subpart W – Petroleum and Natural Gas Systems

C. Subpart FF — Underground Coal Mines

D. Subpart II – Industrial Wastewater Treatment

E. Subpart OO — Suppliers of Industrial Greenhouse Gases

F. Subpart RR – Geologic Sequestration of Carbon Dioxide

G. Subpart TT — Industrial Waste Landfills

III. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review 

and Executive Order 13563: Improving Regulation and 

Regulatory Review

B. Paperwork Reduction Act

C. Regulatory Flexibility Act (RFA)

D. Unfunded Mandates Reform Act (UMRA)

E. Executive Order 13132: Federalism

F. Executive Order 13175: Consultation and Coordination 

with Indian Tribal Governments

G. Executive Order 13045: Protection of Children from 

Environmental Health Risks and Safety Risks
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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 LowIncome Populations

I. Background

A. How is this preamble organized?

The first section of this preamble contains the basic 

background information about the origin of these proposed 

rule amendments and request for public comment. This 

section also discusses EPA’s use of our legal authority 

under the Clean Air Act to collect data under the Mandatory 

Reporting of Greenhouse Gases (GHG reporting) rule.

The second section of this preamble describes in 

detail the changes that are being proposed to correct 

technical errors, to provide clarification, or propose 

amendments to address implementation issues identified by 

EPA and others. This section also presents EPA’s rationale 

for the proposed changes and identifies issues on which EPA 

is particularly interested in receiving public comments.

Finally, the last (third) section of the preamble 

discusses the various statutory and executive order 

requirements applicable to this proposed rulemaking.

B. Background on This Action
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The 2009 final GHG reporting rule (2009 final rule) 

was signed by EPA Administrator Lisa Jackson on September 

22, 2009 and published in the Federal Register on October 

30, 2009 (74 FR 56260, October 30, 2009). The 2009 final 

rule, which became effective on December 29, 2009, includes

reporting of GHGs from various facilities and suppliers, 

consistent with the 2008 Consolidated Appropriations Act1. 

Subsequent notices were published in 2010 finalizing the 

requirements for subparts FF, II, and TT (75 FR 39736, July 

12, 2010), subpart W (75 FR 74458, November 30, 2010), 

subpart DD (75 FR 74774, December 1, 2010) and subpart RR 

(75 FR 75060, December 1, 2010). Subpart OO, which was 

promulgated as part of the 2009 final rule was also revised 

in 2010 (75 FR 79092, December 17, 2010). The source 

categories in 40 CFR part 98 cover approximately 85-90 

percent of U.S. GHG emissions through reporting by direct 

emitters, as well as suppliers of certain products that 

would result in GHG emission when released, used, or 

oxidized, and those that geologically sequester or 

otherwise inject carbon dioxide (CO2) underground. 

C. Legal Authority

 

1 Consolidated Appropriations Act, 2008, Public Law 110–161, 121 Stat. 

1844, 2128. 
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EPA is proposing these rule amendments under its 

existing CAA authority, specifically authorities provided 

in CAA section 114. 

As stated in the preamble to the 2009 final rule (74 

FR 56260) and the Response to Comments on the Proposed 

Rule, Volume 9, Legal Issues, CAA section 114 provides EPA 

broad authority to require the information proposed to be 

gathered by this rule because such data would inform and 

are relevant to EPA’s carrying out a wide variety of CAA 

provisions. As discussed in the preamble to the initial 

proposed rule (74 FR 16448, April 10, 2009), CAA section 

114(a)(1) authorizes the Administrator to require emissions 

sources, persons subject to the CAA, manufacturers of 

control or process equipment, or persons whom the 

Administrator believes may have necessary information to 

monitor and report emissions and provide such other 

information the Administrator requests for the purposes of 

carrying out any provision of the CAA. For further 

information about EPA’s legal authority, see the preambles 

to the 2009 proposed and final rules and EPA’s Response to 

Comments, Volume 9.

D. How would these amendments apply to 2012 reports?

EPA is planning to address the comments on these 

proposed amendments and publish the final amendments before 
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the end of 2011. Therefore, reporters would be expected to 

calculate emissions and other relevant data for the reports 

that are submitted in 2012 using 40 CFR part 98 as amended 

by this proposed action. We have determined that it is 

feasible for the sources to implement these changes for the 

2011 reporting year because the revisions primarily provide 

additional clarifications regarding the existing regulatory 

requirements, do not change the type of information that 

must be collected, and do not materially affect how 

emissions are calculated.

For example, EPA is proposing several technical 

clarifications and amendments to subpart A to address 

issues raised by reporters through questions to the hotline 

in late 2010 and early 2011, as well as those identified by 

EPA. For additional background information on the 

questions raised, please refer to the Technical Support 

Document for the 2011 Technical Corrections, Clarifying and 

Other Amendments to Certain Provisions of the Mandatory 

Reporting of Greenhouse Gases Rule proposal available in 

the docket to this rulemaking (EPA–HQ–OAR–2011-0147). For 

instance, we are proposing to change the threshold for 

underground coal mines to include only those that liberate 

36,500,000 actual cubic feet (acf) of methane (CH4) or more 

per year (equivalent to 100,000 acf of CH4 or more per day). 
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If the current regulatory threshold is retained, all mines 

that are currently subject to quarterly or more frequent 

sampling by Mine Safety and Health Administration (MSHA) 

would be required to report. Given that the original 

requirements were based on an incorrect assumption 

regarding the number of mines that MSHA samples, we are 

proposing a new threshold that will remove reporting 

requirements for approximately 500 mines (see relevant 

discussion in Section II.C of this preamble). We are also 

proposing provisions to clarify the time period during 

which information must be submitted to EPA and to clarify 

which information may be submitted through the electronic 

Greenhouse Gas Reporting Tool (e-GGRT) and which must be 

mailed to the Director of the Climate Change Division. We 

are also proposing a revision to the definition of 

“supplier” to be consistent with changes made to the rule 

during 2010. These changes impose no additional burden for 

facilities, and could be readily implemented for the 2011 

reporting year.

Many proposed revisions provide additional information 

to provide clarity on existing requirements. For example, 

in subpart W (Petroleum and Natural Gas Systems) we are 

providing additional clarity on the methodological options 

for calculating emissions from acid gas removal units and 
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emissions from well venting for liquids unloading. In 

subpart FF (Underground Coal Mines) we are proposing to 

clarify use of MSHA data to calculate emissions. While 

MSHA data may be used to collect data for volume and 

concentration of methane, it does not provide temperature 

and pressure data; therefore, we are proposing that 

measurements of temperature must be made at the same time 

as MSHA measurements for volume and concentration of 

methane and that for pressure, facilities must use either a 

measured value or the average annual barometric pressure 

from the nearest National Oceanic and Atmospheric 

Administration (NOAA) weather service station. This 

proposed clarification is consistent with clarifications 

EPA has issued in response to industry questions and does 

not change the rule requirements for facilities collecting 

data in 2011 because the requirements to collect 

temperature and pressure data were already clear in 40 CFR 

98.324(b)(1). In subpart RR, clarifying text is proposed 

in 40 CFR 98.443(d) to ensure that facilities account for 

CO2 entrained in produced fluids from oil or gas production 

wells or from other fluid wells that are not processed 

through a gas-liquid separator. Although we intended that 

CO2 content in all produced liquids would be determined (see 

Section II.B.4 of the preamble to the final subpart RR rule 
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(75 FR 75065, December 1, 2010)), the text in 40 CFR 

98.443(d) and associated equations were based on 

measurements that did not include fluids removed without 

the use of a separator, such as water removed for pressure 

relief. Therefore, the clarifying text does not change the 

rule requirements for facilities collecting data in 2011. 

Other proposed amendments provide additional clarity 

to the data reporting elements. For example, in subpart II 

(Industrial Wastewater Treatment) we are proposing to 

clarify what is meant by weekly sampling in 40 CFR 

98.353(c) and (d); the proposed revisions would clarify 

that reporters that sample only once per week must sample 

more than three days apart.

For some subparts, we are proposing amendments that 

would provide additional flexibility to the sources. Thus, 

while they would be free to use the amended regulations 

once final, facilities are not required to follow the 

amendments for 2011 data collection. For example, in 

subpart TT (Industrial Waste Landfills), facilities are 

provided an additional approach for determining the 

volatile solids concentration or the waste-specific 

degradable organic carbon (DOC) values for historically 

disposed streams. The July 12, 2010 final rule had no 

provisions by which waste streams that were not disposed of 
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in the first reporting year could be assessed. These waste 

streams were required to use the default DOC values, which 

have a high degree of uncertainty. The proposed revision 

allows owners and operators of industrial waste landfills 

to develop more accurate values for volatile solids 

concentration and site-specific DOC. With these proposed 

amendments, these facilities would have the option, but not 

be required, to use the newly proposed option for the 

reports submitted to EPA in 2012 and thereafter.

EPA is also proposing corrections to terms and 

definitions in certain equations. For example, in subpart 

TT (Industrial Waste Landfill), we are proposing to delete 

Equation TT-7 and amend Equation TT-8, which were 

incorrectly based on the assumption that the volatile 

solids concentration was expected to have units of mass of 

volatile solids per mass of (wet) waste. We are correcting 

these equations per Standard Method 2540G “Total, Fixed, 

and Volatile Solids in Solid and Semisolid Samples,” in 

which the volatile solids concentration is determined on a 

dry basis. These clarifications do not result in 

additional requirements; therefore, EPA has concluded that 

reporters subject to the subparts that would be amended by 

this proposed action can follow the rule, as amended, in 

submitting their reports in 2012 and thereafter.
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Finally, EPA is proposing other technical corrections 

(e.g., correcting cross references) that have no impact on 

facilities’ data collection efforts in 2011.

In summary, these amendments would not require any 

additional monitoring or information collection above what 

was already included in 40 CFR part 98. Therefore, we 

expect that sources can use the same information that they 

have been collecting under 40 CFR part 98 for each subpart 

to calculate and report GHG emissions for 2011 and submit

reports in 2012 under the amended subparts.

EPA generally seeks comment on the conclusion that it 

is appropriate to implement these amendments and 

incorporate the requirements in the data reported to EPA in 

2012. Further, we seek comment on whether there are 

specific subparts and specific proposed changes where 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 in 2011. We request that 

commenters provide specific examples of how the proposed 

implementation schedule would or would not work.

II. Technical Corrections and Other Amendments

Following promulgation of subparts A and OO on October 

30, 2009, subparts FF, II, and TT on July 12, 2010, subpart 

W on November 30, 2010, and subparts DD and RR on December 
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1, 2010, EPA has identified errors in the regulatory 

language that we are now proposing to correct. These 

errors were identified as a result of working with affected 

industries to implement these subparts. We have also 

identified certain rule provisions that should be amended 

to provide greater clarity. The amendments we are now 

proposing include the following types of changes:

 Changes to correct cross references within and between 

subparts. 

 Additional information to better or more fully 

understand compliance obligations in a specific 

provision, such as the reference to a standardized 

method that must be followed.

 Amendments to certain equations to better reflect 

actual operating conditions.

 Corrections to terms and definitions in certain 

equations.

 Corrections to data reporting requirements so that 

they more closely conform to the information used to 

perform emission calculations.

 Other amendments related to certain issues identified 

as a result of working with the affected sources 

during rule implementation and outreach.

We are seeking public comment only on the issues 

specifically identified in this notice for the identified 

subparts. We will not respond to any comments addressing 

other aspects of 40 CFR part 98.

A. Subpart A – General Provisions

EPA is proposing several technical clarifications and 

amendments to subpart A to address issues raised by 
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reporters and identified by EPA during the first year of 

implementation of the GHG Reporting Program (GHGRP), as 

well as to clarify terminology to ensure consistency across 

all subparts. In addition, a number of minor amendments 

are proposed to ensure that the General Provisions 

appropriately reflect the incorporation of the additional 

subparts into the GHGRP that were finalized in 2010.

Threshold for Electrical Transmission and Distribution 

Equipment Use. We are proposing to amend Table A-3 in the 

General Provisions to clarify applicability of the rule for 

Electrical Transmission and Distribution Equipment Use 

(subpart DD). The final subpart DD rule (December 1, 2010; 

75 FR 74774) specifies at §98.301 that reporting is 

required for an electric power system only if the total 

nameplate capacity of SF6 and PFC containing equipment 

located within the electric power system, when added to the 

total nameplate capacity of SF6 and PFC containing equipment 

that is not located within the electric power system but is 

under common ownership or control, exceeds 17,820 pounds. 

That section of the rule also specifies that a facility 

other than an electric power system that is subject to part 

98 because of emissions from another source category is 

only required to report emissions under subpart DD if the 

total nameplate capacity of SF6 and PFC containing equipment 
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located within that facility exceeds 17,820 pounds. The 

final rule, however, does not include the 17,820 pound 

capacity threshold in Table A-3. Some potential reporters 

have questioned if this omission means that all facilities 

with electric power equipment must submit an annual report, 

even if they are below the capacity threshold and are not 

otherwise required to report under any other provisions of 

part 98. This interpretation is clearly not the intent of 

the rule. The regulatory text in the final rule can and 

should be interpreted to mean that a facility is required 

to submit an annual report only if the capacity threshold 

is exceeded. This interpretation is clear from the 

preamble to the proposal (74 FR 16609) as well as the final 

rule (75 FR 74774)). However, we are proposing to revise 

Table A-3 to insert the capacity threshold language of 

§98.301 to make the rule clearer and less subject to 

misinterpretation. Because the test for whether a facility 

meets the numerical threshold differs depending on the type

of facility, we are including a reference to §98.301. 

Therefore, we are revising the Table A-3 entry for subpart 

DD to read as follows: Electrical transmission and 

distribution use at facilities where the total nameplate 

capacity of SF6 and PFC containing equipment exceeds 17,820 

pounds, as determined under §98.301 (subpart DD).
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Threshold for Underground Coal Mines. We are 

proposing to change the threshold for underground coal 

mines to include only those that have ventilation emissions 

of 36,500,000 acf of CH4 or more per year. For a full 

description of this proposed change, please refer to the 

relevant discussion under subpart FF of this action. 

Computation of Time. EPA is proposing to add a 

provision to 40 CFR 98.3(b) to allow information, including 

but not limited to, the annual GHG report and any 

subsequent re-submissions, the certificate of 

representation, and requests to use best available 

monitoring methods, to be submitted to EPA on the next 

business day in the event that a regulatory deadline falls 

on a weekend or a Federal holiday. The proposed language 

is consistent with a similar provision under the Acid Rain 

Program (40 CFR 72.11) and will provide all reasonable 

flexibilities for submitting data without compromising data 

quality. 

2012 Reporting Deadline. We are proposing a one-time 

extension of the 2012 reporting deadline for facilities and 

suppliers subject to source categories for which data 

collection began January 1, 2011 (referred to below as the 
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“new 2011 reporting year source categories”)2. A deadline 

extension from March 31, 2012 to September 28, 2012 would 

apply only to reporting of data elements under the 

following source categories: Electronics Manufacturing 

(subpart I), Fluorinated Gas Production (subpart L), 

Magnesium Production (subpart T), Petroleum and Natural Gas 

Systems (subpart W), Use of Electric Transmission and 

Distribution Equipment (subpart DD), Underground Coal Mines 

(subpart FF), Industrial Wastewater Treatment (subpart II), 

Imports and Exports of Equipment Pre–charged with 

Fluorinated GHGs or Containing Fluorinated GHGs in Closed–

cell Foams (subpart QQ), Geologic Sequestration of Carbon 

Dioxide (subpart RR), Manufacture of Electric Transmission 

and Distribution (subpart SS), Industrial Waste Landfills 

(subpart TT), and Injection of Carbon Dioxide (subpart UU).

All facilities and suppliers subject to the GHGRP, 

including facilities and suppliers that include the source 

categories listed above, would still be required to report 

their GHG information for all other subparts by March 31, 

2012. For example, a facility subject to report GHG 

 

2 There was a separate one-time extension of the reporting deadline for 

facilities and suppliers first required to report GHG information to 

EPA in 2011, for data collected during 2010 (76 FR 14812). The 

deadline extension in this proposal only applies to the reporting of 

information from those source categories for which data collection 

began in 2011 and for which data are to be reported in 2012. 
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information under subparts C, W, and PP would still be 

required to report GHG information for subparts C and PP by 

March 31, 2012, but would not be required to submit the 

required data reporting elements under subpart W until 

September 28, 2012.

We are proposing this change to the 2012 reporting 

deadline for the new 2011 reporting year source categories 

in order to allow sufficient time for development, and more 

importantly stakeholder testing, of the electronic-GHG 

Reporting Tool (e-GGRT). Stakeholder testing provides an 

opportunity for EPA to receive feedback from reporters and 

other interested stakeholders to enable EPA to test the 

effectiveness of the user interface of e-GGRT, correct any 

problems in advance of the reporting deadline, and 

ultimately ensure that the data received under the program 

are of the highest quality. Stakeholder testing of the 

electronic reporting tool for the new 2011 reporting year 

source categories is particularly important given the large 

number of reporters affected by these new categories (more 

than one quarter of all reporters are estimated to be 

required to report under these new subparts).

Based on the discussion above, we are seeking comment 

on whether a six-month extension of the 2012 reporting 

deadline for the new 2011 reporting year source categories 
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to September 28, 2012, would be appropriate. Facilities 

and suppliers subject to the rule would still be required 

to report all other required data reporting elements by 

March 31, 2012, but would not report information related to 

the new 2011 reporting year source categories until 

September 28, 2012.

Reporting on use of Best Available Monitoring Methods 

(BAMM). We are proposing to amend 40 CFR 98.3(c)(7) to 

remove the phrase “according to paragraph (d) of this 

section” thereby requiring all facilities and suppliers 

that use BAMM to provide a brief description of each “best 

available monitoring method” used, the parameter measured 

using the method, and the time period during which the 

“best available monitoring method” was used, if applicable. 

This reporting requirement was applicable to all facilities 

and suppliers using BAMM in the 2009 final rule. Most of 

the subparts promulgated in 2010 (subparts T, DD, FF, II, 

QQ, RR, SS, TT, and UU) directly referred back to the 

procedures in 40 CFR 98.3(d), and therefore the requirement 

to report basic information on BAMM is required. Through 

this amendment, we are clarifying that this basic 

information must be reported for all subparts, including 

subparts L (Fluorinated Gas Production) and W (Petroleum 

and Natural Gas Systems). This does not impact the 
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requirements of subpart I (Electronics Manufacturing), 

which already directly include this reporting requirement 

in the data reporting requirements of that subpart.

Definitions.

Blowdown vent stack. We are proposing to amend the 

definition of blowdown vent stack emissions to add the 

phrase “emissions from emergency events are not included.” 

EPA is proposing to make this change to promote better 

consistency with provisions in subpart C, which exempted 

emissions from emergency generators and equipment from 

being included in the GHG emissions calculations.

Supplier. Based on changes made to the rule during 

2010, the definition of supplier does not adequately 

represent the breadth of subparts covered under the rule. 

EPA is proposing to change the definition of supplier in 40 

CFR 98.6 so it specifically refers to those source 

categories listed in Table A-5 to subpart A of part 98, and 

is as described in the definition of the source category in 

the applicable subparts.

The proposed amendment is necessary because suppliers 

are currently defined as suppliers of fossil fuels and 

industrial GHGs. However, during 2010, EPA changed the 

definition of fossil fuels in a rulemaking (75 FR 79092) 

that could be wrongly interpreted to exclude some suppliers 
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that are clearly subject to the rule. In the 2009 final 

rule, fossil fuel was defined in 40 CFR 98.6 as meaning 

natural gas, petroleum, coal, or any form of solid, liquid, 

or gaseous fuel derived from such material, including for 

example, consumer products that are derived from such 

materials and are combusted. Using this definition, 

suppliers of fossil fuel-based products were covered by 

subparts MM and NN regardless of the product end-use. This 

interpretation is clear from the preamble to the 2009 final 

rule (74 FR 56260). However, in the subsequent rulemaking 

(75 FR 79092) EPA modified the definition of fossil fuel to 

read natural gas, petroleum, coal, or any form of solid, 

liquid, or gaseous fuel derived from such material, for 

purpose of creating useful heat. We were clear in the 

preamble to that final rule that the change was not 

intended to have any impact on coverage of GHGs under the 

GHGRP (see 75 FR 79104). Nevertheless, referring to only 

suppliers of fossil fuels could now wrongly be interpreted 

so as to exclude some coverage under subparts MM and NN. 

In addition, we added a new source category to the 

rule called Importers and Exporters of Fluorinated GHGs 

Contained in Pre–charged Equipment or Closed–cell Foams 

(subpart QQ, 75 FR 74774). Although one could interpret 

the existing definition to include suppliers of fluorinated 
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GHGs in bulk and in products, the proposed amendment 

further clarifies that suppliers include all the relevant 

source categories included in Table A-5.

We are also proposing a harmonizing change in 40 CFR 

98.1(a)(1) to remove the terms “fossil fuel” and 

“industrial greenhouse gas” before the term “supplier.” 

Submission of reports and other information to EPA. 

There were some questions raised in the 2009 final rule 

about where certain communications should be directed, 

whether electronically through the electronic greenhouse 

gas reporting tool (40 CFR 98.5) or through the mail with 

an attention to the Director of the Climate Change Division 

(40 CFR 98.9). 40 CFR 98.5 reads that each GHG report and 

certificate of representation for a facility or supplier 

must be submitted electronically in a format specified by 

the Administrator. 40 CFR 98.9 was intended to provide a 

mailing address for all other communications under the 

program, however, the regulatory language indicated that 

the mailing address was for all requests, notifications, 

and communications to the Administrator other than 

submittal of the annual GHG report. This raised a question 

as to whether the certificate of representation could be 

submitted through the mail.
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To address this potential source of confusion, we are 

clarifying that the annual GHG report, the certificate of 

representation, and all other requests, notifications, or 

communications that can be submitted through e-GGRT, must 

be submitted through e-GGRT. All other requests, 

notifications, or communications to the Administrator 

pursuant to this part shall be submitted through the mail 

to the Director of the Climate Change Division.

Other Technical Corrections. We are proposing to 

amend 40 CFR 98.2(d) and (e) to remove references to 

paragraphs 40 CFR 98.2(a)(4)(i) and (a)(4)(ii), 

respectively, which were removed when we finalized 

amendments during 2010 to consolidate the lists of source 

categories covered into tables. The correct references for 

both paragraphs should have been to 40 CFR 98.2(a)(4). In 

those same paragraphs we are clarifying that the 

applicability determination for importers should be 

assessed separately from the applicability determination 

for exporters. In other words, the emissions from the 

quantity of GHGs imported should be calculated for 

comparison to the 25,000 metric tons CO2e threshold and 

separately the quantity of GHGs exported should be 

calculated for comparison to the 25,000 metric tons CO2e. 

Based on questions received from reporters during the 2010 
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reporting year, it was unclear if the quantity of imports 

and exports should be assessed separately, added together, 

or the net imports minus exports calculated for comparison 

to the threshold. Finally, we are clarifying in Table A-5 

that coverage and the applicability determination for 

importers and exporters under subpart MM includes suppliers 

of natural gas liquids in addition to suppliers of 

petroleum products. The inclusion of natural gas liquids 

suppliers was clear in 40 CFR 98.2(a)(4) and subpart MM (40 

CFR 98.390), however, it was inadvertently omitted from 

Table A-5.

We are proposing to amend 40 CFR 98.2(i)(3) to add a 

date by which owners and operators must notify EPA that 

they no longer need to submit an annual GHG report because 

their operations have changed such that all applicable GHGemitting processes and operations cease to operate. 40 CFR 

98.2(i) provides three instances where facilities or 

suppliers no longer need to report to EPA. In instances 

where facilities or suppliers report less than 25,000 

metric tons carbon dioxide equivalent (mtCO2e) per year for 

5 years, or less than 15,000 mtCO2e for 3 years, they are 

required to notify EPA by March 31 of the following year 

that they are no longer to report for the year after the 

year in which these conditions have been met. Similarly, 
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the owner or operator is exempt from reporting in the years 

following the year in which cessation of such operations 

occurs, provided that the owner or operator submits a 

notification to the Administrator. However, the rule does 

not provide a date by which such notification be made. EPA 

is proposing that, similar to the requirements in 40 CFR 

98.2(i)(1) and (i)(2), owners or operators notify EPA by 

March 31 of the year following the reporting year in which 

such conditions have been met.

In 40 CFR 98.3(c)(10) and in the definition of United 

State parent company(s) in 40 CFR 98.6, we are proposing to 

replace the term “reporting entity” with the term “facility 

or supplier.” Reporting entity has not typically been used 

in the GHGRP and for consistency across the individual 

subparts of the rule, we are proposing to use the term 

“facility or supplier” which in turn clarifies that the 

obligation is on the owner or operator of any such facility 

or supplier. This is consistent with the preamble to the 

rule that amended 40 CFR part 98 with 40 CFR 98.3(c)(10), 

in which it is clear that “reporting entity” means 

“facility or supplier” (see, for example, 75 FR 57676).

To address several requests for clarification received 

on the recordkeeping requirements, we are proposing to 

clarify that the 3-year requirement for retention of 
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records starts from the date of submission of the annual 

GHG report for the reporting year in which the record was 

generated. This is as opposed to having the 3-year clock 

start on the day that the record was generated. The 

proposal, which is consistent with the Acid Rain Program, 

is in recognition of the fact that common practice is to 

retain all of the records for a single reporting year in a 

readily retrievable format, regardless if the record was 

generated on January 1st or December 31st of that reporting 

year. We are therefore proposing that the records be 

retained for 3 years from the data of submission of the 

applicable annual GHG report.

In 40 CFR 98.3(c)(5)(ii) we are proposing to replace

the use of the term “emissions” with “quantities” when 

referring to the information reported under industrial GHG 

suppliers. This is consistent with efforts throughout the 

GHG Reporting Program to clarify that information reported 

for supplier categories do not necessarily reflect 

emissions to the atmosphere, but rather “quantities” that 

may be released if all of the supply were combusted or 

released.

We are also proposing to correct an incorrect cross 

reference in 40 CFR 98.4(m)(4) from (m)(2)(iv)(A) to 

(m)(2)(v)(A). 
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B. Subpart W – Petroleum and Natural Gas Systems 

EPA is proposing several technical clarifications and 

amendments to subpart W to address issues raised during the 

first year of promulgation of the rule, as well as 

clarifications to specified provisions in the rule to 

ensure consistency across all subparts. In addition, 

several technical corrections are proposed to clarify 

provisions that were either erroneous or unclear to 

reporters.

Definitions. EPA is proposing to amend the definition 

for gas well in 40 CFR 98.238. The definition of gas well 

that was finalized in the rule, posed the question of 

whether or not gas wells that included any hydrocarbon 

condensate were also considered gas wells. The amendment 

clarifies the definition for gas well by stating that it 

includes gas wells that also produce natural gas including 

condensate.

Threshold Clarifications. EPA is broadly including 

clarification to several throughput thresholds in subpart W 

in response to clarifications sought by reporters subject 

to the rule. We are proposing to amend the threshold in 

the definition of the source category for the onshore 

natural gas processing industry segment in 40 CFR 

98.230(a)(2). This definition includes a threshold 
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provision, which states that all processing facilities that 

do not fractionate with a throughput per day of 25 million 

standard cubic feet (MMscf) or greater are covered under 

the rule. Without a clarification on how the 25 MMscf per 

day is to be determined, this provision resulted in 

confusion for reporters. Thus, we propose to amend the 

definition to state that the 25 MMscf per day throughput 

threshold is based on an annual average throughput that the 

reporter would use to determine if they are covered under 

this definition.

Similarly, we are proposing to clarify that the 

throughput threshold for glycol dehydrators (40 CFR 

98.233(e)(1) and (e)(2)) and onshore production storage 

tanks (40 CFR 98.233(j)(1),(j)(2),(j)(3) and (j)(4)) are 

also based on annual average throughput. These proposed 

amendments are described further in the Calculating 

Greenhouse Gas Emissions section below.

Greenhouse Gases to Report. We are proposing to 

clarify in 40 CFR 98.232(d) that the greenhouse gases to be 

reported under the natural gas processing industry segment 

include nitrous oxide (N2O) emissions and not just CO2 and 

CH4 emissions. This proposed amendment will make 40 CFR 

98.232(d) consistent with other provisions in the rule 

related to calculating GHG emissions from flare stacks. 
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The rule in 40 CFR 98.232(j) clearly states that you are 

required to report CO2, CH4 and N2O emissions for all flare 

stacks in all applicable industry segments and flare stacks 

are included to be reported in natural gas processing 

facilities (98.232(d)(6)). Finally, the calculation 

methodology for flare stack emissions includes the method 

for quantifying N2O emissions from these stacks (See section 

98.233(n)(8)). This proposed clarification avoids 

confusion as to whether N2O emissions, which typically 

result from flaring activities, would need to be reported 

under this industry segment. 

In addition, we are proposing to clarify in 40 CFR 

98.232(i) that CO2 and CH4 emissions are to be reported from 

the natural gas distribution industry segment. This 

clarification was necessary to ensure that the affected 

reporters are aware that these GHG’s are to be reported 

from this industry segment.

Calculating Greenhouse Gas Emissions. We are 

proposing several clarifications, corrections, and 

amendments throughout 40 CFR 98.233.

First, we are proposing to amend the definition for 

GHGi of Equation W-1 in 40 CFR 98.233(a) which is used for 

calculating GHG emissions from natural gas pneumatic device 

venting. In specific, the definition for the parameter GHGi
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in Equation W-1 was incorrect in that it inferred that it 

applied to facilities listed in 40 CFR 98.230(a)(3) through

(a)(8) when it actually only applies to the onshore 

production, natural gas transmission, and underground 

natural gas storage industry segments of subpart W. In 

addition, we are proposing to further amend the definition 

for parameter GHGi in Equation W-1 to clarify that GHGi

should equal 0.952 for CH4 and 1 X 10-3 for CO2 for 

facilities in 40 CFR 98.230(a)(4) and (a)(5). Previously,

this equation did not include any clarification of what the 

parameter GHGi would be for methane and carbon dioxide and 

as a result confusion arose as to what values should be 

used for the natural gas transmission and underground 

natural gas storage industry segments. Further, for both 

Equation W-1, and W-2, of 40 CFR 98.233, we are proposing 

to amend the definition for the parameter GHGi to include a 

reference to 40 CFR 98.233(u)(2)(i) to clarify how and at 

what frequency GHGi is to be determined for produced natural 

gas from the onshore production industry segment. We are 

proposing these amendments to Equations W-1 and W-2, to 

clarify specific aspects of the parameter GHGi and how it 

applies to applicable industry segments and how it is to be 

determined to address lack of clarity on these aspects of 

the equation.
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Next, we are proposing amendments to 40 CFR 98.233(d) 

to clarify how the four different methods are to be used 

for determining GHG emissions from acid gas removal (AGR) 

vents. In many cases a reporter may have both a continuous 

emissions monitoring system (CEMS) or a vent meter 

available at their facility, and when reviewing the methods 

in 40 CFR 98.233(d) in the final rule, the reporter would 

not be able to easily determine which method would apply 

when certain technologies are available. Thus, we are 

proposing to amend 40 CFR 98.233(d)(2), (3) and (4) to 

clarify that if a facility has a vent meter but no CEMs 

available for determining the CO2 emissions from AGR units 

then they would use Calculation Methodology 2 and if a 

facility has neither a CEMs in place or a vent meter in 

place, they have the option of using either Calculation 

Methodology 3 or 4 of 40 CFR 98.233(d). 

Next, we are proposing several amendments to 40 CFR 

98.233(e) for calculating emissions from dehydrator vents. 

First, we are proposing to include minor non-substantive 

revisions to the citations in 40 CFR 98.233(e) and 

(e)(1)(xi)(C). Next we are proposing to fix an erroneous 

citation in 40 CFR 98.233(e)(1)(xi) to correctly reference 

40 CFR 98.233(e)(1)(xi) instead of 40 CFR 98.233(e)(2)(xi). 

Finally, we are proposing to amend 40 CFR 98.233(e)(1) and 
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(e)(2) to clarify that the throughput threshold of 0.4 

million standard cubic feet per day is to be determined 

using an annual average daily throughput. We are proposing 

to include this particular amendment to clarify to 

reporters how this throughput threshold is to be 

determined.

We are proposing to amend engineering Equation W-8,

which is used to calculate emissions from well venting for 

liquids unloading. First, we are proposing to amend the 

first sentence in 40 CFR 98.233(f)(2) to state that 

Calculation Methodology 2 is to be used to calculate the 

total emissions for well venting for liquids unloading 

whereas the rule previously stated that Calculation 

Methodology 2 was to be used to calculate emissions from 

each well venting for liquids unloading event. This 

clarification is in line with the equation in that the 

emissions from well venting for liquids unloading that have 

occurred in the year of data collection are to be summed 

and an annual value would result for all wells, as opposed 

to each well separately.

We are proposing to amend Equation W-13 to include 

corrections and clarifications to the parameter 

definitions. First we are proposing to correct parameter 

Ea,n, EFwo, and Vf to state that they represent standard 
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conditions and not actual conditions. Secondly, we are 

proposing a correction to the emission factor (EF) value in 

EFwo that was based on actual conditions and should have 

been in standard conditions. This proposed change would 

result in the emissions factor value adjustment EFwo = 2,454 

to 3,114 standard cubic feet per workover. Next, we are 

proposing to revise the definition of Ea,n to Es,n to clarify 

that the annual natural gas emissions calculated are from a 

single gas well venting event and at standard conditions. 

Previously the rule stated that the Ea,n (now referred to as 

the Esn), represents emissions from gas well venting, which 

resulted in confusion as to whether this equation was to 

apply for gas well venting in previous years or to more 

than one gas well venting during the year of data 

collection. Finally, we are proposing to revise 40 CFR 

98.233(h)(1). The rule states that the resulting emissions 

from Equation W-13 are to be converted into standard 

conditions. However, this should not be the case because 

Equation W-13 would already result in emissions in standard 

condition. As a result, we are proposing to include 

language in 40 CFR 98.233(h)(1) that would reference 

paragraphs in subpart W that will convert the emissions 

from Equation W-13 into GHG volumetric and mass emissions.
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In Equation W-14 used for determining blowdown vent 

stacks emissions, we are proposing to clarify that the 

parameter Vv is the actual physical volume of the blowdown 

equipment and not the gas volume. It was always EPA’s 

intent that the physical volume between isolation valves be 

considered against the 50 standard cubic feet threshold for 

blowdown vent stacks3. EPA is also proposing to clarify the 

reporting requirements for blowdown vent stacks by stating 

that emissions are calculated per unique volume type and 

not equipment type. Equation W-14 in 40 CFR 98.233(i) 

determines emissions on a unique volume basis; therefore, 

emissions should be reported as such. 

In addition, we are proposing to make amendments to 

equations and parameters dependant on CH4 and CO2

composition by making clarifications to the parameter, GHGs 

used to convert whole gas, total hydrocarbon, or methane 

emissions into volumetric or mass CO2, and CH4 emissions in 

Equations W-1, W-2, W-30, and W-31.

In 40 CFR 98.233(j) we are proposing to clarify that 

the throughput threshold referenced in Calculation 

 

3

Please see Response to Comment number EPA-HQ-OAR-2009-0923-1018-27 in 

Mandatory Greenhouse Gas Reporting Rule Subpart W – Petroleum and 

Natural Gas: EPA's Response to Public Comments, Volume 8. This 

document can be found at 

http://www.epa.gov/climatechange/emissions/downloads10/SubpartW_RTC_part2.pdf
41 of 157

Methodologies 1-4 is based on an annual average daily 

throughput of oil, whereas the rule gave no clarification 

as to what basis the oil throughput was based on, resulting

in many questions from affected owners and operators on how 

this throughput threshold was to be determined. We are 

also proposing to correct an erroneous citation in 40 CFR 

98.234(j)(1)(vii) and 40 CFR 98.233(j)(2), which referenced 

citations that do not exist. In Equation W-15, where 

volumetric GHG emissions are determined from onshore 

production storage tanks, we are proposing to revise the 

equation by including a multiplier so the resulting 

emissions would be in the correct units. In addition, we 

are proposing to amend the definition for the EFi and count 

parameters to clarify that these parameters must be used 

for both gas-liquid separators with throughput less than 10 

barrels per day and wells with throughput less than 10 

barrels per day sending liquids straight to a tank without 

going through any separator. The definition to equation W15 in the 2010 final rule could have been misinterpreted to 

apply only to instances where there was a separator at the 

well. The proposed clarification makes the definitions to 

Equation W-15 consistent with the introduction to 40 CFR 

98.233(j)(5). 
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In Equation W-16, we are proposing to amend the 

definition for the parameter En by first correcting the 

citation that erroneously included 40 CFR 98.233(j)(3),

which should not have been included because it references a 

methodology that is specific for wells that flow directly 

to storage tanks bypassing a wellhead separator. In 

addition, we are proposing to amend the definition for En by 

including a conversion factor that would result in the 

emissions being determined on a yearly basis as opposed to 

an hourly basis. In addition, we are proposing to delete 

the parameter Et in the equation as it is being accounted 

for in the revised equation and is no longer necessary.

In 40 CFR 98.233(k) we are proposing the inclusion of 

minor revisions to 40 CFR 98.233(k)(2) and (k)(4) to 

clarify that emissions to be calculated are annual 

emissions. In addition, we are proposing to revise 40 CFR 

98.233(k)(4)(i) by removing the reference to 40 CFR 

98.233(j)(1) as this reference was incorrectly directed to 

the onshore production storage tank calculations where 

owners and operators could use a software program to 

determine flashing emissions which are not covered under 

the transmission storage tanks calculations. Finally, we 

are also proposing to revise 40 CFR 98.233(k)(4)(ii) by 

clarifying that the flare stack calculations are to be used 
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for emissions that are sent to a flare and not from a 

flare. The latter resulted in confusion from reporters as 

to what emissions they would be capturing by using the 

flare calculation methodologies.

We are proposing to amend the provisions in 40 CFR 

98.233(z) for determining combustion emissions from both 

the onshore petroleum and natural gas production and 

natural gas distribution industry segments. First, we are 

proposing to include an engineering equation to be used for 

determining CH4 emissions resulting from combustion of a 

fuel. The rule did not include a specific equation or 

methodology for determining the methane emissions from 

combustion of fuel, however, the provisions stated that 

both CH4 and CO2 emissions were to be calculated from the 

combustion of fuel. In addition, we are proposing to amend 

the equation used to calculate CO2 emissions by including a 

combustion efficiency parameter.

We are proposing to clarify that 40 CFR 98.233(z)(6), 

calculation of N2O emissions from stationary combustion, 

applies only to units combusting field gas or process vent 

gas. Units combusting other fuels listed in Table C-1 

would estimate N2O (and CH4) emissions using the appropriate 

Tier 1 equations in subpart C. We have reorganized section 

98.233(z)(6) to incorporate this proposed amendment. We 
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are proposing to amend Equation W-40 to account for an 

incorrect exponent on the conversion factor from kilograms 

to metric tons. Without making this change to the rule, 

the emissions would have resulted in an incorrect 

calculation of emissions.

We are also proposing to revise equation W-41 to 

insert missing variables a and b from the equation. 

Without including the missing variables, equation 41 would 

lack clarity and be unusable.

Emission Factor Tables. We are proposing to revise 

the emission factors for high bleed, low bleed, and 

intermittent bleed pneumatic devices to correct for an 

error where the original emission factors were on a CH4

basis and should have been adjusted to account for the 

total hydrocarbon basis as noted in equation. These 

proposed revisions would apply to Table W-3 and Table W-4.

Other Technical Corrections. EPA is proposing to 

clarify in 40 CFR 98.236(c)(6)(ii)(B) that only the number 

of workovers with hydraulic fracturing that vent gas to the 

atmosphere or flare gas needs to be reported. The current 

rule language could suggest you must report on the total 

number of workovers per year, including those that don’t 

involve hydraulic fracture and those that do not vent gas 

to the atmosphere.
45 of 157

It came to EPA’s attention that the density parameter 

in Equation W-36 was calculated incorrectly. EPA proposes 

correcting these parameters to 0.0520 kg/ft3 for CO2 and 

N2O, and 0.0190 kilograms per square foot (kg/ft3) for CH4

at 68°F and 14.7 pounds per square inch absolute (psia). 

C. Subpart FF — Underground Coal Mines

Proposed changes to Subpart A. We are proposing to 

amend Table A-3 to subpart A of part 98. According to 

Table A-3 to subpart A of part 98, all underground coal 

mines that are subject to quarterly or more frequent 

sampling by MSHA of ventilation systems (subpart FF) must 

report, regardless of size.

This threshold was based on EPA’s understanding that 

quarterly sampling by MSHA was only done at the largest, 

gassiest mines, defined as those emitting more than 100,000 

actual cubic feet (acf) CH4 per day. For example, the 

proposal preamble states, 

“We propose that all active underground coal mines for 

which CH4 from the ventilation system is sampled 

quarterly by MSHA (or on a more frequent basis), are 

required to report under this rule. MSHA conducts 

quarterly testing of CH4 concentration and flow at 

mines emitting more than 100,000 cf CH4 per day. We 

selected this threshold because subjecting underground 
46 of 157

mine operators to a new emissions-based threshold is 

unnecessarily burdensome, as many of these mines are 

already subject to MSHA regulations. The MSHA 

threshold for reporting of 100,000 cf CH4 per day 

covers approximately 94 percent of the CH4 emitted from 

underground coal mine ventilation systems and about 86 

percent of total emissions from underground mining 

(including stationary fuel combustion emissions at 

mine sites, as shown in Table FF–1 of this preamble).” 

In the proposal preamble, we estimated that this 

threshold covers only about 128 of the estimated 612 active 

underground mines in the United States (74 FR 16553). 

Although it was not evident in reviewing the public 

comments received on the proposed subpart FF, since 

finalization we have learned that the threshold was based 

on an incorrect understanding that MSHA only samples 

quarterly at mines liberating 100,000 acf of CH4 or more 

day.

If the current regulatory threshold is retained, all 

mines would be required to report. This would add nearly 

500 mines to the number previously expected to report, but 

these 500 mines would represent only another 14 percent of 

the total GHG emissions from underground coal mines. EPA 
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is reviewing ways to address this and ensure that the 

threshold in the rule reflects EPA’s longstanding intent to 

capture the gassiest mines that are responsible for the 

majority of emissions from underground coal mines in the 

United States.

We are proposing to amend the language so that mines 

liberating 36,500,000 acf of CH4 or more per year from their 

ventilation systems are subject to the rule. This capacity 

threshold (equivalent to an average of 100,000 acf of CH4 or 

more per day) may be more easily identifiable for the coal 

industry, is consistent with our original intent in terms 

of coverage, and removes reporting requirement for the 

approximately 500 mines.

We considered but are not proposing, a threshold of 

15,000 metric tons CO2e per year. This threshold would also 

be consistent with our original intent in terms of coverage 

and it would remove the reporting requirement for the 

approximately 500 mines. However, it would be less 

familiar to industry than the roughly equivalent threshold 

of 36,500,000 acf of CH4 or more per year.

Equations FF-1 and FF-3. We are proposing the 

following technical amendments to Equations FF-1 and FF-3 

in 40 CFR 98.323.
48 of 157

We propose to amend 40 CFR 98.324(a) and 98.324(b) to 

specify that variables “V,” “MCF,” “C,” “T,” and “P” are 

not “daily” rates. We are also proposing to edit the units 

of “V” to cfm from scfm and to revise the units for “C” to 

read “%” to allow for the use of “C” on a dry basis. 

Sampling for pressure. We propose to amend FF-1 to 

allow facilities to use the annual average barometric 

pressure from the nearest NOAA weather service station as a 

default to measuring ventilation system pressure. 

According to MSHA, approved equipment to conduct pressure 

measurements is not readily available in the United States.

Sampling for moisture content. We received numerous 

questions regarding the placement of timing of sampling for 

moisture content. We are proposing to add a paragraph (d) 

to 40 CFR 98.324 to specify that when flow and 

concentration are measured on different bases, moisture 

content is measured at the location of the flow meter at 

least weekly if using CEMS, and at the location and time of

the grab sample, if using grab samples.

Additionally, we received numerous inquiries about how 

reporters are to measure for moisture content, and asking 

whether measurements were really necessary because no 

moisture content measurement requirements are in 40 CFR 

98.324. To clarify how and when reporters are to measure 
49 of 157

for moisture content, we are proposing to amend 40 CFR 

98.323 and 98.324 to include reference to calibration and 

documentation of procedures for moisture content monitors. 

These proposed amendments clarify that the moisture content 

is to be based on measurement values and not assumed 

moisture content values. In related amendments, we are 

proposing to amend 40 CFR 98.326(o) to clarify the 

reporting requirements for temperature, pressure, and

moisture content measurements. Together, the proposed 

amendments to Equations FF–1 and FF-3 and 40 CFR 98.324 

would clarify that moisture content need only be determined 

when the concentration and flow measurements are made on 

different basis (one wet and one dry) and that, if needed, 

the moisture content must be measured.

MSHA data. We received numerous comments on the use 

of MSHA data to calculate emissions. MSHA samples volume 

and concentration of methane, but does not collect data on 

temperature, pressure, and moisture content, which are 

required inputs for the equations in this subpart. To 

allow facilities to use MSHA data, we propose to amend 40 

CFR 98.324(b)(2) to clarify that temperature and moisture 

content must be sampled at the same time and location as 

the MSHA samples, and that for pressure, facilities must 

use either a measured value or the average annual 
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barometric pressure from the nearest NOAA weather service 

station.

Monitoring equipment. We propose to amend 40 CFR 

98.324(g) to include the use of infrared and flame 

ionization analyzers with the provision that they are 

calibrated annually using measurements made by gas 

chromatography methods. The infrared and flame ionization 

analyzers are frequently used by the coal mining industry 

and they are often more familiar with their calibration and 

operation.

We propose to amend 40 CFR 98.324(f) for consistency 

with the types of monitoring equipment required. We 

propose to replace references to “fuel flow meters” with 

“flow meters,” because the gas that is measured may or may 

not be used as a fuel. We also propose to delete 

references to “heating value monitors,” and “sour gas flow 

meters” because these monitors and meters are not required. 

D. Subpart II – Industrial Wastewater Treatment

We are proposing clarifying amendments and technical 

corrections to subpart II to address questions EPA has 

received about the rule’s requirements, as well as to 

clarify terminology.
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We are proposing to amend 40 CFR 98.352(d) to replace 

the term “landfill gas” with “biogas” to correct a 

typographical error. 

We are proposing to amend the definitions of the terms 

for “Tm” and “Pm” in Equation II-4 to refer to “average 

temperature” and “average pressure” to clarify how 

reporters should use the multiple temperature and pressure 

measurements that they may make during a measurement 

period. We are also proposing to amend these definitions 

to clarify how the calculation should be adjusted if the 

flow rate meter automatically corrects for temperature and 

pressure.

We are proposing to amend 40 CFR 98.353(c)(2)(ii), 40 

CFR 98.353(c)(2)(iii)(A) and (B), and 40 CFR 98.354(c) and 

(d) to replace “once each calendar week, with at least 

three days between measurements” with “at least once each 

calendar week; if only one measurement is made each 

calendar week, there must be at least three days between 

measurements,” to clarify what is meant by weekly sampling.

We are proposing to amend Equation II-6 of 40 CFR 

98.353 to correct an error in the placement of brackets and 

parentheses. This amendment will eliminate the possibility 

that the equation will return incorrect quantities of 

methane emissions. We are also proposing to amend the 
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units in the definition of CH4En under Equation II-6 to 

clarify that the annual quantity should be reported in 

“metric tons” not “metric tons/yr.”

We are proposing to amend 40 CFR 98.353(c) to reorder 

the text to clarify that continuous gas flow monitoring is 

required for each anaerobic sludge digester, anaerobic 

reactor, or anaerobic lagoon from which some biogas is 

recovered; and to clarify that the continuous gas flow 

measurements must be used to determine cumulative gas 

production each week. We are also proposing to amend 40 

CFR 98.353(c)(1) to replace the term “content” with the 

term “quantity” to clarify that fully integrated systems 

report CH4 quantity which accounts for both CH4

concentration and biogas flow.

We are proposing to amend 40 CFR 98.354(f) by dividing 

it into subparagraphs and by deleting an incorrect cross 

reference, to clarify the monitoring requirements for 

anaerobic sludge digester, anaerobic reactor, or anaerobic 

lagoon from which some biogas is recovered. 

We are proposing to amend 40 CFR 98.356(a) by 

replacing the term ”explain” with “indicate” to provide 

guidance to reporters about the information they should 

include in the description or diagram of their wastewater 

treatment system. We are also proposing to replace the 
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term “all anaerobic lagoons” with “each anaerobic lagoon” 

to clarify that reporters should provide the average depth 

of each lagoon, not the average of all lagoons.

We are proposing to amend 40 CFR 98.356(b)(3) and (4) 

to clarify that the values for “Bo” and “MCF,” that are 

used as inputs to Equation II-1 or II-2, are to be taken 

from Table II-1. We are also proposing to amend 40 CFR 

98.356(d)(2) by replacing the text “Cumulative volumetric 

biogas flow for each week” with “Total weekly volumetric 

biogas flow for each week (up to 52 weeks/year)” to clarify 

that reporters should provide the total gas recovered for 

the week, for up to 52 weeks per year.

We are proposing to amend subpart II (Industrial 

Wastewater Treatment) (40 CFR 98.350 to 40 CFR 98.358) in 

multiple places, replacing the term “anaerobic digester” 

with “anaerobic sludge digester” to clarify the test refers 

to the anaerobic process defined in 40 CFR 98.350(b)(2); 

and to replace the term “gas” with “biogas” to clarify the 

gas referred to is the biogas defined in 40 CFR 98.358.

E. Subpart OO — Suppliers of Industrial Greenhouse Gases

We are proposing to amend subpart OO to require that 

the data currently reported under 40 CFR 98.416(a)(8) and 

(9) be kept as a record rather than reported. We are also 
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proposing to make a corresponding revision to 40 CFR 

98.416(a)(10). 

Section 98.416(a)(8) requires that fluorinated GHG and 

nitrous oxide production facilities report the total mass 

in metric tons of each reactant fed into the F-GHG or 

nitrous oxide production process, by process; and section 

98.416(a)(9) requires that fluorinated GHG and nitrous 

oxide production facilities report the total mass in metric 

tons of the reactants, by-products, and other wastes 

permanently removed from the F-GHG or nitrous oxide 

production process, by process. Although these data 

elements do not, in themselves, represent additions to or 

subtractions from the U.S. supply of industrial GHGs, we 

required reporting of these data elements in the October 

30, 2009, Mandatory GHG Reporting Rule to facilitate 

verification of production levels through a material 

balance. (For more discussion of that decision, see page 

26 of the Mandatory Greenhouse Gas Reporting Rule: EPA's 

Response to Public Comments, Volume No. 40, Subpart OO—

Suppliers of Industrial Greenhouse Gases.) 

We are now proposing to require recordkeeping, rather 

than reporting, of these data elements. After additional 

consideration, we have concluded that these data elements, 

by themselves, have somewhat limited usefulness for 
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verifying production levels because the relationship 

between the masses of the reactants fed into the process, 

the mass of the nitrous oxide or fluorinated GHG product, 

and the mass of the reactants, by-products, and other 

wastes permanently removed from the process can vary. For 

example, if catalysts are added to the process and 

subsequently removed from it, the sum of the masses of the 

product and the materials removed from the process may 

exceed the sum of the masses of the reactants fed into the 

process. On the other hand, if by-products or other 

materials are emitted from the process, e.g., through 

fugitive emissions, the sum of the masses of the reactants 

may exceed the sum of the masses of the product and the 

materials removed from the process. Finally, the accuracies 

and precisions of the various instruments used to measure 

the masses of the reactants fed into the process, the mass 

of the nitrous oxide or fluorinated GHG produced, and the 

masses of the materials permanently removed from the 

process may all vary, further complicating comparisons 

among these quantities. Retention of these data as records 

would permit on-site verification of production as part of 

the audit process, which would have the benefit of 

permitting consideration of other production process 

information (e.g., the use of catalysts) in making 
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comparisons among the inputs and outputs of the production 

process. We estimate that approximately 20 facilities 

produce fluorinated GHGs or nitrous oxide in the U.S., 

making on-site verification a practicable option for 

subpart OO. 

We are also proposing to revise §98.416(a)(10) by 

removing the introductory qualifier. In its entirety, the 

provision currently reads, “For transformation processes 

that do not produce an F-GHG or nitrous oxide, mass in 

metric tons of any fluorinated GHG or nitrous oxide fed 

into the transformation process, by process.” The phrase 

“for transformation processes that do not produce an F-GHG 

or nitrous oxide” was intended to prevent double-reporting 

between this provision and §98.416(a)(8), which requires 

reporting of the mass of each reactant fed into the 

fluorinated GHG or nitrous oxide production process. (In 

the case where one fluorinated GHG was transformed into 

another, the first fluorinated GHG would be one of the 

reactants fed into the process and would therefore be 

reported under (a)(8).) With the proposed removal of 

§98.416 (a)(8), the introductory qualifier in 

§98.416(a)(10) must be removed to ensure that the 

quantities of fluorinated GHGs fed into all transformation 
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processes, including transformation processes that produce 

other fluorinated GHGs, will be reported under subpart OO4.

F. Subpart RR – Geologic Sequestration of Carbon Dioxide. 

We are proposing clarifying amendments and technical 

corrections to subpart RR to correct known errors. 

Accounting for CO2 Entrained in Produced Water. We are

proposing to clarify 40 CFR 98.443(d) to ensure that CO2

entrained in produced water that is not processed through a 

gas-liquid separator is accounted for in the mass balance 

equation. We intended that CO2 content in all produced 

liquids would be determined5, and assumed that all produced 

liquids would be processed through a gas-liquid separator. 

The text in 40 CFR 98.443(d), and the associated equations 

(Equations RR-7, RR-8, and RR-9) are based on measurements 

made at a separator to calculate the amount of CO2 in 

produced fluids. However, EPA has recognized that in some 

situations, including water removed for pressure relief or 

reservoir maintenance, fluids may be removed from the 

subsurface without being processed through a separator. 

The current text and equations would not account for CO2 in 

water that is withdrawn from the subsurface and reinjected 

 

4 Note that if a fluorinated GHG is produced and transformed at the same 

facility, neither its production nor its transformation are required to 

be reported under subpart OO.

5 See Section II.B.4 of preamble to the final Subpart RR rule (75 FR

75065, December 1, 2010).
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or disposed without going through a separator.

To address this issue, we propose adding a new 

sentence to 40 CFR 98.443(d) to specifically account for 

any CO2 in fluids that are produced and not processed 

through a separator. We also propose adding a new sentence 

to 40 CFR 98.443(d)(3) to clarify that the reporter must 

include additional information regarding the measurement 

methods used to determine the concentration of CO2 in 

fluids, and a discussion of how the amount of produced CO2

would be determined, in the monitoring, reporting and 

verification (MRV) plan. In the MRV plan, the reporter 

would describe the disposition of the produced water 

(reinjected into another zone, reused, or otherwise 

disposed) and provide justification for determining whether 

the CO2 entrained in the water is sequestered. The MRV plan 

would also describe considerations the reporter intends to 

use to calculate CO2 from produced water for the mass 

balance equation.

CO2 Emissions from Equipment Leaks and Vented Emissions 

of CO2. We are proposing to revise the term “CO2 equipment 

leakage and vented CO2 emissions” throughout subpart RR with 

the term “CO2 emissions from equipment leaks and vented 

emissions of CO2.” This change is proposed to ensure 

consistency with the terminology that is used in 40 CFR 
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part 98 subpart W and to more accurately describe the 

equipment between flow meters and wellheads for which 

monitoring requirements are specified in subpart RR. 

Specifically, we are proposing the following changes:

 At 40 CFR 98.442(e) and 98.442(f), revise the term 

“Mass of CO2 equipment leakage and vented CO2

emissions” to read “Mass of CO2 emissions from 

equipment leaks and vented emissions of CO2.”

 In Equations RR-11 and RR-12 at 40 CFR 98.443, revise 

the term “Total annual CO2 mass emitted (metric tons) 

as equipment leakage or vented emissions” to read 

“Total annual CO2 mass emitted (metric tons) from 

equipment leaks and vented emissions of CO2.”

 At 40 CFR 98.444(d), revise the heading “CO2 equipment 

leakage and vented CO2 emissions” to read “CO2

emissions from equipment leaks and vented emissions of 

CO2.”

 At 40 CFR 98.445(e), revise the term “CO2 equipment 

leakage or vented CO2 emissions to read “CO2 emissions 

from equipment leaks and vented emissions of CO2.”

 At the introductory text of 40 CFR 98.446(f)(3), 

revise the term “CO2 equipment leakage and vented CO2

emissions” to read “CO2 emissions from equipment leaks 

and vented emissions of CO2.”

 At 40 CFR 98.446(f)(3)(i) and 98.446(f)(3)(ii), revise 

the term “mass of CO2 emitted (in metric tons) annually 

as equipment leakage or vented emissions” to read 

“mass of CO2 emitted (in metric tons) annually from 

equipment leaks and vented emissions of CO2.”

 At 40 CFR 98.447(a)(5) and 98.447(a)(6), revise the 

term “CO2 emitted as equipment leakage or vented 

emissions” to read “CO2 emitted from equipment leaks 

and vented emissions of CO2.”

 At 40 CFR 98.448(a)(5), revise the term 

“considerations for calculating equipment leakage and 

vented emissions” to read “considerations for 

calculating CO2 emissions from equipment leaks and 

vented emissions of CO2.”
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Other Technical Corrections. We are proposing to 

amend a cross reference in the introductory language of 40 

CFR 98.446(a)(2) and 40 CFR 98.446(a)(3). The incorrect 

references refer the reader to 40 CFR 98.446(a)(5), but 

should refer the reader 40 CFR 98.446(a)(4). We are also 

proposing to amend a cross reference at 40 CFR 

98.446(f)(1)(vii). The incorrect reference refers the 

reader to 40 CFR 98.446(f)(1)(i), but should refer the 

reader to 40 CFR 98.446(f)(1)(ii).

We are proposing to revise the data reporting element 

at 40 CFR 98.446(e) and the introductory text at 40 CFR 

98.446(f). As currently written, it is ambiguous when 

reporters would report total amount sequestered. We are 

proposing that the revised data reporting element at 40 

98.446(e) read as follows: “Report the date that you began 

collecting data for calculating total amount sequestered 

according to §98.448(a)(7) of this subpart”. We are 

proposing that the revised introductory text at 40 CFR 

98.446(f) read as follows: “Report the following. If the 

date specified in paragraph (e) of this section is during 

the reporting year for this annual report, report the 

following starting on the date specified in paragraph (e) 

of this section.”
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We are proposing to revise the heading of 40 CFR 

98.448(e) to correct a typographical error. The text of 40 

CFR 98.448(e) refers to requirements for revised MRV plans, 

but the heading is incorrectly labeled as “Final MRV plan.” 

We propose to revise the heading to read “Revised MRV 

plan.” 

We are proposing to revise the definition of “CO2

received” at 40 CFR 98.449 to correct a typographical error 

by adding the word “means” after the CO2 received defined 

term. The definition would read “CO2 received means the CO2

stream that you receive to be injected for the first time 

into a well on your facility that is covered by this 

subpart. CO2 received includes, but is not limited to, a 

CO2 stream from a production process unit inside your 

facility and a CO2 stream that was injected into a well on 

another facility, removed from a discontinued enhanced oil 

or natural gas or other production well, and transferred to 

your facility.”

G. Subpart TT — Industrial Waste Landfills

Numerous clarifying amendments and technical 

corrections are proposed to subpart TT to address questions 

EPA has received about the rule’s requirements and to 

correct known errors. Technical amendments to the rule are 

also proposed to address some additional questions. These 
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more substantive technical amendments are discussed first, 

and then the clarifying amendments are presented.

Determining Waste-specific DOC values for Closed 

Landfills. We are proposing to amend 40 CFR 98.464 by 

adding a new paragraph (c) to provide methodologies for 

closed landfills or active landfills that have stopped 

accepting certain types of wastes to determine the volatile 

solids concentration (for exemption purposes under 40 CFR 

98.460(c)(2)(xii)) or to determine the waste-specific DOC 

values for historically disposed waste streams. The 

proposed provisions would allow landfills to identify waste 

streams similar to those that had been historically placed 

in the landfill, measure the volatile solids concentration 

of these “similar” waste streams, and use those measured 

values to assess the applicability of the exemption under 

40 CFR 98.460(c)(2)(xii) or to determine the average DOC 

value for the historical waste streams. The proposed 

provisions also allow use of process knowledge to determine 

the volatile solids concentration and, if needed, to 

calculate the corresponding DOC value if a similar waste 

stream cannot be identified.

This provision is being proposed to allow industrial 

waste landfill owners and operators a means by which to 

develop volatile solids concentration and site-specific DOC 
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values for historically disposed waste streams. The sitespecific DOC values will in turn improve the accuracy of 

the modeled methane generation. The July 12, 2010, final 

rule had no provisions by which waste streams that were not 

disposed of in the landfill during the first reporting year 

could be assessed. These waste streams would be required 

to use the default DOC values, which have a higher degree 

of uncertainty. Facilities may still elect to use the 

default DOC values, but proposed amendments provide 

methodologies for developing site-specific DOC values for 

these “historically-disposed” waste streams.

We are also proposing to amend 40 CFR 98.467 to 

clarify that records must be retained for the volatile 

solids concentration determinations, including 

determinations using process knowledge.

Equations for Determining Volatile Solids and DOC 

Values. We are proposing to delete Equation TT-7 and amend 

Equation TT-8 to 40 CFR 98.464 to correct inadvertent 

errors in these equations. These equations as presented in 

the July 12, 2010, final rule were incorrect because the 

volatile solids concentration was expected to have units of 

mass of volatile solids per mass of (wet) waste. However, 

per Standard Method 2540G “Total, Fixed, and Volatile 

Solids in Solid and Semisolid Samples,” the volatile solids 
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concentration is determined on a dry basis (milligram (mg) 

volatile solids per mg dried solids). As such, Standard 

Method 2540G provides the volatile solids concentration in 

the appropriate units needed for 40 CFR 98.464(b)(3), and 

Equation TT-7 in the final rule can be deleted. 

Additionally, we propose to amend 40 CFR 98.464(b)(4) to 

correct the errors in Equation TT-8 (which is proposed to 

be renumbered as Equation TT-7) and to clarify the units of 

the variables used in the equation.

We are revising the variable “F” in Equation TT-1 and 

new Equation TT-7 (which was Equation TT-8) to correct the 

measured CH4 concentration for zero percent oxygen. We are 

proposing to change “Fx” to be “F” in Equation TT-1 because 

this parameter should be a fixed value for a given 

reporting year and revising the definition of “F” to be 

“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.” to clarify that, 

if a measured value of CH4 concentration is used it should 

be based on measurements made during the reporting year and 

the volume fraction should be adjusted to 0 percent oxygen 

for use in Equation TT-1.
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In addition, we are proposing to add a new paragraph

(g) in 40 CFR 98.464 and a new Equation TT-8 to provide 

guidance on how to correct the measured CH4 concentration 

for zero percent oxygen in order to arrive at an 

appropriate value for F in the case of air infiltration 

into the landfill gas at the monitoring location. 

Provisions for Actively Aerated Landfills and Other 

Amendments to Conform with Amendments to subpart HH. 

Similar to amendments that were made to subpart HH 

(Municipal Solid Waste Landfills), we propose to amend the 

definition of the methane correction factor (MCF) to allow 

landfills with active aeration units to use an MCF value 

other than the default value of 1. For landfills with 

active aeration units, a site-specific MCF can be developed 

based on the amount of aeration and the fraction of the 

landfill that is actively aerated. Owners and operators of 

landfills with active aeration can use the default MCF 

factor of 1 or they may elect to develop a site-specific 

MCF value. The owner or operator of the industrial waste 

landfill must document the basis for the alternative MCF 

value; in no cases can an MCF value less than 0.5 be used. 

These amendments are being proposed because the default MCF 

value of 1 is expected to overestimate the modeled methane 

generation at a facility that actively aerates the waste in 
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the landfill. Additionally, we propose to add 40 CFR 

98.466(d)(4) to require reporting of the MCF value and the 

basis for using an MCF value other than the default value 

of 1.

We are proposing to define the term “construction and 

demolition waste landfills” as defined in subpart HH and 

use that term rather than “dedicated construction and 

demolition waste landfills.”

We are also proposing to revise the footnote to Table 

TT-1 to subpart TT of part 98 to clarify that leachate 

recirculation rates can be determined from company records 

or engineering estimates and that the owner or operator of 

a landfill that uses leachate recirculation may elect to 

use the k value for the wet climate rather than calculating 

the leachate recirculation rate. These amendments provide 

improved consistency between the reporting requirements for 

municipal and industrial waste landfills.

Other Technical Corrections. We are proposing other 

technical corrections for subpart TT to correct 

typographical errors, to correct equations, and to provide 

minor clarifications. These proposed corrections are 

summarized below:

 In 40 CFR 98.460(c)(2)(i), replacing “Coal combustion 

residue (e.g., fly ash)” with “Coal combustion or 

incinerator ash (e.g., fly ash)” to better describe 
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our intent to classify all combustion ash products as 

inert.

 In 40 CFR 98.463(a)(1): 

– Revising the definition of GCH4 to delete the word 

“rate” because the units of the modeled methane 

generation is metric tons. 

– Revising the definition of DOCx from “degradable 

organic carbon for year X...” to be “degradable 

organic carbon for waste disposed in year X...” for 

clarity.

 In 40 CFR 98.463(a)(2):

– Revising “January 1, 1980” to be “January 1, 1960” 

in both places to correct an inadvertent error.

– Replacing the term “first emissions monitoring year” 

with “first emissions reporting year” to improve 

consistency with the terminology used in other 

sections of subpart TT.

 In 40 CFR 98.463(a)(2)(ii)(C):

– Deleting the phrase “fixed average annual bulk waste 

disposal quantity for each year for which historic 

disposal quantity and” in the paragraph text and 

adding to the definition of Wx “This annual bulk 

waste disposal quantity applies for all years from 

“YrOpen” to “YrData” inclusive” to clarify that the 

value calculated by Equation TT-4 applies for all 

years from “YrOpen” to “YrData” inclusive. 

– Revising the definition of LFC and YrData to allow 

closed landfills that have some measurement data to 

appropriately calculate Wx only for years for which 

the closed landfill does not have waste disposal 

data available from company records or from Equation 

TT-3. 

 In 40 CFR 98.464(b), replacing “For each waste stream 

for which you choose to determine...” with “For each 

waste stream received during the reporting year for 

which you choose to determine...” for clarity given the 

addition of 40 CFR 98.464(c).

 In 40 CFR 98.464(b)(1), adding the parenthetical “(as 

received at the landfill)” to clarify that the 

representative sample of each waste stream was to be 

determined “as received at that landfill” (as opposed 

to sampling waste in ‘closed’ sections of the 
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landfill) and for clarity given the addition of 40 CFR 

98.464(c).

 In 40 CFR 98.466(b), replacing “Report the following 

waste characterization information:” with “Report the 

following waste characterization and modeling 

information:” to better describe the reporting 

elements included in this paragraph.

 Moving paragraphs 40 CFR 98.466(d)(3) and (4) to 

98.466(b)(3) and (4) because these reporting elements 

are based on reporting year practices and do not need 

to be separately reported for each year or used in the 

summation for Equation TT-1. Also, to clarify that 

the fraction of CH4 in the landfill gas, F, should be 

based on CH4 concentration corrected to 0% oxygen. 

 In 40 CFR 98.466(b)(2), adding “...for which Equation 

TT-1 of this subpart is used to calculate modeled CH4

generation” to clarify that only descriptions of waste 

streams disposed of in the landfill and used in 

Equation TT-1 must be reported (as opposed to all 

wastes managed on-site regardless of whether the waste 

in managed in the landfill). 

 In 40 CFR 98.466(c)(3)(ii), replacing “The year, the 

waste disposal quantity and production quantity for 

each year Equation TT-2 applies” with “The year, the 

waste disposal quantity and production quantity for 

each year used in Equation TT-2 of this subpart to 

calculate the average waste disposal factor (WDF)” to 

clarify that these data are to be reported for the 

years used to calculate WDF, not the years for which 

WDF was subsequently used to calculate waste 

quantities. 

 In 40 CFR 98.466(d), adding the phase “and each year 

thereafter up” so that the paragraph reads “For each 

year of landfilling starting with the “Start Year” (S) 

and each year thereafter up to the current reporting 

year, report the following information:” to clarify 

that the reporting elements must be reported 

separately for each year. 

 Adding a new paragraph 40 CFR 98.466(d)(1) to read 

“The calendar year for which following data elements 

apply” to ensure the calendar year is also reported. 

Renumber existing paragraphs 98.466(d)(1) and (2) to 

(d)(2) and (3) and add the phrase “for the specified 
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year” to ensure the data elements are reported with 

specified year in the new paragraph 98.466(d)(1). 

 In 40 CFR 98.466(f), deleting the word “rate” to 

conform with revised definition of term and replace it 

with “(GCH4)” to clarify this is the equation term to 

be reported. 

 In 40 CFR 98.466(f), adding “(MG)” after “methane 

generation” to improve clarity and replace “Equation 

TT-5” with “Equation TT-6” to correct an improper 

equation cross-reference.

 In 40 CFR 98.468, adding the definition of “design 

capacity” to clarify what is meant by this term as it 

is used in 40 CFR 98.460. The definition is similar 

to 40 CFR 60.751 (Standards of Performance for 

Municipal Solid Waste Landfills).

 In Table TT-1, amending the default value of 

construction and demolition waste from 0.04 to 0.08 to 

correct an inadvertent error.

 In Table TT-1, revising the description of the waste 

type “Inert Waste” to read “Inert Waste [i.e., wastes 

listed in 40 CFR 98.460(c)(2)]” to correct an 

incorrect cross-reference. 

III. 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).

B. Paperwork Reduction Act
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This action does not impose any new information 

collection burden. These proposed amendments do not make 

any substantive changes to the reporting requirements in 

any of the subparts for which amendments are being 

proposed. In many cases, the proposed amendments to the 

reporting requirements could potentially reduce the 

reporting burden by making the reporting requirements 

conform more closely to current industry practices. 

However, the OMB has previously approved the information

collection requirements for subparts A and OO contained in 

the regulations promulgated on October 30, 2009, subpart W 

promulgated on November 30, 2010, subpart DD promulgated on 

December 1, 2010, subparts FF and TT promulgated on July 

12, 2010, and subpart RR promulgated on December 1, 2010 

under 40 CFR part 98 under the provisions of the Paperwork 

Reduction Act, 44 U.S.C. 3501 et seq., and has assigned OMB 

control numbers 2060-0629; 2060-0650; and 2060-0647; and 

2060-0649 respectively. The OMB control numbers for EPA’s 

regulations in 40 CFR are listed in 40 CFR part 9.

Further information on EPA’s assessment on the impact 

on burden can be found in the Technical Corrections and 

Amendments Cost Memo in docket number EPA-HQ-OAR-2011-0147.

C. Regulatory Flexibility Act (RFA)
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The RFA generally requires an agency to prepare a 

regulatory flexibility analysis of any rule subject to 

notice and comment rulemaking requirements under the 

Administrative Procedure Act or any other statute unless 

the agency certifies that the rule will not have a 

significant economic impact on a substantial number of 

small entities. Small entities include small businesses, 

small organizations, and small governmental jurisdictions.

For purposes of assessing the impacts of 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-for-profit enterprise which is 

independently owned and operated and is not dominant in its 

field. 

After considering the economic impacts of these 

proposed rule amendments on small entities, I certify that 

this action will not have a significant economic impact on 

a substantial number of small entities. The proposed rule 

amendments will not impose any new requirement on small 

entities that are not currently required by the regulation 
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of subparts A and OO promulgated on October 30, 2009; 

subparts FF, II, and TT promulgated on July 12, 2010; 

subpart W promulgated on November 30, 2010, or subparts DD 

or RR, both promulgated on December 1, 2010.

EPA took several steps to reduce the impact of 40 CFR 

part 98 on small entities when developing the final GHG 

reporting rules in 2009 and 2010. For example, EPA 

determined appropriate thresholds that reduced the number 

of small businesses reporting. In addition, EPA conducted 

several meetings with industry associations to discuss 

regulatory options and the corresponding burden on 

industry, such as recordkeeping and reporting. Finally, 

EPA continues to conduct significant outreach on the GHG 

reporting program and maintains an “open door” policy for 

stakeholders to help inform 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)

Title II of the Unfunded Mandates Reform Act of 1995 

(UMRA), 2 U.S.C. 1531–1538, requires Federal agencies, 

unless otherwise prohibited by law, to assess the effects 

of their regulatory actions on State, local, and Tribal 
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governments and the private sector. Federal agencies must 

also develop a plan to provide notice to small governments 

that might be significantly or uniquely affected by any 

regulatory requirements. The plan must enable officials of 

affected small governments to have meaningful and timely 

input in the development of EPA regulatory proposals with 

significant Federal intergovernmental mandates and must 

inform, educate, and advise small governments on compliance 

with the regulatory requirements.

The proposed rule amendments 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 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 amendments will not impose any new 

requirements that are not currently required for 40 CFR 

part 98, and the rule amendments would not unfairly apply 

to small governments. Therefore, this action is not 

subject to the requirements of section 203 of the UMRA.

E. Executive Order 13132: Federalism 
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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 amendments apply directly to facilities that 

supply certain products that would result in GHGs when 

released, combusted or oxidized and facilities that 

directly emit greenhouses gases. They do not apply to 

governmental entities unless the government entity owns a 

facility that directly emits GHGs above threshold levels 

(such as a landfill), so relatively few government 

facilities would be affected. This regulation also does 

not limit the power of States or localities to collect GHG 

data and/or regulate GHG emissions. Thus, Executive Order 

13132 does not apply to this action.

Although section 6 of Executive Order 13132 does not 

apply to this action, EPA did consult with State and local 

officials or representatives of State and local governments 

in developing subparts A and OO promulgated on October 30, 

2009; subparts FF, II, and TT promulgated on July 12, 2010; 

subpart W promulgated on November 30, 2010, and subparts DD 

and RR, both promulgated on December 1, 2010. A summary of 
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EPA’s consultations with State and local governments is 

provided in Section VIII.E of the preamble to the 2009 

final rule.

In the spirit of Executive Order 13132, and consistent 

with EPA policy to promote communications between EPA and 

State and local governments, EPA specifically solicits 

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 rule amendments would not result in 

any changes to the current requirements of 40 CFR part 98. 

Thus, Executive Order 13175 does not apply to this action.

Although Executive Order 13175 does not apply to this 

action, EPA sought opportunities to provide information to 

Tribal governments and representatives during the 

development of the rules for subparts A and OO promulgated 

on October 30, 2009; subparts FF, II, and TT promulgated on 

July 12, 2010; subpart W promulgated on November 30, 2010, 

and subparts and DD and RR, both promulgated on December 1, 

2010. A summary of the EPA’s consultations with Tribal 

officials is provided in Sections VIII.D and VIII.F of the 
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preamble to the 2009 final rule and in Section IV.F of the 

final rule for subpart W.

G. Executive Order 13045: Protection of Children from 

Environmental Health Risks and Safety Risks

EPA interprets Executive Order 13045 (62 FR 19885, 

April 23, 1997) as applying only to those regulatory 

actions that concern health or safety risks, such that the 

analysis required under section 5-501 of the Executive 

Order has the potential to influence the regulation. This 

action is not subject to Executive Order 13045 because it 

does not establish an environmental standard intended to 

mitigate health or safety risks.

H. Executive Order 13211: Actions that Significantly 

Affect Energy Supply, Distribution, or Use

This action is not subject to Executive Order 13211 

(66 FR 28355, May 22, 2001), because it is not a 

significant regulatory action under Executive Order 12866.

I. National Technology Transfer and Advancement Act

Section 12(d) of the National Technology Transfer and 

Advancement Act of 1995 (NTTAA), Public Law No. 104-113 (15 

U.S.C. 272 note) directs EPA to use voluntary consensus 

standards in its regulatory activities unless to do so 

would be inconsistent with applicable law or otherwise 

impractical. Voluntary consensus standards are technical 
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standards (e.g., materials specifications, test methods, 

sampling procedures, and business practices) that are 

developed or adopted by voluntary consensus standards 

bodies. NTTAA directs EPA to provide Congress, through 

OMB, explanations when the Agency decides not to use 

available and applicable voluntary consensus standards.

This proposed rulemaking does not involve technical 

standards. Therefore, EPA is not considering the use of 

any voluntary consensus standards.

J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and LowIncome 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. 

EPA has determined that this proposed rule will not 

have disproportionately high and adverse human health or 
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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.
Mandatory Reporting of Greenhouse Gases:

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List of Subjects in 40 CFR Part 98

Environmental protection, Administrative practice and 

procedure, Greenhouse gases, Suppliers, Reporting and 

recordkeeping requirements.

____________________________

Dated:

____________________________

Lisa P. Jackson,

Administrator.
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For the reasons stated in the preamble, part 98 of

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. 7401-7671q.

2. Section 98.2 is amended by:

a. Revising paragraph (d).

b. Revising paragraph (e).

c. Revising paragraph (f) introductory text.

d. Revising paragraph (h).

e. Revising paragraph (i)(3).

Subpart A—[Amended]

§98.2 Who must report?

* * * * *

(d) To calculate GHG quantities for comparison to 

the 25,000 metric ton CO2 per year threshold for importers 

and exporters of coal-to-liquid products under paragraph 

(a)(4) of this section, calculate the mass in metric tons 

per year of CO2 that would result from the complete 

combustion or oxidation of the quantity of coal-to-liquid 

products that are imported during the reporting year and, 

that are exported during the reporting year. Compare the 
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imported quantities and the exported quantities separately 

to the 25,000 metric ton CO2 per year threshold. Calculate 

the quantities using the methodology specified in subpart 

LL of this part. 

(e) To calculate GHG quantities for comparison to the 

25,000 metric ton CO2e per year threshold for importers and 

exporters of petroleum products under paragraph (a)(4) of 

this section, calculate the mass in metric tons per year of 

CO2 that would result from the complete combustion or 

oxidation of the combined volume of petroleum products and 

natural gas liquids that are imported during the reporting 

year and that are exported during the reporting year. 

Compare the imported quantities and the exported quantities 

separately to the 25,000 metric ton CO2 per year threshold. 

Calculate the quantities using the methodology specified in 

subpart MM of this part.

(f) To calculate GHG quantities for comparison to the 

25,000 metric ton CO2e per year threshold under paragraph 

(a)(4) of this section for importers and exporters of 

industrial greenhouse gases and for importers and exporters 

of CO2, the owner or operator shall calculate the mass in 

metric tons per year of CO2e imports and exports as 

described in paragraphs (f)(1) through (f)(3) of this 

section. Compare the imported quantities and the exported 
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quantities separately to the 25,000 metric ton CO2 per year 

threshold.

* * * * *

(h) An owner or operator of a facility or supplier 

that does not meet the applicability requirements of 

paragraph (a) of this section is not subject to this rule. 

Such owner or operator would become subject to the rule and 

reporting requirements, if a facility or supplier exceeds 

the applicability requirements of paragraph (a) of this 

section at a later time pursuant to §98.3(b)(3). Thus, the 

owner or operator should reevaluate the applicability to 

this part (including the revising of any relevant emissions 

calculations or other calculations) whenever there is any 

change that could cause a facility or supplier to meet the 

applicability requirements of paragraph (a) of this 

section. Such changes include but are not limited to 

process modifications, increases in operating hours, 

increases in production, changes in fuel or raw material 

use, addition of equipment, and facility expansion.

(i) * * *

(3) If the operations of a facility or supplier are 

changed such that all applicable GHG-emitting processes and 

operations listed in paragraphs (a)(1) through (a)(4) of 

this section cease to operate, then the owner or operator 
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is exempt from reporting in the years following the year in 

which cessation of such operations occurs, provided that 

the owner or operator submits a notification to the 

Administrator that announces the cessation of reporting and 

certifies to the closure of all GHG-emitting processes and 

operations no later than March 31 of the year following 

such changes. This paragraph (i)(3) does not apply to 

seasonal or other temporary cessation of operations. This 

paragraph (i)(3) does not apply to facilities with 

municipal solid waste landfills or industrial waste 

landfills, or to underground coal mines. The owner or 

operator must resume reporting for any future calendar year 

during which any of the GHG-emitting processes or 

operations resume operation.

* * * * *

3. Section 98.3 is amended by:

a. Revising paragraph (b) introductory text.

b. Revising paragraph (b)(1). 

c. Adding paragraph (b)(4).

d. Revising paragraph (c)(5)(ii).

e. Revising paragraph (c)(7).

f. Revising paragraph (c)(10).

g. Revising paragraph (c)(11). 
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h. Revising the second sentence of paragraph (g) 

introductory text.

§98.3 What are the general monitoring, reporting, 

recordkeeping and verification requirements of this part?

* * * * *

(b) Schedule. The annual GHG report for reporting 

year 2010 must be submitted no later than September 30, 

2011. The annual report for reporting years 2011 and 

beyond must be submitted no later than March 31 of each 

calendar year for GHG emissions in the previous calendar 

year, except as provided in paragraph (b)(1) of this 

section. 

(1) For reporting year 2011, GHG information required 

by the subparts listed in paragraphs (b)(1)(i) through 

(b)(1)(xii) of this section must be submitted no later than 

September 28, 2012. This reporting date applies only to 

the data reporting requirements identified in the listed 

subparts and does not affect data reporting requirements of 

other subparts that apply to a facility or supplier. 

(i) Electronics Manufacturing (subpart I). 

(ii) Fluorinated Gas Production (subpart L). 

(iii) Magnesium Production (subpart T). 

(iv) Petroleum and Natural Gas Systems (subpart W). 
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(v) Use of Electric Transmission and Distribution 

Equipment (subpart DD). 

(vi) Underground Coal Mines (subpart FF). 

(vii) Industrial Wastewater Treatment (subpart II). 

(viii) Imports and Exports of Equipment Pre–charged 

with Fluorinated GHGs or Containing Fluorinated GHGs in 

Closed–cell Foams (subpart QQ). 

(ix) Geologic Sequestration of Carbon Dioxide 

(subpart RR). 

(x) Manufacture of Electric Transmission and 

Distribution (subpart SS). 

(xi) Industrial Waste Landfills (subpart TT).

(xii) Injection of Carbon Dioxide (subpart UU).

* * * * *

(4) Unless otherwise stated, if the final day of any 

time period falls on a weekend or a Federal holiday, the 

time period shall be extended to the next business day.

(c) * * *

(5) * * *

(ii) Quantity of each GHG from each applicable supply 

category in Table A-5 of this subpart, expressed in metric 

tons of each GHG. For fluorinated GHG, report quantities 

of all fluorinated GHG, including those not listed in Table 

A-1 of this subpart.
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* * * * *

(7) A brief description of each “best available 

monitoring method” used, the parameter measured using the 

method, and the time period during which the “best 

available monitoring method” was used, if applicable.

* * * * *

(10) NAICS code(s) that apply to the facility or 

supplier. 

(i) Primary NAICS code. Report the NAICS code that 

most accurately describes the facility or supplier’s 

primary product/activity/ service. The primary 

product/activity/ service is the principal source of 

revenue for the facility or supplier. A facility or 

supplier that has two distinct 

products/activities/services providing comparable revenue 

may report a second primary NAICS code.

(ii) Additional NAICS code(s). Report all 

additional NAICS codes that describe all 

product(s)/activity(s)/service(s) at the facility or 

supplier that are not related to the principal source of 

revenue.

(11) Legal name(s) and physical address(es) of 

the highest-level United States parent company(s) of the 

owners (or operators) of the facility or supplier and the 
87 of 157

percentage of ownership interest for each listed parent 

company as of December 31 of the year for which data are 

being reported according to the following instructions:

(i) If the facility or supplier is entirely owned by 

a single United States company that is not owned by 

another company, provide that company’s legal name and 

physical address as the United States parent company 

and report 100 percent ownership.

(ii) If the facility or supplier is entirely owned 

by a single United States company that is, itself, owned by 

another company (e.g., it is a division or subsidiary of a 

higher-level company), provide the legal name and 

physical address of the highest-level company in the 

ownership hierarchy as the United States parent company 

and report 100 percent ownership.

(iii) If the facility or supplier is owned by more 

than one United States company (e.g., company A owns 40 

percent, company B owns 35 percent, and company C owns 

25 percent), provide the legal names and physical 

addresses of all the highest-level companies with an 

ownership interest as the United States parent 

companies, and report the percent ownership of each 

company.
88 of 157

(iv) If the facility or supplier is owned by a joint 

venture or a cooperative, the joint venture or cooperative 

is its own United States parent company. Provide the 

legal name and physical address of the joint venture or 

cooperative as the United States parent company, and 

report 100 percent ownership by the joint venture or 

cooperative.

(v) If the facility or supplier is entirely owned by 

a foreign company, provide the legal name and physical 

address of the foreign company’s highest-level company 

based in the United States as the United States parent 

company, and report 100 percent ownership.

(vi) If the facility or supplier is partially owned 

by a foreign company and partially owned by one or more 

U.S. companies, provide the legal name and physical 

address of the foreign company’s highest-level company 

based in the United States, along with the legal names 

and physical addresses of the other U.S. parent 

companies, and report the percent ownership of each of 

these companies.

(vii) If the facility or supplier is a federally 

owned facility, report “U.S. Government” and do not 

report physical address or percent ownership.

* * * * *
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(g) Recordkeeping. * * * Retain all required 

records for at least 3 years from the date of submission of 

the annual GHG report for the reporting year in which the 

record was generated. * * * 

* * * * *

4. Section 98.4 is amended by revising paragraph 

(m)(4) to read as follows:

§98.4 Authorization and responsibilities of the designated 

representative.

* * * * *

(m) * * *

(4) Any electronic submission covered by the 

certification in paragraph (m)(2)(v)(A) of this section and 

made in accordance with a notice of delegation effective 

under paragraph (m)(3) of this section shall be deemed to 

be an electronic submission certified, signed, and 

submitted by the designated representative or alternate 

designated representative submitting such notice of 

delegation.

5. Section 98.6 is amended by revising the 

definitions of “Blowdown vent stack”, “Supplier”, and 

“United States parent company(s)” to read as follows: 

§98.6 Definitions.

* * * * *
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Blowdown vent stack emissions mean natural gas and/or 

CO2 released due to maintenance and/or blowdown operations 

including compressor blowdown and emergency shut-down (ESD) 

system testing. Emissions from emergency events are not 

included.

* * * * *

Supplier means a producer, importer, or exporter in 

any supply category included in Table A-5, as defined by 

the corresponding subpart of this part.

* * * * *

United States parent company(s) means the highestlevel United States company(s) with an ownership interest 

in the facility or supplier as of December 31 of the year 

for which data are being reported.

* * * * *

6. Section 98.9 introductory text is amended to read 

as follows:

§98.9 Addresses.

All requests, notifications, and communications to the 

Administrator pursuant to this part, other than submittal 

of the annual GHG report; the certificate of 

representation; and other requests, notifications or 

communications that can be submitted through the electronic 
91 of 157

greenhouse gas reporting tool, shall be submitted to the 

following address: 

* * * * *

7. Table A-3 to subpart A is amended by revising the 

entry for “Underground coal mines” and for “Electrical 

transmission and distribution equipment use” to read as 

follows: 

Table A-3 of Subpart A of Part 98—Source Category List for 

§98.2(a)(1)

Source Categoriesa Applicable in 2010 and Future 

Years

* * * * * * *

Additional Source Categoriesa Applicable in 2011 and 

Future Years

* * * * * * *

Electrical transmission and distribution equipment 

use at facilities where the total nameplate capacity 

of SF6 and PFC containing equipment exceeds 17,820 

pounds, as determined under §98.301 (subpart DD).

Underground coal mines liberating 36,500,000 actual 

cubic feet of CH4 or more per year (subpart FF). 

* * * * * * *

a Source categories are defined in each applicable subpart.

8. Table A-5 to subpart A is amended by revising the 

entries for “Petroleum product suppliers (subpart MM)” to 

read as follows: 

Table A-5 to Subpart A of Part 98 —Supplier Category List 

for §98.2(a)(4)

Supplier Categoriesa Applicable in 2010 and Future Years
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* * * * * * *

Petroleum product suppliers (subpart MM):

(A) All petroleum refineries that distill crude oil.

(B) Importers of an annual quantity of petroleum products and 

natural gas liquids that is equivalent to 25,000 metric tons 

CO2e or more.

(C) Exporters of an annual quantity of petroleum products 

and natural gas liquids that is equivalent to 25,000 metric 

tons CO2e or more.

* * * * * * *

aSuppliers are defined in each applicable subpart.

Subpart W—[Amended]

9. Section 98.230 is amended by revising 

paragraph(a)(3)(ii) to read as follows:

§98.230 Definition of the source category. 

(a) * * *

(3) * * *

(ii) All processing facilities that do not 

fractionate with annual average throughput of 25 MMscf per 

day or greater. 

* * * * *

10. Section 98.232 is amended by revising paragraph 

(d) introductory text and paragraph (i) introductory text 

to read as follows:

§98.232 GHGs to report. 

* * * * *
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(d) For onshore natural gas processing, report CO2, 

CH4, and N2O emissions from the following sources: 

* * * * *

(i) For natural gas distribution, report CO2 and CH4

emissions from the following sources:

* * * * *

11. Section 98.233 is amended by:

a. Revising the definition of “GHGi” in Equation W-1 

of paragraph (a).

b. Revising the definition of “GHGi” in Equation W-2 

and W-2 in paragraph (c).

c. Revising the first sentence of paragraphs (d)(2), 

(d)(3), and (d)(4).

d. Revising paragraphs (e) introductory text, (e)(1) 

introductory text, (e)(1)(xi) introductory text, 

(e)(1)(xi)(A) through (C), and (e)(2) introductory text.

e. Revising paragraph (f)(2) introductory text.

f. In paragraph (f)(2), revising the introductory 

text, Equation W-8, and definitions of Equation W-8.

g. In paragraph (f)(3), revising Equation W-9 and the 

definitions of Equation W-9.

h. In paragraph (h), revising the definitions of 

“Ea,n”, “EFwo”, and “Vf” in Equation W-13.

i. Removing paragraph (h)(1).
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j. Redesignating paragraphs (h)(2) and (h)(3) as 

paragraphs (h)(1) and (h)(2), respectively, and revising 

new paragraph (h)(1). 

k. Revising paragraphs (i) introductory text and 

(i)(2).

l. Revising the definition of “Vv” in Equation W-14 

of paragraph (i)(3).

m. Revising paragraph (i)(4).

n. Revising the first sentence of paragraph (j)(1) 

and revising paragraph (j)(1)(vii).

o. Revising paragraphs (j)(2), (j)(3) introductory 

text, and (j)(4) introductory text.

p. In paragraph (j)(5), revising Equation W-15, 

revising the definitions of “EFi” and “Count”, and defining 

the use of “1,000”.

q. In paragraph (j)(8), revising Equation W-16, 

revising the definition of “En”, removing the definition of 

“Et”, and defining the use of “8,760”.

r. Revising paragraphs (k)(2) and (k)(4).

s. Revising paragraph (q) introductory text.

t. Revising the definition of “  i ” in Equation W-36 

of paragraph (v).

u. Revising paragraph (z) introductory text.
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v. In paragraph (z)(2)(iii), revising Equation W-39;

adding Equations W-39A and W-39B; adding definitions for 

“Ea,CH4”, “η”, “YCO2”, and “YCH4”; and revising the 

definitions of “Yj” and “Rj”. 

w. Revising paragraph (z)(3). 

x. Removing paragraphs (z)(6)(i) through (z)(6)(iii).

y. Redesignating paragraphs (z)(4), (z)(5), and 

(z)(6) as (z)(2)(iv), (z)(2)(v), and (z)(2)(vi), 

respectively. 

z. In newly redesignated paragraph (z)(2)(vi), 

revising Equation W-40 and revising the definition of 

“HHV”. 

§98.233 Calculating GHG emissions.

* * * * *

(a) * * *

GHGi = For onshore petroleum and natural gas 

production facilities, concentration of GHG i, 

CH4 or CO2, in produced natural gas as defined 

in paragraph (u)(2)(i) of this section; for 

facilities listed in §98.230(a)(4) and (a)(5), 

GHGi equals 0.952 for CH4 and 1×10-2 for CO2.

* * * * *

(c) * * *

GHGi = Concentration of GHG i, CH4 or CO2, in produced 

natural gas as defined in paragraph (u)(2)(i) 

of this section.

* * * * *
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(d) * * *

(2) Calculation Methodology 2. If CEMS is not 

available but a vent meter is installed, use the CO2

composition and annual volume of vent gas to calculate 

emissions using Equation W-3 of this section.

* * * * *

(3) Calculation Methodology 3. If CEMS or a vent 

meter is not installed, you may use the inlet or outlet gas 

flow rate of the acid gas removal unit to calculate 

emissions for CO2 using Equation W-4 of this section.

* * * * *

(4) Calculation Methodology 4. If CEMS or a vent 

meter is not installed, you may calculate emissions using 

any standard simulation software packages, such as 

AspenTech HYSYS® and API 4679 AMINECalc, that uses the PengRobinson equation of state, and speciates CO2 emissions. *

* *

* * * * *

(e) Dehydrator vents. For dehydrator vents, 

calculate annual CH4, CO2 and N2O (when flared) emissions 

using any of the calculation methodologies described in 

paragraph (e) of this section.

(1) Calculation Methodology 1. Calculate annual mass 

emissions from dehydrator vents with annual average daily 
97 of 157

throughput greater than or equal to 0.4 million standard 

cubic feet per day using a software program, such as 

AspenTech HYSYS® or GRI-GLYCalc, that uses the PengRobinson equation of state to calculate the equilibrium 

coefficient, speciates CH4 and CO2 emissions from 

dehydrators, and has provisions to include regenerator 

control devices, a separator flash tank, stripping gas and 

a gas injection pump or gas assist pump. A minimum of the 

following parameters determined by engineering estimate 

based on best available data must be used to characterize 

emissions from dehydrators:

* * * * *

(xi) Wet natural gas composition. Determine this 

parameter by selecting one of the methods described under 

paragraph (e)(1)(xi) of this section.

(A) Use the wet natural gas composition as defined in 

paragraph (u)(2)(i) or (u)(2)(ii) of this section.

(B) If wet natural gas composition cannot be 

determined using paragraph (u)(2)(i) or (u)(2)(ii) of this 

section, select a representative analysis.

(C) You may use an appropriate standard method 

published by a consensus-based standards organization if 

such a method exists or you may use an industry standard 
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practice as specified in §98.234(b) to sample and analyze 

wet natural gas composition.

* * * * *

(2) Calculation Methodology 2. Calculate annual CH4

and CO2 emissions from glycol dehydrators with annual 

average daily throughput less than 0.4 million cubic feet 

per day using Equation W-5 of this section: * * *

* * * * *

(f) * * *

(2) Calculation Methodology 2. Calculate the total 

emissions for well venting for liquids unloading using 

Equation W-8 of this section.

       











         



W V

Ea n VW CDW WDW SPW SFRW HRV,W ZV,W

3 2

, 0.37 10 1.0 (Eq. W-8)

Where:

Ea,n = Annual natural gas emissions at actual 

conditions, in cubic feet/year. 

W = Number of wells with well venting for liquids 

unloading at the facility. 

0.37×10-3 = {3.14 (pi)/4}/{14.7*144} (psia converted to 

pounds per square feet).

CDW = Casing diameter for each well, in inches.

WDW = Well depth to first producing horizon for each 

well, in feet.

SPW = Shut-in pressure for each well, in pounds 

square inch atmosphere (psia).

VW = Number of vents per year per well.
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SFRW = Average sales flow rate of each gas well in 

cubic feet per hour.

HRV,W = Hours that each well was left open to the 

atmosphere during each unloading event. 

1.0 = Hours for average well to blowdown casing 

volume at shut-in pressure.

ZV,W = If HRV,W is less than 1.0 then ZV,W is equal to 

0. If HRV,W is greater than or equal to 1.0 

then ZV,W is equal to 1.

* * * * *

(3) * * *

       











         



W V

Ea n VW CDW WDW SPW SFRW HRV,W ZV,W

3 2

, 0.37 10 1.0 (Eq. W-9)

Where:

Ea,n = Annual natural gas emissions at actual 

conditions, in cubic feet/year. 

W = Number of wells with well venting for liquids 

unloading at the facility. 

0.37×10-3 = {3.14 (pi)/4}/{14.7*144} (psia converted to 

pounds per square feet).

TDW = Tubing diameter for each well, in inches.

WDW = Tubing depth to plunger bumper for each well, 

in feet.

SPW = Sales line pressure for each well, in pounds 

per square inch atmospheric (psia).

NV = Number of vents per year per well.

SFRW = Average sales flow rate of each gas well in 

cubic feet per hour.

HRV,W = Hours that each well was left open to the 

atmosphere during each unloading event. 

0.5 = Hours for average well to blowdown tubing 

volume at sales line pressure.
100 of 157

ZV,W = If HRV,W is less than 0.5 then ZV,W is equal to 

0. If HRV,W is greater than or equal to 0.5 

then ZV,W is equal to 1.

* * * * *

(h) * * *

Es,n = Annual natural gas emissions in standard cubic 

feet from a gas well venting during well 

completions and workovers without hydraulic 

fracturing. 

* * * * *

EFwo = Emission Factor for non-hydraulic fracture well 

workover venting in standard cubic feet per 

workover. EFwo = 3114 standard cubic feet per 

well workover without hydraulic fracturing.

* * * * *

Vf = Average daily gas production rate in standard 

cubic feet per hour of each well completion 

without hydraulic fracturing. This is the total 

annual gas production volume divided by total 

number of hours the wells produced to the sales 

line. For completed wells that have not 

established a production rate, you may use the 

average flow rate from the first 30 days of 

production. In the event that the well is 

completed less than 30 days from the end of the 

calendar year, the first 30 days of the 

production straddling the current and following 

calendar years shall be used. 

* * * * *

(1) Volumetric emissions for both CH4 and CO2 shall be 

calculated from volumetric natural gas emissions using 

calculations in paragraphs (u) of this section. Mass 

emissions for both CH4 and CO2 shall be calculated from 
101 of 157

volumetric natural gas emissions using calculations in 

paragraphs (v) of this section.

(2) Calculate annual emissions from gas well venting 

during well completions and workovers not involving 

hydraulic fracturing to flares as follows: 

* * * * *

(i) Blowdown vent stacks. Calculate CO2 and CH4

blowdown vent stack emissions from depressurizing equipment 

to the atmosphere (excluding depressurizing to a flare, 

over-pressure relief, operating pressure control venting 

and blowdown of non-GHG gases; desiccant dehydrator 

blowdown venting before reloading is covered in paragraph 

(e)(5) of this section) as follows (Emissions from 

emergency events are not included.):

* * * * *

(2) If the total physical volume between isolation 

valves is greater than or equal to 50 cubic feet, retain 

logs of the number of blowdowns for each equipment type 

(including but not limited to compressors, vessels, 

pipelines, headers, fractionators, and tanks). Blowdown 

volumes smaller than 50 standard cubic feet are exempt from 

reporting under paragraph (i) of this section.

(3) * * *
102 of 157

Vv = Total physical volume of blowdown equipment 

chambers (including pipelines, compressors and 

vessels) between isolation valves in cubic feet.

* * * * *

(4) Calculate both CH4 and CO2 volumetric and mass 

emissions using calculations in paragraph (u) and (v) of 

this section.

* * * * *

(j) * * *

(1) Calculation Methodology 1. For separators with 

annual average daily throughput of oil greater than or 

equal to 10 barrels per day. * * *

* * * * *

(vii) Separator oil composition and Reid vapor 

pressure. If this data is not available, determine these 

parameters by selecting one of the methods described under 

paragraph (j)(1) (vii) of this section. 

* * * * *

(2) Calculation Methodology 2. Calculate annual CH4

and CO2 emissions from onshore production storage tanks for 

wellhead gas-liquid separators with annual average daily 

throughput of oil greater than or equal to 10 barrels per 

day by assuming that all of the CH4 and CO2 in solution at 

separator temperature and pressure is emitted from oil sent 

to storage tanks. You may use an appropriate standard 
103 of 157

method published by a consensus-based standards 

organization if such a method exists or you may use an 

industry standard practice as described in §98.234(b) to 

sample and analyze separator oil composition at separator 

pressure and temperature.

(3) Calculation Methodology 3. For wells with annual 

average daily oil production greater than or equal to 10 

barrels per day that flow directly to atmospheric storage 

tanks without passing through a wellhead separator, 

calculate annual CH4 and CO2 emissions by either of the 

methods in paragraph (j)(3) of this section:

* * * * *

(4) Calculation Methodology 4. For wells with annual 

average daily oil production greater than or equal to 10 

barrels per day that flow to a separator not at the well 

pad, calculate annual CH4 and CO2 emissions by either of the 

methods in paragraph (j)(4) of this section:

* * * * *

(5) * * *

Es,i EFi*Count *1000

(Eq. W-15)

Where:

Es,i = Annual total volumetric GHG emissions (either 

CO2 or CH4) at standard conditions in cubic 

feet.
104 of 157

EFi = Populations emission factor for separators or 

wells in thousand standard cubic feet per 

separator or well per year, for crude oil use 

4.3 for CH4 and 2.9 for CO2 at 68°F and 14.7 

psia, and for gas condensate use 17.8 for CH4

and 2.9 for CO2 at 68°F and 14.7 psia.

Count = Total number of separators or wells with 

throughput less than 10 barrels per day.

1,000 = Conversion to cubic feet

* * * * *

(8) * * *

   n n n

n

s i n T E T

E

E CF   











 * * 8760

8760

* , (Eq. W-16)

Where:

* * * * *

En = Storage tank emissions as determined in 

Calculation Methodologies 1, 2, or 4 in 

paragraphs (j)(1), (j)(2) and (j)(4) of this 

section (with wellhead separators) in cubic feet 

per year. 

* * * * *8,760 = Conversion to hourly 

emissions.

* * * * *

(k) * * *

(2) If the tank vapors are continuous for 5 minutes, 

or the acoustic leak detection device detects a leak, then 

use one of the following two methods in paragraph (k)(2) of 

this section to quantify annual emissions: 

* * * * *
105 of 157

(4) Calculate annual emissions from storage tanks to 

flares as follows:

(i) Use the storage tank emissions volume and gas 

composition as determined in paragraphs (k)(1) through 

(k)(3) of this section.

(ii) Use the calculation methodology of flare stacks 

in paragraph (n) of this section to determine storage tank 

emissions sent to a flare.

* * * * *

(q) Leak detection and leaker emission factors. You 

must use the methods described in §98.234(a) to conduct 

leak detection(s) of equipment leaks from all sources 

listed in §98.232(d)(7), (e)(7), (f)(5), (g)(3), (h)(4), 

and (i)(1). This paragraph (q) applies to emissions 

sources in streams with gas content greater than 10 percent 

CH4 plus CO2 by weight. Emissions sources in streams with 

gas content less than 10 percent CH4 plus CO2 by weight do 

not need to be reported. Tubing systems equal to or less 

than one half inch diameter are exempt from the 

requirements of this paragraph (q) and do not need to be 

reported. If equipment leaks are detected for sources 

listed in this paragraph (q), calculate equipment leak 

emissions per source per reporting facility using Equation 

W-30 of this section for each source with equipment leaks. 
106 of 157

* * * * *

(v) * * *

 i = Density of GHG i. Use 0.0520 kg/ft3 for CO2 and 

N2O, and 0.0190 kg/ft3 for CH4 at 68°F and 14.7 

psia or 0.0530 kg/ft3 for CO2 and N2O, and 0.0193 

kg/ft3 for CH4 at 60°F and 14.7 psia .

* * * * *

(z) Onshore petroleum and natural gas production and 

natural gas distribution combustion emissions. Calculate 

CO2, CH4, and N2O combustion-related emissions from 

stationary or portable equipment, except as specified in 

paragraph (z)(3) of this section, as follows:

(2) * * *

(iii) * * *

  

j

Ea CO Va YCO Va Yj Rj( * ) * * * , 2 2  (Eq. W-39A)

  Ea,CH 4  Va * 1 *YCH 4 (Eq. W-39B)

Where:

* * * * *

Ea,CH4 = Contribution of annual CH4 emissions from 

portable or stationary fuel combustion sources 

in cubic feet, under actual conditions.

η = Combustion efficiency for portable and 

stationary equipment determined based on 

engineering estimation. 

* * * * *

Yj = Concentration of gas hydrocarbon constituents 

j (such as methane, ethane, propane, butane, 
107 of 157

and pentanes plus) in gas sent to combustion 

unit.

YCH4 = Concentration of methane constituent in gas 

sent to combustion unit.

YCO2 = Concentration of CO2 constituent in gas sent 

to combustion unit.

Rj = Number of carbon atoms in the gas hydrocarbon 

constituent j; 1 for methane, 2 for ethane, 3 

for propane, 4 for butane, and 5 for pentanes 

plus) in gas sent to combustion unit.

(iv) Calculate GHG volumetric emissions at standard 

conditions using calculations in paragraph (t) of this 

section.

(v) Calculate both combustion-related CH4 and CO2 mass 

emissions from volumetric CH4 and CO2 emissions using 

calculation in paragraph (v) of this section.

(vi) Calculate N2O mass emissions using Equation W–40 

of this section.

N O     Fuel  HHV  EF 3

2 1 10 (Eq. W-40)

Where:

* * * * *

HHV = For the high heat value for field gas or 

process vent gas, use 1.235 x 10-3 mmBtu/scf 

for HHV.

* * * * *
108 of 157

(3) External fuel combustion sources with a rated 

heat capacity equal to or less than 5 mmBtu/hr do not need 

to report combustion emissions or include these emissions 

for threshold determination in §98.231(a). You must report 

the type and number of each external fuel combustion unit.

12. Section 98.234 is amended by revising Equation W41 of paragraph (e) to read as follows:

§98.234 Monitoring and QA/QC requirements.

* * * * *

(e) * * *

2 2 V 2bV b

a

V b

RT

p

m m  m 









(Eq. W-41)

Where:

p = Absolute pressure.

R = Universal gas constant.

T = Absolute temperature.

Vm = Molar volume.

a = c

c

p

R T

2 2

0.45724

b = c

c

p

0.7780RT

α =  

2

2

1 0.37464 1.54226 0.26992 1

































   

Tc

T

 

Where:

ω = Acentric factor of the species.
109 of 157

Tc = Critical temperature.

Pc = Critical pressure.

* * * * *

13. Section 98.236 is amended by revising paragraphs 

(c)(6)(ii)(B) and (c)(7)(i).

§98.236 Data reporting requirements.

* * * * *

(c) * * *

(6) * * *

(ii) * * *

(B) Total count of workovers in calendar year that 

flare gas or vent gas to the atmosphere.

* * * * *

(7) * * *

(i) Total number of blowdowns per unique volume type 

in calendar year. 

* * * * *

14. Tables W-3 and W-4 to subpart W are amended by 

revising the entries for “Low Continuous Bleed Pneumatic 

Device Vents”, “High Continuous Bleed Pneumatic Device 

Vents”, and “Intermittent Bleed Pneumatic Device Vents” as 

follows:
110 of 157

Table W-3 to Subpart W of Part 98--Default Total 

Hydrocarbon Emission Factors for Onshore Natural Gas 

Transmission Compression

Onshore natural gas transmission compression Emission Factor 

(scf/hour/component)

Leaker Emission Factors - Compressor Components, Gas Service

* * * * * * * *

Leaker Emission Factors – Non-Compressor Components, Gas Service

* * * * * * * *

Population Emission Factors – Gas Service

Low Continuous Bleed Pneumatic Device Vents2 1.79

High Continuous Bleed Pneumatic Device Vents2 20.1

Intermittent Bleed Pneumatic Device Vents2 20.1

1 Valves include control valves, block valves and regulator valves.

2 Emission Factor is in units of "scf/hour/device"

Table W-4 to Subpart W of Part 98—Default Total Hydrocarbon 

Emission Factors for Underground Natural Gas Storage

Underground natural gas storage

Emission Factor 

(scf/hour/component

)

Leaker Emission Factors - Storage Station, Gas Service

* * * * * * *

Population Emission Factors - Storage Wellheads, Gas Service

* * * * * * *

Population Emission Factors - Other Components, Gas Service

Low Continuous Bleed Pneumatic Device 

Vents2 1.79

High Continuous Bleed Pneumatic Device 

Vents2 20.1

Intermittent Bleed Pneumatic Device Vents2

20.1

1 Valves include control valves, block valves and regulator 

valves.

2 Emission Factor is in units of "scf/hour/device"

Subpart FF—[Amended]

15. Section 98.322 is amended by revising paragraph 

(f) to read as follows:

§98.322 GHGs to report.

* * * * *

(f) An underground coal mine that is subject to this 

part because emissions from source categories described in 
111 of 157

Tables A-3, A-4 or A-5, or from stationary combustion 

(subpart C), is not required to report emissions under 

subpart FF of this part unless the coal mine liberates 

36,500,000 actual cubic feet (acf) or more of methane per 

year from its ventilation system.

16. Section 98.323 is amended by:

a. Revising the definitions of “V”, “C”, and “P” in 

Equation FF-1 of paragraph (a).

b. Revising the first sentence of paragraph (a)(2).

c. Revising the definitions of “Vi”, “Ci”, Ti, and 

“Pi” in equation FF-3 of paragraph (b).

d. Revising the first sentence of parapraph (b)(1).

e. Revising paragraph (c) introductory text.

§98.323 Calculating GHG emissions.

(a) * * *

V = Volumetric flow rate for the quarter

(cfm) based on sampling or a flow rate meter. 

If a flow rate meter is used and the meter 

automatically corrects for temperature and 

pressure, replace “520°R/T × P/1 atm” with 

“1”.

* * * * *

C = CH4 concentration of ventilation gas for the 

quarter (%). 

* * * * *

P = Pressure at which flow is measured (atm) 

for the quarter. The annual average 
112 of 157

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. * 

* *

* * * * *

(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 

(cfm).If a flow rate meter is used and the 

meter automatically corrects for 

temperature and pressure, replace 

“520°R/Ti × Pi/1 atm” with “1”.

* * * * *

Ci = CH4 concentration of gas for the days in 

the week when the degasification system is 

in operation at that monitoring point (%).

* * * * *

Ti = Temperature at which flow is measured 

(°R). 

Pi = 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 
113 of 157

calendar week with at least 3 days between measurements. * 

* *

* * * * *

(c) If gas from degasification system wells or 

ventilation shafts is sold, used onsite, or otherwise 

destroyed (including by flaring), 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 Eq. FF-1 or Eq. FF-3, as applicable. 

* * * * *

17. Section 98.324 is amended by:

a. Revising paragraphs (b)(1) and (b)(2).

b. Revising paragraph (c).

c. Revising paragraph (d). 

d. Revising paragraph (e) introductory text.

e. Revising paragraphs (g) and (h).

§98.324 Monitoring and QA/QC requirements. 

* * * * *

(b) * * *

(1) Collect quarterly or more frequent grab samples 

(with no fewer than 6 weeks between measurements) for 
114 of 157

methane concentration and make quarterly measurements of 

flow rate, temperature, pressure, and moisture content, if 

applicable. The sampling and measurements must be made at 

the same locations as MSHA inspection samples are taken, 

and should be taken when the mine is operating under normal 

conditions. You must follow MSHA sampling procedures as 

set forth in the MSHA Handbook entitled, General Coal Mine 

Inspection Procedures and Inspection Tracking System 

Handbook Number: PH-08-V-1, January 1, 2008 (incorporated 

by reference, see §98.7). 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. 

(2) Obtain results of the quarterly (or more 

frequent) testing performed by MSHA for the methane 

flowrate. At the time and location of the MSHA sampling, 

make measurements of temperature, pressure and moisture 

content using the same procedures specified in paragraph 

(b)(1) of this section. If the MSHA data for methane flow 

is provided in the units of actual cubic feet of methane 

per day, the methane flow data is inserted into Equation 

FF-1 of this section in place of the value for V and the 
115 of 157

variables MCF, C/100%, and 1440 are removed from the 

equation.

* * * * *

(c) For CH4 liberated at degasification systems, 

determine whether CH4 will be monitored from each well and 

gob gas 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 well or gob gas vent hole, as long as emissions 

from all are addressed, and the methodology for calculating 

total emissions is documented. Monitor both gas volume and 

methane concentration by one of the following two options: 

(1) Monitor emissions through the use of one or more 

continuous emissions monitoring systems (CEMS). If 

operators use CEMS as the basis for emissions reporting, 

they must provide documentation on the process for using 

data obtained from their CEMS to estimate emissions from 

their mine ventilation systems. 

(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 
116 of 157

composition should be determined either by submitting 

samples to a lab for analysis, or from the use of 

methanometers at the degasification well 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. 

(3) 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 gas in a location near or 

representative of the location of:

(i) The gas flow meter at least once each calendar 

week; if measuring with CEMS. If only one measurement is 

made each calendar week, there must be at least three days 

between measurements; and 

(ii) The grab sample, if using grab samples, at the 

time of the sample.
117 of 157

(d) Monitoring must adhere to one of the methods 

specified in paragraphs (d)(1) through (d)(2) of this 

section. 

(1) ASTM D1945-03, Standard Test Method for Analysis 

of Natural Gas by Gas Chromatography; ASTM D1946-90 

(Reapproved 2006), Standard Practice for Analysis of 

Reformed Gas by Gas Chromatography; ASTM D4891-89 

(Reapproved 2006), Standard Test Method for Heating Value 

of Gases in Natural Gas Range by Stoichiometric Combustion; 

or ASTM UOP539-97 Refinery Gas Analysis by Gas 

Chromatography (incorporated by reference, see §98.7).

(2) As an alternative to the gas chromatography 

methods provided in paragraph (d)(1) of this section, you 

may use gaseous organic concentration analyzers and a 

correction factor to calculate the CH4 concentration 

following the requirements in paragraphs (d)(2)(i) through 

(d)(2)(iii) of this section.

(i) Use Method 25A or 25B at 40 CFR part 60, appendix 

A-7 to determine gaseous organic concentration as required 

in §98.323 and in paragraphs (b) and (c) of this section. 

You must calibrate the instrument with CH4 and determine the 

total gaseous organic concentration as carbon (or as CH4; 

K=1 in Equation 25A-1 of Method 25A at 40 CFR part 60, 

appendix A-7).
118 of 157

(ii) Determine a correction factor that will be used 

with the gaseoue organic concentrations measured in 

paragraph (i) of this section. The correction factor must 

be determined at the routine sampling location no less 

frequently than once a reporting year following the 

requirements in paragraphs (d)(2)(ii)(A) through 

(d)(2)(ii)(C) of this section.

(A) Take a minimum of three grab samples of the gas 

with a minimum of 20 minutes between samples and determine 

the methane composition of the gas using one of the methods 

specified in paragraph (d)(1) of this section.

(B) As soon as practical after each grab sample is 

collected and prior to the collection of a subsequent grab 

sample, determine the gaseous organic concentration of the 

gas using either Method 25A or 25B at 40 CFR part 60, 

appendix A-7 as specified in paragraph (d)(2)(i) of this 

section.

(C) Determine the arithmetic average methane 

concentration and the arithmetic average gaseous organic 

concentration of the samples analyzed according to 

paragraphs (d)(2)(ii)(A) and (d)(2)(ii)(B) of this section, 

respectively, and calculate the non-methane organic carbon 

correction factor as the ratio of the average methane 

concentration to the average total gaseous organic 
119 of 157

concentration. If the ratio exceeds 1, use 1 for the 

correction factor.

(iii) Calculate the CH4 concentration as specified in 

Equation FF-9 of this section:

CCH4 = fNMOC x CTGOC (Eq. FF-9)

Where:

CCH4 = Methane (CH4) concentration in the gas (volume 

%) for use in Equations FF-1 and FF-3 of this 

subpart.

fNMOC = Correction factor from the most recent 

determination of the correction factor as 

specified in paragraph (d)(2)(ii) of this section 

(unitless).

CTGOC = Gaseous organic carbon concentration measured 

using Method 25A or 25B at 40 CFR part 60, 

appendix A-7 during routine monitoring of the gas 

(volume %).

(e) All flow meters and gas composition monitors that 

are used to provide data for the GHG emissions calculations 

shall be calibrated prior to the first reporting year, 

using the applicable methods specified in paragraphs (d), 

and (e)(1) through (e)(7) of this section. Alternatively, 

calibration procedures specified by the flow meter 

manufacturer may be used. Flow meters and gas composition 

monitors shall be recalibrated either at the minimum 

frequency specified by the manufacturer or annually. The 

operator shall operate, maintain, and calibrate a gas 

composition monitor capable of measuring the concentration 
120 of 157

of CH4 in the gas using one of the methods specified in 

paragraph (d) of this section. The operator shall operate, 

maintain, and calibrate the flow meter using any of the 

following test methods or follow the procedures specified 

bythe flow meter manufacturer. Flow meters must meet the 

accuracy requirements in §98.3(i).

* * * * *

(g) All temperature, pressure, and moisture content 

monitors must be operated and calibrated using the 

procedures and frequencies specified by the manufacturer.

(h) If applicable, the owner or operator shall 

document the procedures used to ensure the accuracy of gas 

flow rate, gas composition, temperature, pressure, and 

moisture content measurements. These procedures include, 

but are not limited to, calibration of flow meters, and 

other measurement devices. The estimated accuracy of 

measurements, and the technical basis for the estimated 

accuracy shall be recorded.

18. Section 98.325 is amended by revising the first 

sentence of paragraph (b) as follows:

§98.325 Procedures for estimating missing data.

* * * * *

(b) For each missing value of CH4 concentration, flow 

rate, temperature, pressure, and moisture content for 
121 of 157

ventilation and degasification systems, the substitute data 

value shall be the arithmetic average of the qualityassured values of that parameter immediately preceding and 

immediately following the missing data incident. * *

*

Section 98.326 is amended by:

a. Revising paragraph (f).

b. Revising paragraph (h).

c. Revising paragraph (j).

d. Revising paragraph (k).

e. Revising paragraph (o).

§98.326 Data reporting requirements. 

* * * * *

(f) Quarterly volumetric flow rate for each 

ventilation monitoring point (scfm), date and location of 

each measurement, and method of measurement (quarterly 

sampling or continuous monitoring), used in Equation FF-1.

* * * * *

(h) Weekly volumetric flow rate used to calculate CH4

liberated from degasification systems (cfm) and method of 

measurement (sampling or continuous monitoring), used in 

Equation FF-3.

* * * * *
122 of 157

(j) Weekly volumetric flow rate used to calculate CH4

destruction for each destruction device and each point of 

offsite transport (cfm).

(k) Weekly CH4 concentration (%) used to calculate CH4

flow to each destruction device and each point of offsite 

transport (C).

* * * * *

(o) Temperatures (°R), pressure (atm), and moisture 

content used in Eq. FF-1 and FF-3, and the gaseous organic 

concentration correction factor, if Equation FF-9 was 

required. 

* * * * *

Subpart II—[Amended]

19. Section 98.350 is amended by revising the first 

sentence of paragraph (b) introductory text to read as 

follows:

§98.350 Definition of Source Category

* * * * *

(b) An anaerobic process is a procedure in which 

organic matter in wastewater, wastewater treatment sludge, 

or other material is degraded by micro-organisms in the 

absence of oxygen, resulting in the generation of CO2 and 

CH4. * * *

* * * * *
123 of 157

20. Section 98.352 is amended by revising paragraph 

(d) as follows:

§98.352 GHGs to report.

* * * * *

(d) You must report under subpart C of this part 

(General Stationary Fuel Combustion Sources) the emissions 

of CO2, CH4, and N2O from each stationary combustion unit 

associated with the biogas destruction device, if present, 

by following the requirements of subpart C of this part. 

21. Section 98.353 is amended by:

a. Revising paragraph (a)(2).

b. Revising paragraph (c) introductory text and 

paragraph (c)(1).

c. Revising the definitions of “Rn”, “Tm”, and “Pm” 

in Equation II-4 of paragraph (c)(1).

d. Revising paragraph (c)(2) introductory text.

e. Removing paragraph (c)(2)(i).

f. Redesignating paragraphs (c)(2)(ii) and 

(c)(2)(iii) as paragraphs (c)(2)(i) and (c)(2)(ii), 

respectively. 

g. Revising new paragraphs (c)(2)(i) and (c)(2)(ii).

h. Revising paragraph (d) introductory text.

i. Revising the definition of “Rn” in Equation II-5 

in paragraph (d)(1).
124 of 157

j. Revising Equation II-6 and revising the definition 

of “CH4En”, “Rn”, “DE1”, and “fDest_1” in paragraph (d)(2).

§98.353 Calculating GHG emissions.

(a) * * *

(2) If you measure the concentration of organic 

material entering an anaerobic reactor or anaerobic lagoon 

using methods for the determination of 5-day biochemical 

oxygen demand (BOD5), then estimate annual mass of CH4

generated using Equation II-2 of this section. 

* * * * *

(c) For each anaerobic sludge digester, anaerobic 

reactor, or anaerobic lagoon from which some biogas is 

recovered, estimate the annual mass of CH4 recovered 

according to the requirements in paragraphs (c)(1) and 

(c)(2) of this section. To estimate the annual mass of CH4

recovered, you must continuously monitor biogas flow rate 

and determine the volume of biogas each week and the 

cumulative volume of biogas each year that is collected and 

routed to a destruction device as specified in §98.354(h). 

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 (c)(2)(ii) of this section.
125 of 157

(1) If you continuously monitor CH4 concentration (and 

if necessary, temperature, pressure, and moisture content 

required as specified in §98.354(f)) of the biogas that is 

collected and routed to a destruction device using a 

monitoring meter specifically for CH4 gas, as specified in 

§98.354(g), you must use this monitoring system and 

calculate the quantity of CH4 recovered for destruction 

using Equation II-4 of this section. A fully integrated 

system that directly reports CH4 quantity requires only the 

summing of results of all monitoring periods for a given 

year. 

* * * * *

Rn = Annual quantity of CH4 recovered from the nth 

anaerobic reactor, sludge digester, or 

lagoon (metric tons CH4/yr)

* * * * *

Tm = Average temperature at which flow is measured 

for the measurement period(°R). If the flow 

rate meter automatically corrects for 

temperature to 520° R, replace “520° R/Tm” 

with “1”.

Pm = Average pressure at which flow is measured for 

the measurement period (atm). If the flow 

rate meter automatically corrects for 

pressure to 1 atm, replace “Pm/1” with “1”.

* * * * *

(2) If you do not continuously monitor CH4 

concentration according to paragraph(c)(1) of this section, 
126 of 157

you must determine the CH4 concentration, temperature, 

pressure, and, if necessary, moisture content of the biogas 

that is collected and routed to a destruction device 

according to the requirements in paragraphs (c)(2)(i) 

through (c)(2)(ii) of this section and calculate the 

quantity of CH4 recovered for destruction using Equation II4 of this section. 

(i) Determine the CH4 concentration in the biogas that 

is collected and routed to a destruction device in a 

location near or representative of the location of the gas 

flow meter at least once each calendar week; if only one 

measurement is made each calendar week, there must be least 

three days between measurements. For a given calendar 

week, you are not required to determine CH4 concentration if 

the cumulative volume of biogas for that calendar week, 

determined as specified in paragraph (c) of this section, 

is zero. 

(ii) If the gas flow meter is not equipped with 

automatic correction for temperature, pressure, or, if 

necessary, moisture content: 

(A) Determine the temperature and pressure in the 

biogas that is collected and routed to a destruction device 

in a location near or representative of the location of the 

gas flow meter at least once each calendar week; if only 
127 of 157

one measurement is made each calendar week, there must be 

at least three days between measurements. 

(B) If the CH4 concentration is determined on a dry 

basis and biogas flow is determined on a wet basis, or CH4

concentration is determined on a wet basis and biogas flow 

is determined on a dry basis, and the flow meter does not 

automatically correct for moisture content, determine the 

moisture content in the biogas that is collected and routed 

to a destruction device in a location near or 

representative of the location of the gas flow meter at 

least once each calendar week that the cumulative biogas 

flow measured as specified in §98.354(h) is greater than 

zero; if only one measurement is made each calendar week, 

there must be at least three days between measurements. 

(d) For each anaerobic sludge digester, anaerobic 

reactor, or anaerobic lagoon from which some quantity of 

biogas is recovered, you must estimate both the annual mass 

of CH4 that is generated, but not recovered, according to 

paragraph (d)(1) of this section and the annual mass of CH4

emitted according to paragraph (d)(2) of this section. *

* *

(1) * * *

Rn = Annual quantity of CH4 recovered from the nth 

anaerobic reactor, anaerobic lagoon, or 
128 of 157

anaerobic sludge digester, as calculated in 

Equation II-4 of this section (metric tons CH4).

* * * * *

(2) For each anaerobic sludge digester, anaerobic 

reactor, or anaerobic lagoon from which some quantity of 

biogas is recovered, estimate the annual mass of CH4 emitted 

using Equation II-6 of this section.

CH4En = CH4Ln + Rn (1− [ (DE1 ∗ fDest_1 )+ (DE2 ∗ fDest_2)]) (Eq. II6)

Where:

CH4En = Annual quantity of CH4 emitted from the process n 

from which biogas is recovered (metric tons).

* * * * *

Rn = Annual quantity of CH4 recovered from the nth 

anaerobic reactor or anaerobic sludge digester, 

as calculated in Equation II-4 of this section 

(metric tons CH4).

DE1 = Primary destruction device CH4 destruction 

efficiency (lesser of manufacturer’s specified 

destruction efficiency and 0.99). If the biogas 

is transported off-site for destruction, use 

DE=1.

fDest_1 = Fraction of hours the primary destruction device 

was operating (device operating hours/hours in 

the year). If the biogas is transported off-site 

for destruction, use fDest=1. 

* * * * *

22. Section 98.354 is amended by:

a. Revising the second sentence of paragraph (c).

b. Revising paragraph (d) introductory text.

c. Revising paragraph (f).

d. Revising paragraph (g) introductory text.
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e. Revising paragraph (h) introductory text and 

paragraph (h)(5).

f. Revising paragraph (k).

§98.354 Monitoring and QA/QC requirements. 

(c) * * * You must collect and analyze samples 

for COD or BOD5 concentration at least once each calendar 

week that the anaerobic wastewater treatment process is 

operating; if only one measurement is made each calendar 

week, there must be at least three days between 

measurements. * * *

(d) You must measure the flowrate of wastewater 

entering anaerobic wastewater treatment process at least 

once each calendar week that the process is operating; if 

only one measurement is made each calendar week, there must 

be at least three days between measurements. You must 

measure the flowrate for the 24-hour period for which you 

collect samples analyzed for COD or BOD5 concentration. The 

flow measurement location must correspond to the location 

used to collect samples analyzed for COD or BOD5

concentration. You must measure the flowrate using one of 

the methods specified in paragraphs (d)(1) through (d)(5) 

of this section or as specified by the manufacturer. 

* * * * *
130 of 157

(f) For each anaerobic process (such as anaerobic 

reactor, sludge digester, or lagoon) from which biogas is 

recovered, you must make the measurements or determinations 

specified in paragrahps (f)(1) through (f)(3) of this 

section.

(1) You must continuously measure the biogas flow 

rate as specified in paragraph (h) of this section and 

determine the cumulative volume of biogas recovered. 

(2) You must determine the CH4 concentration of the 

recovered biogas as specified in paragraph (g) of this 

section at a location near or representative of the 

location of the gas flow meter. You must determine CH4

concentration either continuously or intermittently. If 

you determine the concentration intermittently, you must 

determine the concentration at least once each calendar 

week that the cumulative biogas flow measured as specified 

in paragraph (h) of this section is greater than zero, with 

at least three days between measurements. 

(3) As specified in §98.353(c) and paragraph (h) of 

this section, you must determine temperature, pressure, and 

moisture content as necessary to accurately determine the 

biogas flow rate and CH4 concentration. You must determine 

temperature and pressure if the gas flow meter or gas 

composition monitor do not automatically correct for 
131 of 157

temperature or pressure. You must measure moisture content 

of the recovered biogas if the biogas flow rate is measured 

on a wet basis and the CH4 concentration is measured on a 

dry basis. You must also measure the moisture content of 

the recovered biogas if the biogas flow rate is measured on 

a dry basis and the CH4 concentration is measured on a wet 

basis. 

(g) For each anaerobic process (such as an anaerobic 

reactor, sludge digester, or lagoon) from which biogas is 

recovered, operate, maintain, and calibrate a gas 

composition monitor capable of measuring the concentration 

of CH4 in the recovered biogas using one of the methods 

specified in paragraphs (g)(1)through(g)(6) of this section 

or as specified by the manufacturer. 

* * * * *

(h) For each anaerobic process (such as an anaerobic 

reactor, sludge digester, or lagoon) from which biogas is 

recovered, install, operate, maintain, and calibrate a gas 

flow meter capable of continuously measuring the volumetric 

flow rate of the recovered biogas using one of the methods 

specified in paragraphs (h)(1) through (h)(8) of this 

section or as specified by the manufacturer. Recalibrate 

each gas flow meter either biennially (every 2 years) or at 

the minimum frequency specified by the manufacturer. 
132 of 157

Except as provided in §98.353(c)(2)(iii), each gas flow 

meter must be capable of correcting for the temperature and 

pressure and, if necessary, moisture content.

* * * * *

(5) ASME MFC-11M-2006 Measurement of Fluid Flow by 

Means of Coriolis Mass Flowmeters (incorporated by 

reference, see §98.7). The mass flow must be corrected to 

volumetric flow based on the measured temperature, 

pressure, and biogas composition.

* * * * *

(k) If applicable, the owner or operator must 

document the procedures used to ensure the accuracy of 

measurements of COD or BOD5 concentration, wastewater flow 

rate, biogas flow rate, biogas composition, temperature, 

pressure, and moisture content. These procedures include, 

but are not limited to, calibration of gas 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 

documented.

23. Section 98.355 is amended by revising paragraph 

(b) to read as follows:

§98.355 Procedures for estimating missing data

* * * * *
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(b) For each missing value of the CH4 content or 

biogas flow rates, the substitute data value must be the 

arithmetic average of the quality-assured values of that 

parameter immediately preceding and immediately following 

the missing data incident. 

* * * * *

24. Section 98.356 is amended by:

a. Revising paragraph (a) introductory text.

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

c. Revising paragraph (d) introductory text and 

paragraphs (d)(2), (d)(4), (d)(6), and (d)(8).

§98.356 Data reporting requirements. 

* * * * *

(a) A description or diagram of the industrial 

wastewater treatment system, identifying the processes used 

to treat industrial wastewater and industrial wastewater 

treatment sludge. Indicate how the processes are related 

to each other and identify the anaerobic processes. 

Provide a unique identifier for each anaerobic process, 

indicate the average depth in meters of each anaerobic 

lagoon, and indicate whether biogas generated by each 

anaerobic process is recovered. The anaerobic processes 

must be identified as:

* * * * *
134 of 157

(b) * * *

(3) Maximum CH4 production potential (B0) used as an 

input to Equation II-1 or II-2 of this subpart, from Table 

II-1. 

(4) Methane conversion factor (MCF) used as an input 

to Equation II-1 or II-2 of this subpart, from Table II-1. 

* * * * *

(d) For each anaerobic wastewater treatment process 

and anaerobic sludge digester from which some biogas is 

recovered, you must report:

* * * * *

(2) Total weekly volumetric biogas flow for each week 

(up to 52 weeks/year) that biogas is collected for 

destruction.

* * * * *

(4) Weekly average biogas temperature for each week 

at which flow is measured for biogas collected for 

destruction, or statement that temperature is incorporated 

into monitoring equipment internal calcultations.

* * * * *

(6) Weekly average biogas pressure for each week at 

which flow is measured for biogas collected for 

destruction, or statement that pressure is incorporated 

into monitoring equipment internal calcultations.
135 of 157

* * * * *

(8) Whether destruction occurs at the facility or 

off-site. If destruction occurs at the facility, also 

report whether a back-up destruction device is present at 

the facility, the annual operating hours for the primary 

destruction device, the annual operating hours for the 

back-up destruction device (if present), the destruction 

efficiency for the primary destruction device, and the 

destruction efficiency for the back-up destruction device 

(if present). 

* * * * *

Subpart OO—[Amended]

25. Section 98.416 is amended by removing and 

reserving paragraphs (a)(8) and (a)(9) and revising 

paragraph (a)(10) to read as follows: 

§98.416 Data reporting requirements.

* * * * *

(a) * * *

(8) [Reserved]

(9) [Reserved]

(10) Mass in metric tons of any fluorinated GHG or 

nitrous oxide fed into the transformation process, by 

process. 

* * * * *
136 of 157

26. Section 98.417 is amended by adding paragraphs 

(a)(3) and (a)(4) to read as follows:

§ 98.417 Records that must be retained.

(a) * * *

(3) Dated records of the total mass in metric tons of 

each reactant fed into the F–GHG or nitrous oxide 

production process, by process.

(4) Dated records of the total mass in metric tons of 

the reactants, by-products, and other wastes permanently 

removed from the F–GHG or nitrous oxide production process, 

by process. 

* * * * *

Subpart RR-[Amended]

27. Section 98.442 is amended by revising paragraphs 

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

§98.442 GHGs to report.

* * * * *

(e) Mass of CO2 emissions from equipment leaks and 

vented emissions of CO2 from surface equipment located 

between the injection flow meter and the injection 

wellhead.

(f) Mass of CO2 emissions from equipment leaks and 

vented emissions of CO2 from surface equipment located 
137 of 157

between the production flow meter and the production 

wellhead.

* * * * *

28. Section 98.443 is amended by:

a. Revising paragraph (d) introductory text.

b. Revising paragraph (d)(3).

c. Revising the definition of “CO2FI” and “CO2FP” in 

Equation RR-11 of paragraph (f)(1).

d. Revising the definition of “CO2FI” in Equation RR12 of paragraph (f)(2).

§98.443 Calculating CO2 geologic sequestration.

* * * * *

(d) You must calculate the annual mass of CO2 produced 

from oil or gas production wells or from other fluid wells 

for each separator that sends a stream of gas into a 

recycle or end use system in accordance with the procedures 

specified in paragraphs (d)(1) through (d)(3) of this 

section. You must account for any CO2 that is produced and 

not processed through a separator. You must account only 

for wells that produce the CO2 that was injected into the 

well or wells covered by this source category.

* * * * *

(3) To aggregate production data, you must sum the 

mass of all of the CO2 separated at each gas-liquid 
138 of 157

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(d)(5).

* * * * *

(f) * * *

(1) * * *

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.
139 of 157

CO2FP = Total annual CO2 mass emitted (metric tons) 

from equipment leaks and vented emissions of CO2

from equipment located on the surface between the 

production wellhead and the flow meter used to 

measure production quantity, for which a 

calculation procedure is provided in subpart W of 

this part.

* * * * *

(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.

29. Section 98.444 is amended by revising the header 

of paragraph (d) to read as follows:

§98.444 Monitoring and QA/QC requirements.

* * * * *

(d) CO2 emissions from equipment leaks and vented 

emissions of CO2. * * *

* * * * *

30. Section 98.445 is amended by revising paragraph 

(e) to read as follows:

§98.445 Procedures for estimating missing data.

* * * * *

(e) For any values associated with CO2 emissions from 

equipment leaks and vented emissions of CO2 from surface 

equipment at the facility that are reported in this 

subpart, missing data estimation procedures should be 
140 of 157

followed in accordance with those specified in subpart W of 

this part.

* * * * *

31. Section 98.446 is amended by:

a. Revising paragraph (a)(2) introductory text and 

(a)(3) introductory text.

b. Revising paragraph (e).

c. Revising paragraph (f) introductory text.

d. Revising paragraph (f)(1)(vii). 

e. Revising paragraphs (f)(3) introductory text, 

(f)(3)(i), and (f)(3)(ii).

§98.446 Data reporting requirements.

* * * * *

(a) * * *

(2) If a volumetric flow meter is used to receive CO2

report the following unless you reported yes to paragraph 

(a)(4) of this section:

* * * * *

(3) If a mass flow meter is used to receive CO2 report 

the following unless you reported yes to paragraph (a)(4) 

of this section: 

* * * * *
141 of 157

(e) Report the date that you began collecting data 

for calculating total amount sequestered according to 

§98.448(a)(7) of this subpart. 

(f) Report the following. If the date specified in 

paragraph (e) of this section is during the reporting year 

for this annual report, report the following starting on 

the date specified in paragraph (e) of this section.

(1) * * *

(vii) The standard used to calculate each value in 

paragraphs (f)(1)(ii) through (f)(1)(iv) of this section.

* * * * *

(3) For CO2 emissions from equipment leaks and vented 

emissions of CO2, report the following: 

(i) The mass of CO2 emitted (in metric tons) annually 

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.

(ii) The mass of CO2 emitted (in metric tons) annually 

from equipment leaks and vented emissions of CO2 from 

equipment located on the surface between the production 

wellhead and the flow meter used to measure production 

quantity.

* * * * *
142 of 157

32. Section 98.447 is amended by revising paragraphs 

(a)(5) and (a)(6) to read as follows:

§98.447 Records that must be retained.

(a) * * *

(5) Annual records of information used to calculate 

the CO2 emitted 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. 

(6) Annual records of information used to calculate 

the CO2 emitted from equipment leaks and vented emissions of 

CO2 from equipment located on the surface between the 

production wellhead and the flow meter used to measure 

production quantity.

* * * * *

33. Section 98.448 is amended by revising paragraphs 

(a)(5) and (e) to read as follows:

§98.448 Geologic sequestration monitoring, reporting, and 

verification (MRV) plan. 

(a) * * *

(5) A summary of the considerations you intend to use 

to calculate site-specific variables for the mass balance 

equation. This includes, but is not limited to, 

considerations for calculating CO2 emissions from equipment 
143 of 157

leaks and vented emissions of CO2 between the injection flow 

meter and injection well and/or the production flow meter 

and production well, and considerations for calculating CO2

in produced fluids. 

* * * * *

(e) Revised MRV plan. The requirements of paragraph 

(c) of this section apply to any submission of a revised 

MRV plan. You must continue reporting under your currently 

approved plan while awaiting approval of a revised MRV 

plan. 

* * * * *

34. Section 98.449 is amended by revising the 

definition of “CO2 received” to read as follows:

§98.449 Definitions.

* * * * *

CO2 received means the CO2 stream that you receive to 

be injected for the first time into a well on your facility 

that is covered by this subpart. CO2 received includes, but 

is not limited to, a CO2 stream from a production process 

unit inside your facility and a CO2 stream that was injected 

into a well on another facility, removed from a 

discontinued enhanced oil or natural gas or other 

production well, and transferred to your facility.

* * * * *
144 of 157

Subpart TT-[Amended]

35. Section 98.460 is amended by revising paragraphs 

(c)(1) and (c)(2)(i) to read as follows:

§98.460 Definition of the source category.

* * * * *

(c) * * *

(1) Construction and demolition waste landfills. 

(2) * * *

(i) Coal combustion or incinerator ash (e.g., fly 

ash).

* * * * *

36. Section 98.463 is amended by:

a. In paragraph (a)(1), revising Equation TT-1 and 

revising the definitions of “GCH4”, “DOCx”, “MCF”, and “Fx”.

b. Revising paragraph (a)(2) introductory text.

c. Revising paragraph (a)(2)(ii)(C).

d. In paragraph (a)(2)(ii)(C), revising the 

definitions of “Wx”, “LFC”, and “YrData” in Equation TT-4.

§98.463 Calculating GHG emissions.

(a) * * *

(1) * * *

  























        





    

1

( 1) ( )

4

12

16 T

x S

k T x k T x

CH x x F G W DOC MCF DOC F e e (Eq. TT-1)

Where:
145 of 157

GCH4 = Modeled methane generation in reporting year T 

(metric tons CH4).

* * * * *

DOCx = Degradable organic carbon for waste disposed 

in year X from Table TT-1 of this subpart or 

from measurement data [as specified in 

paragraph (a)(3) of this section], if 

available [fraction (metric tons C/metric ton 

waste)]. 

* * * * *

MCF = Methane correction factor (fraction). Use the 

default value of 1 unless there is active 

aeration of waste within the landfill during 

the reporting year. If there is active 

aeration of waste within the landfill during 

the reporting year, use either the default 

value of 1 or select an alternative value no 

less than 0.5 based on site-specific aeration 

parameters.

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) Waste stream quantities. Determine annual waste 

quantities as specified in paragraphs (a)(2)(i) through 

(ii) of this section for each year starting with January 1, 

1960 or the year the landfills first accepted waste if 

after January 1, 1960, up until the most recent reporting 

year. The choice of method for determining waste 

quantities will vary according to the availability of 

historical data. Beginning in the first emissions 

reporting year (2011 or later) and for each year 
146 of 157

thereafter, use the procedures in paragraph (a)(2)(i) of 

this section to determine waste stream quantities. These 

procedures should also be used for any year prior to the 

first emissions reporting year for which the data are 

available. For other historical years, use paragraph 

(a)(2)(i) of this section, where waste disposal records are 

available, and use the procedures outlined in paragraph 

(a)(2)(ii) of this section when waste disposal records are 

unavailable, to determine waste stream quantities. 

Historical disposal quantities deposited (i.e, prior to the 

first year in which monitoring begins) should only be 

determined once, as part of the first annual report, and 

the same values should be used for all subsequent annual 

reports, supplemented by the next year’s data on new waste 

disposal. 

* * * * *

(ii) * * *

(C) For any year in which historic production or 

processing data are not available such that historic waste 

quantities cannot be estimated using Equation TT-3 of this 

section, calculate an average annual bulk waste disposal 

quantity using Equation TT-4 of this section. 

* * * * *
147 of 157

Wx = Quantity of waste placed in the landfill in 

year X (metric tons, wet basis). This annual 

bulk waste disposal quantity applies for all 

years from “YrOpen” to “YrData” inclusive.

LFC = Capacity of the landfill used (or the total 

quantity of waste-in-place) at the end of the 

“YrData” from design drawings or engineering 

estimates (metric tons). For closed landfills 

for which waste quantity data are not available, 

use the landfill’s design capacity.

YrData = The year prior to the year when waste disposal 

data are first available from company records or 

from Equation TT-3 of this section. For 

landfills for which waste quantity data are not 

available, the year in which the landfill last 

received waste.

* * * * *

37. Section 98.464 is amended by:

a. Revising paragraph (b) introductory text.

b. Revising paragraph (b)(1).

c. Revising paragraph (b)(3).

d. In paragraph (b)(4), revising the first sentence, 

redesignating Equation TT-8 as Equation TT-7, and revising 

the definition of “% Volatile Solidsx” and “% Total 

Solidsx”.

e. Redesignating paragraphs (c), (d), and (e) as 

paragraphs (d), (e), and (f), respectively.

f. Adding paragraph (c). 

g. Adding paragraph (g).

h. Redesignating paragraph (f) as paragraph (h). 

§98.464 Monitoring and QA/QC requirements. 
148 of 157

* * * * *

(b) For each waste stream received during the 

reporting year for which you choose to determine volatile 

solids concentration for the purposes of §98.460(c)(2)(xii) 

or choose to determine a landfill-specific DOCx for use in 

Equation TT-1 of this subpart, 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.

(1) Develop and follow a sampling plan to collect a 

representative sample of each waste stream (as received at 

the landfill) for which testing is elected.

* * * * *

(3) For the purposes of §98.460(c)(2)(xii), the 

volatile solids concentration (weight percent on a dry 

basis) is the percent volatile solids determined using 

Standard Method 2540G “Total, Fixed, and Volatile Solids in 

Solid and Semisolid Samples” (incorporated by reference; 

see §98.7). 

(4) Calculate the waste stream-specific DOCx value 

using Equation TT-7 of this section.

 

100%

% TotalSolids

100%

% VolatileSolids DOC F

x x

x  DOC   (Eq. TT-7) 

* * * * *
149 of 157

% Volatile Solidsx = Percent volatile solids determined 

using Standard Method 2540G Total, 

“Fixed, and Volatile Solids in Solid 

and Semisolid Samples” (incorporated by 

reference; see §98.7) for Year X 

[milligrams (mg) volatile solids per 

100 mg dried solids]. 

% Total Solidsx = Percent total solids determined using 

Standard Method 2540G “Total, Fixed, 

and Volatile Solids in Solid and 

Semisolid Samples” (incorporated by 

reference; see §98.7) for Year X (mg 

dried solids per 100 mg wet waste).

(c) For each waste stream for which you choose to 

determine volatile solids concentration for the purposes of 

paragraph §98.460(c)(2)(xii), and that was historically 

managed in the landfill but was not received during the

first reporting year, you must determine volatile solids 

concentration 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 of the 

similar waste stream using the procedures in paragraphs 

(b)(1) through (b)(3) 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 of the historically managed waste stream 
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using process knowledge. You must document the basis for 

volatile solids concentration as determined through process 

knowledge. 

(d) For landfills with gas collection systems, 

operate, maintain, and calibrate a gas composition monitor 

capable of measuring the concentration of CH4 according to 

the requirements specified at §98.344(b).

(e) For landfills with gas collection systems, 

install, operate, maintain, and calibrate a gas flow meter 

capable of measuring the volumetric flow rate of the 

recovered landfill gas according to the requirements 

specified at §98.344(c). 

(f) For landfills with gas collection systems, all 

temperature, pressure, and if applicable, moisture content 

monitors must be calibrated using the procedures and 

frequencies specified by the manufacturer. 

(g) For landfills electing to measure the fraction by 

volume of CH4 in landfill gas (F), follow the requirements 

in paragraphs (g)(1) and (g)(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 at §98.344(b). You must either 

use a gas composition monitor that is also capable of 
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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 TT-8 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 TT-1 

of this part. 

 























2

4

20.9 %

20.9

100% O

C

F

CH c

(Eq. TT-8)

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).

(h) The facility shall document the procedures used 

to ensure the accuracy of the estimates of disposal 
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quantities and, if the industrial waste landfill has a gas 

collection system, 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.

38. Section 98.466 is amended by:

a. Revising paragraph (b) introductory text.

b. Revising paragraph (b)(2).

c. Adding paragraphs (b)(3) and (b)(4). 

d. Revising paragraph (c)(3)(ii).

e. Revising paragraph (d).

f. Revising paragraph (f).

g. Revising paragraph (g)(1). 

§98.466 Data reporting requirements. 

* * * * *

(b) Report the following waste characterization and 

modeling information:

* * * * *

(2) A description of each waste stream (including the 

types of materials in each waste stream) for which Equation 
153 of 157

TT-1 of this subpart is used to calculate modeled CH4

generation.

(3) The fraction of CH4 in the landfill gas, F, 

(volume fraction, dry basis, corrected to 0% oxygen) for 

the reporting year and an indication as to whether this was 

the default value or a value determined through measurement 

data. 

(4) The methane correction factor (MCF) value used in 

the calculations. If an MCF value other than the default 

of 1 is used, provide a description of the aeration system, 

including aeration blower capacity, the fraction of the 

landfill containing waste affected by the 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.

(c) * * *

(3) * * *

(ii) The year, the waste disposal quantity and 

production quantity for each year used in Equation TT-2 of 

this subpart to calculate the average waste disposal factor 

(WDF).

* * * * *
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(d) For each year of landfilling starting with the 

“Start Year” (S) and each year thereafter up to the current 

reporting year, report the following information:

(1) The calendar year for which the following data 

elements apply. 

(2) The quantity of waste (Wx) disposed of in the 

landfill (metric tons, wet weight) for the specified year 

for each waste stream identified in paragraph (b) of this 

section.

(3) 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 of this 

subpart or a value determined through sampling and 

calculation for each waste stream identified in paragraph 

(b) of this section. 

* * * * *

(f) The modeled annual methane generation (GCH4) for 

the reporting year (metric tons CH4) calculated using 

Equation TT-1 of this subpart.

(g) * * *

(1) The annual methane emissions (i.e., the methane 

generation (MG), adjusted for oxidation, calculated using 

Equation TT-6 of this subpart), reported in metric tons CH4. 

* * * * *
155 of 157

39. Section 98.467 is amended to read as follows:

§98.467 Records that must be retained. 

In addition to the information required by §98.3(g), 

you must retain the calibration records for all monitoring 

equipment, including the method or manufacturer’s 

specification used for calibration, and all total and 

volatile solids concentration measurement data used for the 

purposes of paragraph §98.460(c)(2)(xii) or used to

determine landfill-specific DOCx values. 

40. Section 98.468 is amended by adding the 

definitions for “Construction and demolition (C&D) waste 

landfill” and “Design capacity” to read as follows:

§98.468 Definitions.

* * * * *

Construction and demolition (C&D) waste landfill means 

a solid waste disposal facility subject to the requirements 

of subparts A or B of part 257 of this chapter that 

receives construction and demolition waste and does not 

receive hazardous waste (defined in § 261.3 of this 

chapter) or industrial solid waste (defined in § 258.2 of 

this chapter) or municipal solid waste (defined in § 98.6 

of this part) other than residential lead-based paint 

waste. A C&D waste landfill typically receives any one or 

more of the following types of solid wastes: roadwork 
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material, excavated material, demolition waste, 

construction/renovation waste, and site clearance waste.

Design capacity means the maximum amount of solid 

waste a landfill can accept, as indicated 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 the design capacity from volume to mass to 

determine its design capacity, the calculation must include 

a site specific density, which must be recalculated 

annually.

* * * * *

41. Table TT-1 of Subpart TT is amended by revising 

the entries for “Construction and Demolition” and “Inert 

Waste [i.e., wastes listed in §98.460(c)(2)]” to read as 

follows:

Table TT-1 of Subpart TT—Default DOC and Decay Rate Values 

for Industrial Waste Landfills

Industry/Waste Type

DOC 

(weight 

fraction, 

wet basis)

k

[dry 

climatea] 

(yr-1)

k

[moderate 

climatea] 

(yr-1)

k

[wet 

climatea] 

(yr-1)

* * * * * * *

Construction and Demolition 0.08 0.02 0.03 0.04

Inert Waste [i.e., wastes 

listed in §98.460(c)(2)]

0 0 0 0

* * * * * * *

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 
157 of 157

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.