6560.50 

ENVIRONMENTAL PROTECTION AGENCY 

40 CFR Part 98 

[EPA-HQ-OAR-2008-0508; FRL- ] 

RIN 2060-AQ03 

Mandatory Reporting of Greenhouse Gases from Magnesium 

Production, Underground Coal Mines, Industrial Wastewater 

Treatment, and Industrial Waste Landfills 

AGENCY: Environmental Protection Agency (EPA). 

ACTION: Final Rule. 

SUMMARY: EPA is promulgating a regulation to require 

monitoring and reporting of greenhouse gas emissions from 

magnesium production, underground coal mines, industrial 

wastewater treatment, and industrial waste landfills. This 

action adds these four source categories to the list of 

source categories already required to report greenhouse gas 

emissions under 40 CFR part 98. This action requires 

monitoring and reporting of greenhouse gases for these 

source categories only for sources with carbon dioxide 

equivalent emissions above certain threshold levels as 

described in this regulation. This action does not require 

control of greenhouse gases. 

DATES: The final rule is effective on [INSERT THE 

DATE 60 DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER]. 

The incorporation by reference of certain publications 

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programRule (

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listed in the rule is approved by the Director of Federal 

Register as of [INSERT THE DATE 60 DAYS AFTER PUBLICATION 

IN THE FEDERAL REGISTER]. 

ADDRESSES: EPA established a single docket under 

Docket ID No. EPA-HQ-OAR-2008-0508 for this action and for 

the previous action promulgated October 30, 2009 (74 FR 

56260). All documents in the docket are listed on the 

www.regulations.gov website. Although listed in the index, 

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

confidential business information (CBI) or other 

information whose disclosure is restricted by statute. 

Certain other material, such as copyrighted material, is 

not placed on the Internet and will be publicly available 

only in hard copy form. Publicly available docket 

materials are available either electronically through 

www.regulations.gov or in hard copy at EPA’s Docket Center, 

Public Reading Room, EPA West Building, Room 3334, 1301 

Constitution Avenue, NW, Washington, DC 20004. This Docket 

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

through Friday, excluding legal holidays. The telephone 

number for the Public Reading Room is (202) 566-1744, and 

the telephone number for the Air Docket is (202) 566-1741. 

FOR FURTHER GENERAL INFORMATION CONTACT: Carole Cook, 

Climate Change Division, Office of Atmospheric Programs 

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(MC-6207J), Environmental Protection Agency, 1200 

Pennsylvania Ave., NW, Washington, DC 20460; telephone 

number: (202) 343-9263; fax number: (202) 343-2342; e-mail 

address: GHGReportingRule@epa.gov. For technical 

information and implementation materials, please go to the 

website 

www.epa.gov/climatechange/emissions/ghgrulemaking.html. To

submit a question, select Rule Help Center, followed by 

Contact Us.

SUPPLEMENTARY INFORMATION:

Regulated Entities. The Administrator determined that 

this action is subject to the provisions of Clean Air Act 

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

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

as the Administrator may determine.”). The final rule 

affects underground coal mines, magnesium production, 

industrial waste landfills, and industrial wastewater 

treatment facilities that are direct emitters of greenhouse 

gases (GHGs). Regulated categories and entities include 

those listed in Table 1 of this preamble: 

Table 1. Examples of Affected Entities by Category 

Category NAICS Examples of affected facilities 

331419 Primary refiners of nonferrous 

metals by electrolytic methods. 

Magnesium 

Production 

331492 Secondary magnesium processing 

plants. 

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the Greenhouse Gas Reporting 

Rule Hotline at telephone 

number: (877) 444-1188; or 

e-mail: 

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Category NAICS Examples of affected facilities 

Underground Coal 

Mines 

212113 Underground anthracite coal mining 

operations. 

212112 Underground bituminous coal mining 

operations. 

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. 

Industrial Waste 

Landfills 

221320 Sewage treatment facilities. 

322110 Pulp mills. 

322121 Paper mills. 

322122 Newsprint mills. 

322130 Paperboard mills. 

311611 Meat processing facilities. 

311411 Frozen fruit, juice, and vegetable 

manufacturing facilities. 

311421 Fruit and vegetable canning 

facilities. 

325193 Ethanol manufacturing facilities. 

Industrial 

Wastewater 

Treatment 

324110 Petroleum refineries. 

Table 1 of this preamble is not intended to be 

exhaustive, but rather provides a guide for readers 

regarding facilities likely to be affected by this action. 

Although Table 1 of this preamble lists the types of 

facilities that EPA is now aware could be potentially 

affected by the reporting requirements, other types of 

facilities not listed in the table could also be subject to 

reporting requirements. To determine whether you are 

affected by this action, you should carefully examine the 

applicability criteria found in 40 CFR part 98, subpart A 
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as amended by this action. If you have questions regarding 

the applicability of this action to a particular facility, 

consult the person listed in the preceding “FOR FURTHER 

INFORMATION CONTACT” section. 

Many facilities affected by this final rule have GHG 

emissions from other source categories listed in 40 CFR 

part 98. Table 2 of this preamble has been developed as a 

guide to help reporters affected by this action identify 

other source categories (by subpart) that they may need to 

(1) consider in their facility applicability determination, 

and (2) include in their reporting. Table 2 of this 

preamble identifies the subparts that are likely to be 

relevant to sources with magnesium production, underground 

coal mines, industrial wastewater treatment, and industrial 

waste landfills. The table should only be seen as a guide. 

Additional subparts in 40 CFR part 98 may be relevant for a 

given reporter, while some subparts listed in Table 2 of 

this preamble may not be relevant to all reporters in these 

source categories. 

Table 2. Source Categories and Relevant Subparts 

Source category 

(and main applicable 

subpart) 

Other Subparts in 40 CFR part 98 

recommended for review to determine 

applicability 

Magnesium Production Subpart C: General Stationary Fuel 

Combustion. 

Underground Coal Mines Subpart C: General Stationary Fuel 

Combustion. 
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Source category 

(and main applicable 

subpart) 

Other Subparts in 40 CFR part 98 

recommended for review to determine 

applicability 

Subpart C: General Stationary Fuel 

Combustion. 

Subpart Y: Petroleum Refineries. 

Subpart AA: Pulp and Paper 

Manufacturing. 

Industrial Waste 

Landfills1 2 3 4 5 6

a

Subpart II: Industrial Wastewater 

Treatment 

Subpart C: General Stationary Fuel 

Combustion. 

Subpart Y: Petroleum Refineries. 

Subpart AA: Pulp and Paper 

Manufacturing. 

Industrial Wastewater 

Treatment 

Subpart TT: Industrial Waste 

Landfills 

a The industrial landfills source category was proposed with municipal 

solid waste landfills under 40 CFR part 98, subpart HH in the April 10, 

2009 proposal (74 FR 16448). However, EPA has since decided to separate 

landfills into two subparts: subpart HH for municipal solid waste 

landfills (promulgated October 30, 2009 (74 FR 56374) and subpart TT 

for industrial waste landfills.

Judicial Review.

Under CAA section 307(b)(1), judicial review of this 

final rule is available only by filing a petition for 

review in the U.S. Court of Appeals for the District of 

Columbia Circuit by [INSERT THE DATE 60 DAYS AFTER 

PUBLICATION IN THE FEDERAL REGISTER]. Under CAA section 

307(d)(7)(B), only an objection to this final rule that was 

raised with reasonable specificity during the period for 

public comment can be raised during judicial review. This 

section also provides a mechanism for us to convene a 

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proceeding for reconsideration, “[i]f the person raising an 

objection can demonstrate to EPA that it was impracticable 

to raise such objection within [the period for public 

comment] or if the grounds for such objection arose after 

the period for public comment (but within the time 

specified for judicial review) and if such objection is of 

central relevance to the outcome of this rule.” Any person 

seeking to make such a demonstration to us should submit a 

Petition for Reconsideration to the Office of the 

Administrator, Environmental Protection Agency, Room 3000, 

Ariel Rios Building, 1200 Pennsylvania Ave., NW., 

Washington, DC 20004, with a copy to the person listed in 

the preceding FOR FURTHER INFORMATION CONTACT section, and 

the Associate General Counsel for the Air and Radiation Law 

Office, Office of General Counsel (Mail Code 2344A), 

Environmental Protection Agency, 1200 Pennsylvania Ave., 

NW., Washington, DC 20004. Note, under CAA section 

307(b)(2), the requirements established by this final rule 

may not be challenged separately in any civil or criminal 

proceedings brought by EPA to enforce these requirements. 

Acronyms and Abbreviations. The following acronyms 

and abbreviations are used in this document. 

ASME American Society of Mechanical Engineers 

ASTM American Society for Testing and Materials 

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BAMM Best Available Monitoring Methods 

BOD5 5-day biochemical oxygen demand 

CAA Clean Air Act 

CBI confidential business information 

CEMS continuous emission monitoring system(s) 

CERCLA Comprehensive Environmental Response, 

Compensation, and Liability Act 

cf cubic feet 

CFR Code of Federal Regulations 

CH4 methane 

CO2 carbon dioxide 

CO2e CO2-equivalent 

COD chemical oxygen demand 

DOC Degradable organic carbon

EIA economic impact analysis

EO Executive Order 

EPA U.S. Environmental Protection Agency 

FK 5-1-12 dodecafluoro-2-methylpentan-3-one (or NovecTM 612) 

GHG greenhouse gas

HCFC-22 chlorodifluoromethane (or CHClF2) 

HFC-23 trifluoromethane (or CHF3) 

HFCs hydrofluorocarbons 

HFEs hydrofluorinated ethers 

ICR information collection request 

kg kilograms 

MSHA Mine Safety and Health Administration 

MSW municipal solid waste 

N2O nitrous oxide 

NAICS North American Industry Classification System 

NPDES National Pollution Discharge Elimination System 

NTTAA National Technology Transfer and Advancement Act 

of 1995 

OMB Office of Management and Budget 

PFCs perfluorocarbons 

QA/QC quality assurance/quality control 

RCRA Resource Conservation and Recovery Act 

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New

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GGRR Greenhouse Gas 

Reporting Rule

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GWP global warming potential¶

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British thermal units per 

hour¶

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trifluoride ¶

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RFA Regulatory Flexibility Act 

RIA regulatory impact analysis 

SBREFA Small Business Regulatory Enforcement Fairness 

Act 

scf standard cubic feet

scfm standard cubic feet per minute 

SF6 sulfur hexafluoride 

TSCA Toxic Substances Control Act 

U.S. United States 

UMRA Unfunded Mandates Reform Act of 1995 

VOC volatile organic compound(s) 

TABLE OF CONTENTS 

I. Background 

A. Organization of this Preamble 

B. Background on the Final Rule 

C. Legal Authority 

II. Reporting Requirements for Magnesium Production, 

Underground Coal Mines, Industrial Wastewater Treatment,

and Industrial Waste Landfills.

A. Overview 

B. Summary of Changes to the General Provisions of 40 CFR 

part 98

C. Magnesium Production (40 CFR part 98, subpart T) 

D. Underground Coal Mines (40 CFR part 98, subpart FF) 

E. Industrial Wastewater Treatment (40 CFR part 98, 

subpart II) 

F. Industrial Waste Landfills (40 CFR part 98, subpart TT) 

III. Other Source Categories Proposed in 2009

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A. Overview 

B. Ethanol Production 

C. Food Processing 

D. Suppliers of Coal 

IV. Economic Impacts of the Rule 

A. How were compliance costs estimated? 

B. What are the costs of the rule? 

C. What are the economic impacts of the rule? 

D. What are the impacts of the rule on small businesses? 

E. What are the benefits of the rule for society? 

V. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory Planning and Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act (RFA) 

D. Unfunded Mandates Reform Act (UMRA) 

E. Executive Order 13132: Federalism 

F. Executive Order 13175: Consultation and Coordination 

with Indian Tribal Governments 

G. Executive Order 13045: Protection of Children from 

Environmental Health Risks and Safety Risks 

H. Executive Order 13211: Actions that Significantly 

Affect Energy Supply, Distribution, or Use 

I. National Technology Transfer and Advancement Act 

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J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and LowIncome Populations 

K. Congressional Review Act 

I. Background 

A. Organization of this Preamble

This preamble consists of five sections. The first 

section provides a brief history of 40 CFR part 98 and 

describes the purpose and legal authority for today’s 

action. 

The second section of this preamble summarizes the 

revisions made to the general provisions in 40 CFR part 98, 

subpart A and outlines the specific requirements for the 

four new source categories being incorporated into 40 CFR 

part 98 by this action. It also describes the major 

changes made to these source categories since proposal and 

provides a brief summary of significant public comments and 

EPA’s responses on issues specific to each source category. 

The third section of this preamble summarizes and 

provides our rationale for the decisions not to include two 

source categories as distinct subparts in 40 CFR part 98 

and not to include reporting requirements for one 

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additional proposed source category under 40 CFR part 98 at 

this time. 

The fourth section of this preamble provides the 

summary of the cost impacts, economic impacts, and benefits 

of the final rule and discusses comments on the regulatory 

impacts analyses for the four additional source categories. 

Finally, the last section discusses the various 

statutory and executive order requirements applicable to 

this rulemaking. 

B. Background on the Final Rule

Today’s action finalizes monitoring and reporting 

requirements for the following four source categories: 

magnesium production, underground coal mines, industrial 

waste landfills2

, and industrial wastewater treatment. With 

today’s action EPA has decided not to include ethanol 

production and food processing as distinct subparts. 

Lastly, EPA has made the final decision not to include any 

reporting requirements for suppliers of coal at this time. 

These source categories were proposed on April 10, 

2009 (74 FR 16448) as part of a larger rulemaking effort to 

establish a GHG reporting program for all sectors of the 

 

2 The industrial landfills source category was proposed with municipal solid 

waste landfills under 40 CFR part 98, subpart HH in the April 10, 2009 proposal 

(74 FR 16448). However, EPA has since decided to separate landfills into two 

subparts: subpart HH for municipal solid waste landfills (promulgated October 

30, 2009 (74 FR 56374)) and subpart TT for industrial landfills. 

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economy. This rulemaking was initiated by EPA in response 

to the fiscal year 2008 Consolidated Appropriations Act 

(Appropriations Act).3

 This Act authorized funding for EPA 

to develop and publish a rule “...to require mandatory 

reporting of greenhouse gas emissions above appropriate 

thresholds in all sectors of the economy of the United 

States.” An accompanying joint explanatory statement 

directed EPA to "use its existing authority under the Clean 

Air Act" to develop a mandatory GHG reporting rule. 

EPA proposed 40 CFR part 98 on April 10, 2009 (74 FR 

16448) and held two public hearings in April 2009. The 

public comment period ended on June 9, 2009. The final 40 

CFR part 98 was signed by EPA’s Administrator on September 

22, 2009 and published in the Federal Register on October 

30, 2009 (74 FR 56260). The October 2009 Final Rule, which 

became effective on December 29, 2009, included reporting 

requirements for facilities and suppliers in 31 subparts. 

The April 2009 proposal, however, included monitoring and 

reporting requirements for a further eleven source 

categories that were not finalized in the October 30, 2009 

action. This action includes monitoring and reporting 

 

3

 Consolidated Appropriations Act, 2008, Public Law No.110-161, 121 Stat 1844, 

2128. Congress reaffirmed interest in a GHG reporting rule, and provided 

additional funding, in the 2009 and 2010 Appropriations Acts (Consolidated 

Appropriations Act, 2009, Public Law 110-329, 122 Stat. 3574-3716 and 

Consolidated Appropriations Act, 2010, Public Law 111-117, 123 Stat. 3034-

3408). 

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requirements for four of the eleven source categories

(subpart T - Magnesium Production, subpart FF - Underground 

Coal Mines, subpart II - Industrial Wastewater Treatment, 

and subpart TT - Industrial Waste Landfills) that were 

proposed but not finalized in the October 30, 2009 action, 

and amends the general provisions for 40 CFR part 98, 

subpart A. This action also provides EPA’s final decision 

not to include ethanol production and food processing as 

distinct subparts in 40 CFR part 98, as well as the final 

decision not to include suppliers of coal in 40 CFR part 98

at this time4. 

During the comment period, EPA received a number of 

detailed comments on the proposal, including comments 

specific to the proposed subparts for ethanol production, 

food processing, underground coal mines, industrial waste 

landfills, industrial wastewater treatment, and suppliers 

of coal. EPA decided to delay finalizing the reporting 

requirements for these source categories to allow for 

additional time to review public comments, perform 

additional analysis, and consider modifications and 

alternatives to the proposed methodologies. Changes made 

 

4 The remaining four source categories included in the April 2009 proposal but 

not included here are being reproposed in Proposed Mandatory Reporting of 

Greenhouse Gases: Petroleum and Natural Gas Systems(75 FR 18608, April 12, 

2010) and Proposed Mandatory Reporting of Greenhouse Gases: Additional Sources 

of Fluorinate GHGs (75 FR 18652, April 12, 2010).

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(Magnesium Production), 

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Mines), subpart II 

(Industrial Wastewater 

Treatment), and subpart TT 

(Industrial Waste Landfills)

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to the proposed requirements and significant comments 

received during the public comment period for 40 CFR part 

98, subparts FF, II, and TT are described in more detail in 

the discussions of the individual source categories 

included in Section II of this preamble. 

Upon further consideration, EPA decided not to include 

distinct subparts for ethanol production and food 

processing in 40 CFR part 98 because these facilities will 

already be covered under the rule due to their aggregate 

emissions from all applicable source categories in the 

rule, such as stationary combustion, industrial wastewater, 

industrial waste landfills, miscellaneous use of 

carbonates, and any others that may apply. Moreover, EPA 

has also decided to not include coal suppliers in 40 CFR 

part 98 because the vast majority of emissions from 

combustion of coal in the United States is already covered 

by the rule through reporting by direct emitters. Further 

explanation of these decisions is provided in more detail 

in the discussions of the proposed individual source 

categories in Section III of this preamble. 

Summaries of comments on other aspects of the 

reporting rule, such as the verification approach and 

selection of source categories, are included and were 

responded to in the preamble to the October 2009 Final Rule

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(74 FR 56260, October 30, 2009) and in volumes 1 through 14 

of “Mandatory Greenhouse Gas Reporting Rule: EPA’s Response 

to Public Comments”. 

C. Legal Authority

EPA is finalizing 40 CFR part 98, subparts T, FF, II, 

and TT under the existing CAA authorities provided in CAA 

section 114. As discussed in detail in Sections I.C and 

II.Q of the preamble to the 2009 final rule (74 FR 56260, 

October 30, 2009), CAA section 114(a)(1) provides EPA with 

broad authority to require emissions sources, persons 

subject to the CAA, manufacturers of process or control 

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. EPA may gather information for a variety of 

purposes, including for the purpose of assisting in the 

development of emissions standards under CAA section 111, 

determining compliance with implementation plans or such 

standards, or more broadly for “carrying out any provision” 

of the CAA. Section 103 of the CAA authorizes EPA to 

establish a national research and development program, 

including nonregulatory approaches and technologies, for 

the prevention and control of air pollution, including

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GHGs. As discussed in the proposal (74 FR 16448, April 10, 

2009), among other things, data from magnesium production, 

underground coal mines, industrial wastewater treatment, 

and industrial waste landfills will inform decisions about 

whether and how to use CAA section 111 to establish new 

source performance standards (NSPS) for these four source 

categories, including whether there are any additional 

categories of sources that should be listed under CAA 

section 111(b). The data collected will also inform EPA’s 

implementation of CAA section 103(g) regarding improvements 

in sector based nonregulatory strategies and technologies 

for preventing or reducing air pollutants. 

II. Reporting Requirements for Magnesium Production, 

Underground Coal Mines, Industrial Wastewater Treatment, 

and Industrial Waste Landfills. 

A. Overview

40 CFR part 98 requires reporting of GHG emissions and 

supply from all sectors of the economy, including fossil 

fuel suppliers, industrial gas suppliers, and direct 

emitters of GHGs. It covers various GHGs, including carbon 

dioxide (CO2), methane (CH4), nitrous oxide (N2O), 

hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), sulfur 

hexafluoride (SF6), and other fluorinated compounds (e.g., 

hydrofluoroethers (HFEs)). The rule requires that source 

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categories subject to the rule monitor and report GHGs in 

accordance with the methods specified in the individual 

subparts. For a list of the specific GHGs to be reported 

and the GHG calculation procedures, monitoring, missing 

data procedures, recordkeeping, and reporting required by 

facilities subject to each of the four subparts included in 

today’s action, see Section II.C through II.F of this 

preamble. 

In order to meet the quality assurance and 

verification requirements of the rule, EPA is establishing 

an electronic reporting system to facilitate collection of 

data under this rule. All facilities that are covered 

under 40 CFR part 98, including those subject to the 

reporting requirements in 40 CFR part 98, subparts T, FF, 

II, and TT will use this data system to submit required 

data. 

B. Summary of Changes to the General Provisions of 40 CFR 

part 98 

Today’s action amends certain requirements in 40 CFR 

part 98, subpart A (General Provisions). These amendments 

are summarized in this section of the preamble and apply 

only to those subparts included in this action. Other than 

the changes to format discussed immediately below, none of 

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the amendments change the general provisions applicable to 

those subparts already incorporated into 40 CFR part 98. 

Changes to Format. On March 16, 2010, EPA published 

both a direct final rule and concurrent proposal (75 FR 

12451 and 75 FR 12489) that made minor changes to the 

format of several sections of the general provisions to 

accommodate the addition of new subparts in the future in a 

simple and clear manner. The changes included converting

into a tabular format the lists of source categories and 

supply categories that are affected by the October 2009 

final rule. The lists, which were originally embedded in 

three paragraphs of 40 CFR part 98, subpart A (40 CFR 

98.2(a)), were moved to three new tables in 40 CFR part 98, 

subpart A. Each table also indicated the applicable first 

reporting year for each source and supply category. For 

source and supply categories included in the 2009 final

rule, the first reporting year remains 2010. As a 

concurrent harmonizing change, all references to applicable 

subparts (e.g., ‘‘40 CFR part 98 subparts C through JJ’’) 

were replaced by references to the appropriate source or 

supply category table. Other changes included updating the 

language for the schedule for submitting reports and 

calibrating equipment to recognize that subparts that may 

be added in the future would have later deadlines. These 
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revisions did not change the requirements for subparts 

included in the 2009 final rule. 

The direct final rule notice also stated the direct 

final rule would become effective May 17, 2010, unless any 

adverse comments were received by April 15, 2010. If such 

comments were received, EPA would withdraw the direct final 

rule and finalize the proposal at a later date. The Agency 

received two comments that could be construed as adverse 

and subsequently withdrew the direct final on April 30, 

2010 (75 FR 22699).

EPA received two sets of ostensibly adverse comments, 

however neither addressed any of the specific formatting 

changes EPA made to the General Provisions in the direct 

final rule. Rather, the commenters focused on portions of 

the regulatory text that remained unchanged from the 

original final rule that was published on October 30, 2009 

(74 FR 56260). Both raised concerns with sentences that 

remained the same as they were in the October 2009 final 

rule and were not related to the formatting changes 

proposed on March 16, 2010. Specifically, both commenters 

objected to the reporting of biogenic emissions required 

under 40 CFR part 98, section 98.3(C)(4)(i) and (ii). EPA 

did not actually change that requirement from the October 

2009 rule but rather revised the reference in the paragraph 

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from “source categories in subparts C through JJ” to 

“source categories listed in Table A-3 and Table A-4 of 

this subpart” to reflect the proposed reformatting from 

lists of subparts to tables. 

One of the commenters also objected to the schedule 

for reporting described in 98.33(b)(2). Again, EPA did not 

change that requirement at all. Instead, the Agency 

inserted the phrase “and becomes subject to the rule in the 

year that it becomes operational” to the sentence that 

reads “for a new facility or supplier that begins operation 

on or after January 1, 2010 and becomes subject to the rule 

in the year it becomes operational, reporting emissions 

beginning with the first operating month and ending on 

December 31 of that year.” That additional phrase makes it 

clear that reporters must meet the applicability 

requirements for each source category before they are 

subject to any reporting requirements but does not actually 

amend the schedule for reporting itself.

Finally, one commenter objected to regulatory text in 

98.3(i)(1) that requires calibration of flow meters and 

other devices. This specific requirement also remains 

unchanged from the 2009 final rule. Similar to the above

amendment, EPA revised this paragraph not to change the 

requirements for sources covered by the October 2009 final 

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rule, but rather to allow facilities that must report under 

any additional subparts to conduct any initial calibrations 

that are required by the newly published subparts during 

the first year that the subpart applies rather than in the 

year 2010. To do that, EPA changed the following sentence, 

“for facilities and suppliers that become subject to this 

part about April 1, 2010, the initial calibration shall be 

conducted on the date that data collection is required to 

begin” to “for facilities and suppliers that are subject to 

this part on January 1, 2010, the initial calibration shall 

be conducted by April 1, 2010. For facilities and 

suppliers that become subject to this part after April 1,

2010, the initial calibration shall be conducted by the 

date that data collection is required to begin.” 

In both cases, the comments received did not address 

any of the changes EPA proposed to make to the General 

Provisions. As a result, EPA is finalizing those proposed 

minor amendments to accommodate the addition of new 

subparts in this rulemaking. The additional changes to 40 

CFR part 98, subpart A discussed below reflect these 

changes (i.e., revising Tables A-3 and A-4 instead of 40 

CFR 98.2(a)(1), (2) or (4)). As explained above, the 

comments that could be construed as adverse related to

parts of the regulatory text that remained unchanged from 

Deleted: F

Deleted: F

Deleted: e

Deleted: g

Deleted: amend

Deleted: were on
23

the 2009 final rule. If and when EPA decides to make any 

changes to any regulatory requirements set forth in the 

October 2009 final rule, including those highlighted in the 

comments above, the Agency will initiate a separate notice 

and comment process. 

 Changes to Applicability. Facilities containing 

magnesium production, industrial waste landfills, and/or 

industrial wastewater treatment, are subject to 40 CFR part 

98 if they emit 25,000 metric tons CO2-equivalent (CO2e) or 

more per year in combined emissions from combustion units, 

miscellaneous uses of carbonate, ferroalloy production, 

glass production, hydrogen production, iron and steel 

production, lead production, pulp and paper manufacturing, 

zinc production, magnesium production, industrial 

wastewater treatment, and industrial waste landfills, or if 

they are required to report under 98.2(a)(1). In today’s 

action, EPA is making revisions to Table A-4 in 40 CFR part 

98, subpart A from that included in the direct final rule 

and accompanying proposal to include the source categories: 

magnesium production, industrial wastewater treatment, and 

industrial waste landfills. 

Underground coal mines that are subject to quarterly 

(or more frequent) sampling of ventilation systems by the 

Mine Safety and Health Administration (MSHA) are subject to 

Deleted: go through

Deleted: ¶

Deleted: facilities

Deleted: the GGRRMandatory 

GHG Rreporting Rrule

Deleted: amending 

Deleted: of 40 CFR part 98
24

40 CFR part 98 regardless of the actual facility emissions. 

In today’s action, we are making revisions to Table A-3 

from that included in the direct final rule and 

accompanying proposal to include the underground coal mine 

source category. 

Changes to the Reporting Schedule. Facilities with 

existing magnesium production, underground coal mines, 

industrial wastewater treatment, and industrial waste 

landfills must begin monitoring GHG emissions on January 1, 

2011 in accordance with the methods specified in 40 CFR 

part 98, subparts T, FF, II, and TT. Facilities must 

report the GHG emissions and associated verification data 

required under each of these subparts by March 31, 2012. 

Facilities with existing reporting requirements for the 

year 2010 are not required to collect the data required 

under 40 CFR part 98, subparts T, FF, II, and TT for the 

reporting year 2010 or report it in 2011. 

EPA decided to require reporting of calendar year 2011 

emissions for the four source categories finalized in 

today’s action because the data are crucial to the timely 

development of future GHG policy and regulatory programs. 

In the fiscal year 2008 Appropriations Act, Congress 

requested that EPA develop this reporting program on an 

expedited schedule, and Congressional inquiries along with 

Deleted: the GGRRMandatory 

GHG Rreporting Rrule 

Deleted: amending

Deleted: 
25

public comments reinforce that data collection for calendar 

year 2011 is a priority. Delaying data collection until 

calendar year 2012 would mean the data would not be 

received until 2013, which would likely be too late for 

many ongoing GHG policy and program development needs. 

EPA received a number of comments on the April 2009 

proposal from stakeholders expressing concerns that there 

would be insufficient time between the publication of a 

final rule and the date on which monitoring must begin. 

EPA concluded that the time period between the publication 

of this final action and the January 1, 2011 deadline for 

beginning monitoring for 40 CFR part 98, subparts T, FF, 

II, and TT is sufficient to allow facilities to implement 

the required monitoring methods, including calibrating and 

installing monitoring equipment. The monitoring 

requirements for each subpart included in today’s action 

have not changed significantly from those requirements 

proposed in April 2009. Although facilities in some source 

categories will have to make emissions assessments to 

determine whether their facility exceeds the 25,000 metric 

tons CO2e applicability threshold, EPA has concluded that 

there is ample time to complete this assessment. Many 

facilities affected by today’s action will not need 

additional time to make emissions assessments because they 
26

will already be subject to monitoring and reporting 

emissions under other applicable subparts in 40 CFR part 

98. For example, pulp and paper mills which may be 

required to report under 40 CFR part 98, subparts TT and 

II, are already required to report under 40 CFR part 98, 

subpart AA and any other applicable source categories if 

their emissions are more than 25,000 metric tons CO2e per 

year. Furthermore, many of those facilities that are not 

subject to monitoring in 2010 will have already completed 

some assessments of their emissions from source categories 

included in the Octber 2009 Final Rule. For example, many 

industrial facilities will have already assessed their GHG 

emissions from combustion units for the 2010 reporting 

year. For these reasons, EPA concluded that the January 1, 

2011 deadline should provide sufficient time for facilities 

to comply with the rule. 

Best Available Monitoring Methods. In the October 

2009 Final Rule, facilities had the option to use Best 

Available Monitoring Methods (BAMM) for the first quarter 

of the first reporting year. While facilities in the 

source categories included in today’s action will not 

automatically be allowed to use BAMM for the first quarter 

of monitoring (January 1, 2011 to March 31, 2011), 

facilities will have the option to request the use of BAMM. 

Deleted: f

Deleted: GGRRMandatory GHG 

Rreporting Rrule published 

in October 2009

Deleted: f

Deleted: GGRRMandatory GHG 

Rreporting Rrule
27

The request must be submitted by [INSERT DATE 90 DAYS AFTER 

PUBLICATION IN THE FEDERAL REGISTER] and must contain the 

information specified in 40 CFR 98.3(d)(2)(ii). Specific 

information regarding the use of BAMM is included in the 

Monitoring and QA/QC Requirements section of each subpart 

for the source categories included in today’s action. The 

use of BAMM for these source categories will not be 

approved beyond December 31, 2011. The only change to the 

general provisions, by virtue of inclusion of BAMM in each 

subpart, is to make it clear that the automatic three month 

provision of 98.3 does not apply to these subparts. 

For most facilities covered by the source categories 

in today’s action, there are monitoring requirements that 

may not be typical operating procedure and therefore, 

monitoring equipment will need to be purchased and 

installed. In addition, per EPA’s experience with the 

source categories finalized in 2009 final rule, there will 

likely be facilities with unique circumstances that will 

require some additional time to comply with the rule 

requirements. Therefore, EPA decided to allow facilities 

to request the use of BAMM for the first reporting year so 

that those that are not able to acquire, install, and 

calibrate the required monitoring equipment due to their 

unique circumstances may still comply with the rule. 
28

Other Changes to 40 CFR part 98, subpart A. In 

today’s action, we are also amending 40 CFR 98.6 

(definitions) to add definitions for several terms used in 

40 CFR part 98, subparts T, FF, II, and TT and to clarify 

the meaning of certain existing terms for purposes of 40 

CFR part 98, subpart II. 

We are also amending 40 CFR 98.7 (incorporation by 

reference) to include standard methods references in 40 CFR 

part 98, subparts FF, II, and TT. 

C. Magnesium Production (40 CFR part 98, subpart T) 

1. Summary of the Final Rule 

Source Category Definition. Magnesium production and 

processing facilities are defined as any facility where 

magnesium metal is produced through smelting (including 

electrolytic smelting), refining, or remelting operations, 

or any site where molten magnesium is used in alloying, 

casting, drawing, extruding, forming, or rolling 

operations. 

Facilities that meet the applicability criteria in the 

General Provisions (40 CFR 98.2(a)) summarized in Section 

II.B of this preamble must report GHG emissions.

GHGs to Report. Each magnesium production facility 

must report total emissions at the facility level for each 

of the following gases in metric tons of gas per year 

Deleted: S

Deleted: TT

Deleted: II

Deleted: S

Deleted: ¶
29

resulting from their use as cover gases or carrier gases in 

magnesium production or processing: 

 SF6. 

 HFC-134a. 

 FK 5-1-12. 

 CO2.

 Any other GHG as defined in 40 CFR part 98, subpart A 

(General Provisions) of the rule. 

In addition, each facility must report GHG emissions 

for other source categories for which calculation methods 

are provided in the rule. For example, facilities must 

report CO2, N2O, and CH4 emissions from each stationary 

combustion unit on site by following the requirements of 40 

CFR part 98, subpart C (General Stationary Fuel Combustion 

Sources). 

GHG Emissions Calculation and Monitoring. Owners or 

operators of magnesium production facilities must calculate 

emissions of each gas by monitoring the annual consumption 

of cover gases and carrier gases using one of three 

methods: 

 Use a mass-balance approach that takes into account 

the following: 

– Decrease in Inventory: The decrease in inventory 

of cover or carrier gases stored in containers 

from the beginning to the end of the year. 

– Acquisitions: The amount of cover or carrier gas 

acquired through purchases or other transactions. 
30

– Disbursements: The amount of cover or carrier 

gases disbursed to sources and locations outside 

the facility through sales or other transactions. 

 Monitor the changes in the mass of individual 

containers as the gases are used. 

 Monitor the mass flow of pure cover gas and carrier 

gas into the cover gas distribution system. 

Data Reporting. In addition to the information 

required to be reported by the General Provisions (40 CFR 

98.3(c)), reporters must submit additional data that are 

used to calculate GHG emissions. A list of the specific 

data to be reported for this source category is contained 

in 40 CFR part 98, subpart T. 

Recordkeeping. In addition to the information 

required by the General Provisions (40 CFR 98.3(g)), 

reporters must keep records of additional data used to 

calculate GHG emissions. A list of specific records that 

must be retained for this source category is included in 40 

CFR part 98, subpart T. 

2. Summary of Major Changes Since Proposal 

No major changes since proposal have been made to the 

magnesium production sector. 

3. Summary of Comments and Responses 

No comments specific to regulation of the magnesium 

production sector were received. 

D. Underground Coal Mines (40 CFR part 98, subpart FF)

Deleted: S
31

1. Summary of the Final Rule 

Source Category Definition. This source category 

consists of active underground coal mines and any 

underground mines under development that have operational 

pre-mining degasification systems. An underground coal 

mine is a mine at which coal is produced by tunneling into 

the earth to a subsurface coal seam, where the coal is then 

mined with equipment such as cutting machines, and 

transported to the surface. Active underground coal mines 

are underground mines categorized by the MSHA as active and 

where coal is currently being produced or has been produced 

within the previous 90 days. This source category includes 

each ventilation well or shaft, and each degasification 

system well or shaft, and includes degasification systems 

deployed before, during, or after mining operations are 

conducted in a mine area. 

This source category does not include abandoned 

(closed) mines, surface coal mines, post-coal mining 

activities (e.g., storage or transportation of coal), or 

coalbed methane recovery from coal seams not associated 

with active underground coal mines.

Reporters must submit annual GHG reports for 

facilities that meet the applicability criteria in the 

Deleted: Mine Safety and 

Health Administration (

Deleted: )

Deleted: ¶
32

General Provisions (40 CFR 98.2(a)(1)) summarized in 

Section II.B of this preamble. 

GHGs to Report. For underground coal mines, report 

the following: 

 Quarterly CH4 liberation from ventilation and 

degasification systems. 

 Quarterly CH4 destruction for ventilation and 

degasification systems and resultant CO2 emissions, if 

destruction takes place on-site. 

In addition, each facility must report GHG emissions 

for other source categories for which calculation methods 

are provided in the rule. For example, facilities must 

report CO2, N2O, and CH4 emissions from each stationary 

combustion unit on site by following the requirements of 40 

CFR part 98, subpart C (General Stationary Fuel Combustion 

Sources). 

GHG Emissions Calculation and Monitoring. For CH4

liberated from mine ventilation air, facilities are to 

monitor CH4 using either quarterly or more frequent sampling 

of CH4 content and gas flow, or continuous emissions 

monitoring systems (CEMS). 

For the quarterly sampling option, coal mine operators 

are required to either: (a) to obtain the results of the 

quarterly, or more frequent, testing that MSHA conducts, 

and use the results to calculate quarterly emissions, or 

(b) independently collect quarterly, or more frequent, 
33

samples of CH4 released from the ventilation system(s), 

using MSHA procedures, have these samples analyzed for CH4

composition, and use the results to calculate quarterly 

emissions. 

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. 

For CH4 liberated from degasification systems, 

facilities are to monitor CH4 using either weekly sampling, 

or CEMS. 

The option of collecting weekly samples includes both 

measurement of the total gas volume liberated (including 

that which is emitted or sold, used onsite, or otherwise 

destroyed (including by flaring)), along with measurements 

of CH4 concentrations in gas volumes recovered or emitted. 

Under this option, facilities must determine weekly gas 

flow rates and CH4 composition from these degasification 

wells and shafts, either on an individual well or shaft 

basis, or in aggregate at one or more centralized 

collection points. Methane composition could be determined 

either by submitting samples to a lab for analysis, or from 

the use of methanometers at the degasification well site(s) 

and/or one or more centralized collection point(s). 
34

For the CEMS option, facilities must monitor either 

individual wellbores, or can monitor gas at points of 

aggregation, as long as emissions from all wells are 

addressed, and the methodology for calculating total 

emissions from all wells is documented. 

For all systems with CH4 destruction, CH4 destruction 

is monitored through direct measurement of CH4 flow to 

combustion devices with continuous monitoring systems. The 

resulting CO2 emissions for onsite combustion devices 

without energy recovery (i.e., flaring) are to be 

calculated from these monitored values. 

Data Reporting. In addition to the information 

required to be reported by the General Provisions (40 CFR 

98.3(c)), reporters must submit additional data that are 

used to calculate GHG emissions. A list of specific data 

to be reported for this source category is contained in 40 

CFR part 98, subpart FF. 

Recordkeeping. In addition to the records required by 

the General Provisions (40 CFR 98.3(g)), reporters must 

keep records of additional data that are used to calculate 

GHG emissions. A list of specific records that must be 

retained for this source category is contained in 40 CFR 

part 98, subpart FF. 

2. Summary of Major Changes since Proposal 

Deleted: 98.326

Deleted: , subpart FF

Deleted: data to be reported

Deleted: 98.327, subpart FF
35

The major changes in this rule since the original 

proposal are identified in the following list. The 

rationale for these and any other significant changes to 40 

CFR part 98, subpart FF can be found below or in “Mandatory 

Greenhouse Gas Reporting Rule: EPA's Response to Public 

Comments, Subpart FF: Underground Coal Mines.” 

 An option of using one or more CEMS to obtain data on 

mine ventilation systems was added. 

 For CH4 liberated from degasification systems, the 

requirement to monitor each well was removed. CEMS 

may be used to monitor aggregate CH4 from more than one 

well, as long as CH4 from all wells is monitored, and 

the methodology for estimating total emissions from 

all wells is documented. 

 The requirement for continuous monitoring for total CH4

liberation at degasification systems was removed. 

Degasification wells may be monitored with CEMS or 

through weekly sampling of all degasification wells, 

including gob gas vent holes and other degasification 

wells. 

3. Summary of Comments and Responses 

This section contains a brief summary of major 

comments and responses. EPA received many comments on this 

subpart covering numerous topics. EPA’s responses to these 

significant comments can be found in the comment response 

document for underground coal mines in “Mandatory 

Greenhouse Gas Reporting Rule: EPA's Response to Public 

Comments, Subpart FF: Underground Coal Mines.” 

Definition of Source Category 
36

Comment: Several commenters stated that many 

operators currently recover liberated CH4 for various 

purposes, including destruction, and therefore CH4 that has 

been recovered is no longer an emission as it is not vented 

into the atmosphere. The commenters recommended that EPA 

not include recovered CH4 in the reporting requirements. 

Response: EPA agrees that CH4 that has been recovered 

and combusted is not emitted. However, EPA does not agree 

with the commenter that recovered CH4 should be excluded 

from the reporting requirements. Recovery projects at 

mines greatly reduce CH4 emissions from this source. It is 

vital that EPA obtain the best information available about 

these practices for future policy analysis. In addition, 

since mines with CH4 collection systems generally monitor 

the amount of CH4 collected in these systems, this can 

provide an effective internal validation method for

assessment of CH4 generation within the mine. As such, data 

for mines with gas collection systems are also vitally 

important to better understand and improve estimates of CH4

emissions from mines in general. EPA has taken the same 

approach for the reporting of recovered CH4 from landfills 

under 40 CFR part 98, subpart HH. 

Comment: Commenters suggested that EPA include 

abandoned mines in the source category definition. For 

Deleted: removed 

Deleted: , since they are

Deleted: 

Deleted: ing

Deleted: by which they can

Deleted: their 

Deleted: S
37

existing abandoned mines whose operators can be identified 

from State or Federal records, they recommended that EPA 

require the installation of appropriate monitoring 

equipment. They also recommended that EPA make clear that 

the abandoned mine exception does not apply prospectively. 

Response: For currently abandoned mines, EPA 

considered this emission source and determined that 

measuring and/or monitoring emissions from abandoned mines 

would be difficult at this time, since there are currently 

no robust facility-level monitoring methods available to 

measure fugitive emissions from abandoned mines. Further, 

in many cases, EPA concluded that it would be difficult to 

identify owners of abandoned mine sites, i.e., it would be 

difficult to identify the responsible parties to monitor 

and report. Finally, even where the site owner is known, 

these sites are often unmanned, remote, and lack a source 

of nearby power, making it burdensome to monitor emissions. 

EPA may reconsider including abandoned mines in this rule 

should additional information become available 

demonstrating that monitoring is feasible. 

With regard to the “once in, always in” provision of 

the proposed reporting rule, a mine covered by the rule 

that later ceases coal production would need to continue 

reporting until its emissions fell below the levels 

Deleted: s

Deleted: f
38

specified in the provisions to cease reporting in 40 CFR 

part 98, subpart A. Mines continue to emit CH4 after mining 

activities have ceased and therefore it is prudent to 

continuing monitoring emissions until they are below the 

threshold. 

Comment: For surface mines, while commenters 

recognized that existing monitoring methods presently may 

not be robust, some commenters consider the use of existing 

methods to be preferable to excluding this source of 

emissions. They suggested that EPA consider requiring 

these methods for surface mines, adjusting emissions 

figures appropriately to account for uncertainty. 

Response: EPA determined that monitoring emissions 

from surface mines would be challenging, since there are 

currently no robust facility-level monitoring methods to 

measure fugitive CH4 emissions from surface mines at this 

time. Measuring fugitive emissions at specific locations 

would not adequately capture the emissions from the entire 

mine, would be expensive and resource-intensive, and 

difficult for mine operators to implement on a periodic 

basis. EPA may reconsider including surface mines in this 

rule should additional information become available 

demonstrating that monitoring is feasible. 
39

Comment: One commenter expressed concern that even 

the most accurate instrumentation will have accuracy 

difficulties based upon varying conditions, calling into 

question the accuracy of the measurements. Because of 

this, they recommended that degasification wells be exempt 

from the rule. 

Response: EPA does not agree with the commenter that 

CH4 degasification wells should be exempt. While the 

factors mentioned in the comment may indeed influence the 

accuracy of measurement of CH4 from degasification wells, 

EPA considered this issue when including this source 

category, and determined that the collection of facilitylevel data at these mines is still of value to EPA because 

it provides valuable information for characterizing CH4 

emissions from underground coal mining options. This 

information is also of value to mine owners, because those 

facilities reporting under the rule will have stringent 

monitoring systems in place that will allow them to 

quantify the mitigation value of destroying CH4 from their 

degasification systems. 

Reporting Threshold 

Comment: One commenter recommended that establishing 

the reporting threshold at a level of 100,000 metric tons 

CO2e/yr instead of the proposed threshold of MSHA quarterly 
40

reporting would ensure accurate reporting while sparing 

small mines and manufacturers from the burdens of 

compliance. 

Response: In developing the threshold for active 

underground coal mines, EPA considered various emissionsbased thresholds, and determined that reporting should be 

required for those coal mines for which CH4 emissions from 

the ventilation system are sampled quarterly by MSHA. MSHA 

conducts quarterly testing of CH4 concentration and flow at 

mines emitting more than 100,000 cubic feet of CH4 per day. 

This threshold was selected because subjecting underground 

mine operators to a new emissions-based threshold would be 

unnecessarily burdensome and perhaps confusing, since these 

mines are already subject to MSHA regulations and therefore 

would be able to comply with this rule without having to 

separately determine applicability. 

Selection of Proposed GHG Emissions Calculation and 

Monitoring Methods 

Comment: Several commenters recommended that CEMS 

should be allowed as a monitoring method, but not required, 

for both ventilation and degasification systems. In 

particular, they claim that continuous monitoring of CH4

emissions and air flow rates for all degasification wells 

and degasification vent holes is not feasible for several 

reasons. The remote location, unavailability of power, 
41

inaccessibility, susceptibility to vandalism, and the 

relatively short longevity of many degasification and vent 

holes renders continuous monitoring impractical in many 

cases. 

One commenter generally agreed with EPA’s approach to 

underground coal mine CH4 monitoring, but urged EPA to 

require the use of CEMS for ventilation systems in addition 

to degasification systems. 

Most commenters stated that the procedures and 

quarterly sampling are sufficient as an option for GHG 

emissions reporting from ventilation of underground coal 

mines if such data can be received from MSHA. However, 

some expressed concern that MSHA does not normally report 

such data back to mines unless requested. 

Response: For monitoring CH4 liberation from 

underground coal mines, EPA considered several approaches: 

engineering approaches whereby default emission factors 

would be applied to total annual coal production; periodic 

sampling of CH4; daily sampling of CH4; and the use of CEMS. 

EPA selected periodic sampling as its minimum requirement 

because the cost burden of purchasing, installing and 

maintaining CEMS, and the cost of maintaining a more 

frequent sampling program were not justifiable under 
42

present circumstances relative to the greater measurement 

accuracy achieved. 

We agree that CEMS should be allowed, but not 

required, to monitor CH4 liberation from ventilation and 

degasification systems, and have changed the rule 

accordingly. For systems where recovered CH4 is sold, 

destroyed, or used on site, EPA determined that such 

systems are already installed on most wells, and CEMS are 

required. 

For monitoring at ventilation systems, EPA has 

concluded that quarterly sampling is sufficient as an 

option for GHG monitoring from ventilation systems. 

Quarterly sampling was chosen for ventilation systems 

because that is the frequency of sampling conducted by 

MSHA. Greater frequency would provide more accurate data; 

however, the increased burden would outweigh the benefits 

of improved accuracy for the purposes of this reporting 

rule at this time. The quarterly option represents a 

balance between burden on reporters and accuracy of data.

EPA is aware that MSHA does not normally report 

sampling data back to mines unless requested. However, 

since MSHA is conducting sampling that provides data useful 

to this rule, EPA determined that it should include use of 

the data collected by MSHA, by facilities that do obtain 

Deleted: EPA determined that 

coal mining operations do 

not generally vary much from 

quarter to quarter for mine 

ventilation systems. ¶
43

this data from MSHA, as an option under this rule. Under 

this option, facilities would input MSHA data into the 

emissions calculations required under this rule. Mines 

that do not obtain this data from MSHA must conduct 

sampling as specified in the rule. 

EPA added the use of CEMS at ventilation systems as an 

option for monitoring. CEMS are not currently widely 

implemented at ventilation systems, but mines evaluating 

the feasibility of mitigation, abatement, or use of 

ventilation air methane might install CEMS to monitor 

methane, and this monitoring would be allowed under this 

rule. 

For monitoring at degasification systems, it was 

determined that weekly sampling is sufficient. Most 

degasification systems conduct continuous monitoring and 

where this type of monitoring is already in place, it 

should be used for purposes of this rule. Based on 

interviews with a number of mine operators, for many of 

those sites where continuous monitoring is not being 

conducted (primarily for gob gas vent holes) degasification 

wells are monitored at least weekly. Moreover, EPA 

determined that emissions do not generally vary much from 

week to week for mine degasification systems, so the weekly 

measurements would provide sufficient accuracy. 
44

Cost Data 

Comment: Many commenters noted that EPA did not 

appropriately take into consideration the full costs of 

compliance associated with the proposed rule, particularly 

those associated with the installation of CEMS on all 

degasification wells and vent holes. They noted that both 

the number of impacted wells and vent holes, as well as the 

costs associated with implementing such systems, was 

probably underestimated. 

Response: Based on these comments and further 

analysis, EPA reevaluated its cost assessment, revised its 

costs, and on the basis of those revised costs, modified 

the monitoring requirements. 

EPA reassessed the number of degasification wells and 

vent holes that would likely be associated with mines 

required to report under the rule. This resulted in a 

substantially larger estimate of the number of 

degasification wells that would be required to install CEMS 

systems in compliance with the originally proposed 

requirements, with an associated greater incremental cost 

burden. 

EPA determined that implementing CEMS on some 

degasification wells could be quite costly, and in many 

cases, would be difficult and/or impractical due to remote 
45

location, unavailability of power, inaccessibility, 

susceptibility to vandalism, and the relatively short 

longevity of many degasification and vent holes. As a 

result, EPA included consideration of the costs associated 

with weekly or more frequent sampling, as an alternative to 

the installation of CEMS, to address this potential burden. 

For more detailed information on costs, please see Section 

4 of the Economic Impact Analysis (EIA) found in docket 

EPA-OAR-2008-0508. 

E. Industrial Wastewater Treatment (40 CFR part 98, 

subpart II)

1. Summary of the Final Rule 

Source Category Definition. This source category 

applies to anaerobic processes used to treat industrial 

wastewater and wastewater treatment sludge only at pulp and 

paper mills, food processing facilities, ethanol production 

facilities, and petroleum refineries. It does not include 

anaerobic processes used to treat wastewater and wastewater 

treatment sludge at other industrial facilities. It does 

not include municipal wastewater treatment plants or 

separate treatment of sanitary wastewater at industrial 

facilities. It does not include oil/water separators. 

This source category consists of the following: anaerobic 

Deleted: S

Deleted: sludges 

Deleted: sludges 
46

reactors, anaerobic lagoons, anaerobic sludge digesters, 

and biogas destruction devices. 

Facilities that meet the applicability criteria in the 

General Provisions (40 CFR 98.2(a)) summarized in Section 

II.B of this preamble must report GHG emissions. 

GHGs to Report. Operators of anaerobic processes used 

to treat industrial wastewater and industrial wastewater 

treatment sludge at the above noted facilities must report 

the following: 

 The amount of CH4 generated, recovered, and emitted 

from treatment of industrial wastewater using 

anaerobic lagoons or anaerobic reactors. 

 The amount of CH4 recovered and emitted from anaerobic 

sludge digesters.

 The amount of CH4 destroyed by and emitted from biogas 

collection systems and destruction devices. 

Operators of anaerobic wastewater treatment sludge 

digesters are not required to report the amount of CH4

generated. It is EPA’s understanding that all anaerobic 

sludge digesters are designed for CH4 recovery and are 

therefore not expected to emit CH4 directly from the 

digester apparatus. Further, this rule requires operators 

of anaerobic sludge digesters to report the amount of CH4 

recovered and emitted from the recovery system. Therefore, 

all CH4 that is generated in the anaerobic sludge digester 

is already accounted for in the amount of CH4 recovered and 

emitted from the recovery system. For this reason, a 

Deleted: ;

Deleted: ; and

Deleted: are required 
47

separate calculation and report of the amount of CH4

generated is not necessary. 

GHG Emissions Calculation and Monitoring. For each 

anaerobic wastewater treatment process, facilities must 

calculate the mass of CH4 generated using the following 

inputs and data: 

 Volume of wastewater sent to an anaerobic treatment 

process.

 Average concentration of chemical oxygen demand (COD) 

or 5-day biochemical oxygen demand (BOD5) of wastewater 

entering an anaerobic treatment process.

 Maximum CH4 producing potential of wastewater (0.25 for 

COD, 0.6 for BOD5).

 CH4 conversion factor for the type of wastewater 

treatment process used. 

For each anaerobic process (such as a reactor, lagoon, 

or sludge digester) from which biogas is recovered, covered 

facilities must calculate the mass of CH4 recovered using

the following inputs and data: 

 Cumulative volumetric flow of biogas for the 

monitoring period.

 Average CH4 content of the biogas.

 Temperature, pressure, and moisture content at which 

flow is measured, as needed to accurately calculate 

biogas flow and CH4 content. 

For each anaerobic process (such as reactor, lagoon, 

or sludge digester) from which biogas is recovered, covered 

Deleted: ;

Deleted: ;

Deleted: ; and

Deleted: ;

Deleted: ; and
48

facilities must calculate the mass of CH4 emitted using the 

following inputs and data: 

 Mass of CH4 recovered.

 Collection efficiency for the anaerobic process, based 

on the type of anaerobic process.

 Destruction efficiency of the biogas collection and 

combustion system.

 Fraction of hours the destruction device was operating 

in the reporting year. 

Data Reporting. In addition to the information 

required to be reported by the General Provisions (40 CFR 

98.3(c)), facilities must submit additional data that are 

used to calculate or verify GHG emissions. A list of the 

specific data to be reported for this source category is 

contained in 40 CFR part 98, subpart II. 

Recordkeeping. In addition to the records required by 

the General Provisions (40 CFR 98.3(g)) facilities must 

keep records of additional data used to calculate GHG 

emissions. A list of specific records that must be 

retained for this source category is included in 40 CFR 

part 98, subpart II. 

2. Summary of Major Changes Since Proposal 

The major changes since proposal are identified below. 

The rationale for these and any other significant changes 

can be found below or in “Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to Public Comments, Subpart 

Formatted: Normal, Space Before: 

0 pt, After: 0 pt

Deleted: ;

Deleted: ;

Deleted: ; and

Deleted: P

Deleted: P
49

II: Industrial Wastewater Treatment,” and “Technical 

Support Document for Industrial Wastewater Treatment.” 

 The source category has been renamed Industrial 

Wastewater Treatment and the applicability of this 

subpart has been clarified. Only petroleum 

refineries, and ethanol production, food processing, 

and pulp and paper facilities that meet the 

requirements of 98.2(a)(2) are required to report CH4

emissions from anaerobic processes used to treat 

industrial wastewater and industrial wastewater 

treatment sludge and biogas destruction devices. 

Separate treatment of sanitary wastewater at 

industrial facilities is not included in the 

applicability, nor are facilities that do not employ 

the wastewater treatment processes listed in the 

source definition (i.e., those that employ only 

aerobic or anoxic processes are not required to 

report). 

 The requirement to report emissions from oil/water 

separators at petroleum refineries has been removed. 

EPA expects no direct emissions of CO2 or other GHG 

from these oil/water separators. 

 Because petrochemical facilities are not known to 

employ anaerobic wastewater treatment, this sector has 

been removed from the final version of the rule. 

 For ease of reporting, EPA revised the regulation to 

allow for either continuous or weekly monitoring of 

biogas CH4 concentration. Facilities may use either 

installed or portable monitors to measure the CH4

concentration. Further, EPA added BOD5 as an 

alternative to measuring COD to determine the organic 

load of influent to anaerobic wastewater treatment 

systems. 

3. Summary of Comments and Response 

This section contains a brief summary of major 

comments and responses. EPA received many comments on this 

subpart covering numerous topics. EPA’s responses to these 

comments can be found in the comment response document for 

Deleted: sludges 

Deleted: 5-day biochemical 

oxygen demand (

Deleted: )

Deleted: chemical oxygen 

demand (

Deleted: )
50

industrial wastewater treatment in “Mandatory Greenhouse 

Gas Reporting Rule: EPA’s Response to Public Comments, 

Subpart II: Industrial Wastewater Treatment.” 

Comment: Many commenters expressed confusion about 

which facilities were required to report emissions from 

wastewater treatment systems. Some commenters requested 

EPA clarify the definitions of aerobic and anaerobic 

wastewater treatment, while others were uncertain whether 

only the industries explicitly mentioned in the rule were 

required to report. Many commenters also requested that 

EPA clarify whether the rule applied to centralized 

municipal wastewater treatment plants and treatment of 

sanitary wastewater at industrial facilities. 

Response: EPA revised 40 CFR 98.351 to clarify that 

only ethanol production, food processing, petroleum 

refining, and pulp and paper manufacturing facilities must 

report wastewater treatment system emissions if they both 

meet the requirements of 40 CFR 98.2 (a)(1) or (2) and 

operate an anaerobic process to treat industrial wastewater 

or industrial wastewater treatment sludge. 

With regard to anaerobic processes covered by the 

rule, EPA revised 40 CFR 98.350 to state explicitly that 

facilities are only required to report emissions for the 

following: anaerobic reactors, anaerobic lagoons, anaerobic 

Deleted: sludges
51

sludge digesters, and biogas destruction devices. To 

further clarify the scope of 40 CFR part 98, subpart II, 

EPA has removed emission factors for aerobic processes used 

to treat industrial wastewater from Table II-1 of 40 CFR 

part 98, subpart II because these processes are not covered 

by the reporting rule. 

EPA agrees with commenters that it is appropriate to 

exclude centralized domestic or municipal wastewater 

treatment plants from 40 CFR part 98, as was the case in 

the proposed rule. EPA continues to exclude municipal 

wastewater treatment plants from the final rule, and has 

retitled 40 CFR part 98, subpart II as Industrial 

Wastewater Treatment to clarify the applicability of this 

subpart. 

EPA also agrees with commenters that it is appropriate 

to exclude separate treatment of sanitary wastewater at 

industrial facilities from 40 CFR part 98. Most such 

sanitary treatment plants are much smaller than municipal 

wastewater treatment plants and few use anaerobic 

treatment. As a result, EPA explicitly excluded these 

systems from 40 CFR part 98; however, anaerobic processes 

used to treat combined industrial and sanitary wastewater 

are covered by the rule. 

Deleted: S

Deleted: rule s

Deleted: the

Deleted: GHG Reporting 

RuleGGRR

Deleted: S

Deleted: the GHG Reporting 

RuleGGRR

Deleted: the GHG Reporting 

Rule GGRR
52

Comment: Multiple commenters objected to the 

inclusion of emissions from petroleum refinery oil/water 

separators in the rule. Some argued that the GHG emissions 

from these devices would be insignificant. Others asserted 

that the GHG emissions calculations were unsupported and 

that this subpart was the only one to consider the 

atmospheric conversion of volatile organic compounds (VOCs) 

to CO2 in the calculation of GHG emissions. 

Response: In the proposed rule, EPA included a method 

to calculate CO2 emissions that indirectly come from VOCs 

from petroleum refinery oil/water separators. EPA agrees 

with commenters that this requirement should be removed 

because this is the only source category to consider and 

require reporting of the conversion of VOCs to CO2 in the 

atmosphere. The purpose of this rule is to collect direct 

GHG emissions data from downstream sources including 

industrial wastewater treatment. Therefore we are not 

collecting data from downstream sources on indirect 

emissions such as VOCs that can convert to CO2 once in the 

atmosphere. Please see “Technical Support Document for 

Industrial Wastewater Treatment” for more detailed 

information on this issue. While EPA is not requiring the 

reporting of CO2 resulting from VOC emissions at this time, 

Deleted: Since t

Deleted: and not data from 

sources simply because they 

emit

Deleted: , this requirement 

was removed
53

we understand that these emissions may be important and we 

may revisit this reporting requirement in the future. 

Comment: EPA received many comments recommending that 

wastewater treatment be considered a de minimis source. 

Some argued that wastewater treatment contributes an 

extremely small percentage of emissions compared to certain 

sectors’ process emissions. Others contended that the 

burden of determining the small amount of wastewater 

treatment emissions was not warranted. 

Response: EPA disagrees that reporting of wastewater 

treatment emissions should be excluded from the rule.

Despite the comparatively small amount of GHG emissions 

from wastewater treatment nationally, emissions at 

individual facilities could be significant. We note that 

the source categories required to report are industries 

that both have the potential to exceed the reporting 

threshold, and have high levels of BOD or COD in their 

wastewater and frequently employ anaerobic treatment 

operations. See the Wastewater Treatment Technical Support 

Document (EPA–HQ–OAR–2008–0508–035). These two conditions 

result in the opportunity for increased GHG emissions. EPA 

has minimized the overall reporting burden by focusing the 

rule requirements on those treatment systems with the 

highest likelihood of generating GHG emissions exceeding 

Formatted: Font: Courier New
54

the reporting threshold. In light of the potential 

significance of the emissions, lack of facility specific 

data, and revisions made to the reporting requirements in 

response to comments, we find that the burden on facilities 

is justified. 

Given this reporting rule is aimed at collecting data 

to inform a range of future policies and programs it is 

important to understand the entirety of a facility’s 

emissions. Therefore, requiring facilities in the included 

industry sectors to report wastewater treatment emissions, 

even though they may result in only a small portion of a 

facility’s overall emissions, will allow each reporting 

facility to estimate their total emissions more accurately. 

Comment: Many commenters requested additional 

flexibility in the rule requirements. Some requested the 

ability to use BOD instead of COD to calculate the organic 

content of the wastewater they treat in anaerobic 

processes. Others requested changes in sampling frequency 

for both biogas and wastewater. 

Response: To reduce the reporting burden, EPA has 

revised the rule to allow for the use of either COD in 

conjunction with Equation II-1 of the rule or BOD5 in 

conjunction with Equation II-2 of the rule for the 

calculation of CH4 generation. EPA does not expect that 

Deleted: Requiring facilities 

in the included industry 

sectors to report wastewater 

treatment emissions will 

allow each reporting 

facility to estimate their 

emissions accurately. While 

anaerobic wastewater 

treatment may in some cases 

result in only a small 

portion of a facility’s 

emissions, excluding this 

source from the reporting 

requirements will provide a 

less than accurate portrayal 

of the true emissions from 

each facility. 
55

this will effect the accuracy of the estimate of the annual 

mass of CH4 generated at the facility. 

EPA also revised the language regarding sampling of 

wastewater to require facilities to collect a flowproportional composite sample (either constant time 

interval between samples with sample volume proportional to 

stream flow, or constant sample volume with time interval 

between samples proportional to stream flow). Facilities 

are required to collect a minimum of four sample aliquots 

per 24-hour period and to composite the aliquots for 

analysis. This requirement provides for greater certainty 

that the collected sample represents the wastewater 

influent to the anaerobic wastewater treatment process, 

without imposing unnecessary burden on reporters. 

In response to comments, EPA considered revising the 

proposed language of 40 CFR 98.354 to clarify how 

facilities might meet the stated requirement for the 

collection of grab samples or time-weighted composite 

samples. EPA considered allowing facilities to collect 

grab samples if the wastewater influent to the anaerobic 

wastewater treatment process represents the discharge from 

a well-mixed wastewater storage unit (tank or pond), such 

that the COD or BOD5 concentration of the waste stream does 

not vary in a 24-hour period. Similarly, EPA considered 

Deleted: §
56

allowing facilities to collect time-weighted composite 

samples if the flow rate of the wastewater influent to the 

anaerobic wastewater treatment process does not vary more 

than ±50 percent of the mean flow rate for a 24-hour 

sampling period. However, establishing that these 

conditions are met would require the facility to collect 

more samples than the proposed requirement to collect flowweighted composite samples. Thus we did not include these 

sampling approaches in the final rule. 

The final rule establishes differing requirements for 

the frequency of monitoring biogas flow and biogas CH4

concentration. EPA expects that facilities that recover 

biogas will have existing gas flow meters, and is therefore 

requiring continuous monitoring of biogas flow from these 

facilities. EPA has revised the rule to allow either 

continuous or weekly monitoring of biogas CH4 concentration. 

If a facility has equipment that continuously monitors CH4

concentration, the facility must use this equipment to 

determine the CH4 concentration in the recovered biogas. If 

a facility does not currently monitor biogas CH4

concentration, they must use either installed or portable 

equipment to monitor the CH4 concentration at least once a 

week. Once a week means once each calendar week, with at 

least three days between measurements. Weekly monitoring 
57

provides an adequate number of samples to evaluate the 

variability and uncertainly associated with CH4 generation. 

Less frequent monitoring would result in greater 

uncertainty and would not significantly reduce the costs 

compared to weekly monitoring. 

Some gas flow meters and gas composition meters 

automatically compensate for temperature, pressure, and 

moisture content. EPA revised the equations in 40 CFR part 

98, subpart II so that facilities that use automatically 

compensated meters are not required to measure temperature, 

pressure and moisture content. Facilities that operate 

meters that are not automatically compensated must measure 

these parameters as specified in 40 CFR 98.354. 

Some facilities, particularly food processing 

facilities, may not operate their wastewater treatment 

plants all year round. EPA clarified that wastewater 

monitoring requirements apply when the anaerobic wastewater 

treatment process is operating. Further, biogas methane 

concentration monitoring is only required in weeks when the 

cumulative biogas flow measured as specified in 40 CFR 

98.354(g) is greater than zero. 

Comment: Many commenters argued that it would be 

unduly burdensome and costly to require facilities to 

monitor influent to wastewater treatment systems. Some 

Deleted: S
58

stated that their influent often consists of multiple 

phases, making measurement of wastewater organic content 

(BOD5 or COD) difficult. Others contended that since 

effluent concentrations and flow are already measured for 

the purposes of National Pollutant Discharge Elimination 

System (NPDES) compliance, EPA should allow facilities to 

use engineering calculations and effluent measurements to 

calculate GHG emissions. 

Response: The rule requires that flow and BOD5 or COD 

be monitored at the location of influent to the anaerobic 

treatment process. EPA disagrees that facilities should be 

allowed to use the flow and organic loading of treated 

effluent to estimate CH4 generation. CH4 generation is a 

function of the organic load into the treatment system. If 

facilities used measured treated effluent organic load, 

they would need to back-calculate the influent (untreated) 

load. This approach would require EPA to describe all 

possible treatment scenarios, which would make the rule 

cumbersome and overly complex. Facilities would be 

required to use complex and burdensome methodologies to 

back-calculate the influent load. 

Further, influent monitoring gives the most accurate 

determination of GHG emissions because it captures the 

inherent variability of the wastewater. In contrast, 
59

treated effluent characteristics typically have lower 

variability because high and/or variable influent 

concentrations have been reduced by treatment. 

EPA also disagrees that monitoring the influent to the 

anaerobic process would be difficult because it consists of 

multiple phases. EPA has revised 49 CFR 98.354(b) of the 

rule to clarify that flow and BOD5 or COD concentration must 

be monitored following all preliminary and primary 

treatment steps (e.g., after grit removal, primary 

clarification, oil-water separation, dissolved air 

flotation, or similar solids and oil separation processes). 

Such preliminary and primary treatment sufficiently removes 

the non-aqueous phases (oil, foam, suspended solids) that 

the wastewater stream that can be analyzed for BOD5 and COD 

without undue burden. 

EPA disagrees that the cost of monitoring would be an 

undue burden on facilities. The final rule continues to 

require facilities to collect and analyze samples of 

anaerobic treatment process influent no less than once per 

week. Weekly monitoring provides an adequate number of 

samples to evaluate the variability and uncertainty 

associated with CH4 generation. Less frequent monitoring 

would result in greater uncertainty and would not 
60

significantly reduce the costs compared to weekly 

monitoring. 

EPA has determined that the sampling methods contained 

in the rule are not unduly burdensome and still result in 

an accurate estimate of GHG emissions from industrial 

wastewater treatment processes for the purpose of this 

rulemaking. 

F. Industrial Waste Landfills (40 CFR part 98, subpart TT)

1. Summary of the Final Rule 

Source Category Definition. This source category 

consists of industrial waste landfills whose total landfill 

design capacity is greater than or equal to 300,000 metric 

tons and that accepted waste on or after January 1, 1980 

This source category does not include Resource 

Conservation and Recovery Act (RCRA) Subtitle C or Toxic 

Substances Control Act (TSCA) hazardous waste landfills, 

construction and demolition landfills, or landfills that 

only receive inert waste materials, such as coal combustion 

residue (e.g., fly ash), cement kiln dust, rocks and/or 

soil, glass, non-chemically bound sand (e.g., green foundry 

sand), clay, gypsum, pottery cull, bricks, mortar, cement, 

furnace slag, refractory material, or plastics. 

Deleted: S
61

Facilities that meet the applicability criteria in the 

General Provisions (40 CFR 98.2(a)) summarized in Section 

II.B of this preamble must report GHG emissions. 

GHGs to Report. For industrial waste landfills, 

facilities must report: 

 Annual CH4 generation and CH4 emissions from the 

industrial waste landfill. 

 Annual CH4 recovered (for landfills with gas collection 

and destruction systems). 

GHG Emissions Calculation and Monitoring. All 

facilities must ascertain annual modeled CH4 generation 

based on: 

 Measured or estimated values of historic annual waste 

disposal quantities; and 

 Appropriate values for model inputs (i.e., degradable 

organic carbon (DOC) fraction in the waste, CH4

generation rate constant). Default parameter values 

are specified for certain industries and for 

industrial waste generically. 

Facilities that do not collect and destroy landfill 

gas must adjust the annual modeled CH4 generation to account 

soil oxidation (CH4 that is converted to CO2 as it passes 

through the landfill cover before being emitted) using a 

default soil oxidation factor. The resulting value must be 

reported and represents both CH4 generation (corrected for 

oxidation) and CH4 emissions. 
62

Facilities that collect and destroy landfill gas must 

calculate the annual quantity of CH4 recovered and destroyed 

based on continuous monitoring of landfill gas flow rate, 

and continuous or weekly monitoring of CH4 concentration, 

temperature, pressure, and moisture of the collected gas 

prior to the destruction device. 

Those facilities that collect and destroy landfill gas 

must then calculate CH4 emissions in two ways and report 

both results. Emissions must be calculated by: 

1. Subtracting the measured amount of CH4 recovered 

from the modeled annual CH4 generation (with adjustments for 

soil oxidation and destruction efficiency of the 

destruction device) using the equations provided; and 

2. Applying a gas collection efficiency to the 

measured amount of CH4 recovered to “back-calculate” CH4

generation, then subtracting the measured amount of CH4

recovered (with adjustments for soil oxidation and 

destruction efficiency of the destruction device) from the 

back-calculated CH4 generation using the equations provided. 

A default collection efficiency of 75 percent is specified, 

but landfills should use a collection efficiency that takes 

into account collection system coverage, operation, and 

landfill cover materials. 

Formatted: Subscript

Formatted: Subscript

Formatted: Subscript

Formatted: Subscript

Formatted: Subscript

Formatted: Subscript
63

Data Reporting. In addition to the information 

required to be reported by the General Provisions (40 CFR 

98.3(c)), reporters must submit additional data that are 

used to calculate GHG emissions. A list of the specific 

data to be reported for this source category is contained 

in 40 CFR part 98, subpart TT. 

Recordkeeping. In addition to the records required by 

the General Provisions (40 CFR 98.3(g)), reporters must 

keep records of additional data used to calculate GHG 

emissions. A list of specific records that must be 

retained for this source category is included in 40 CFR 

part 98, subpart TT. 

2. Summary of Major Changes Since Proposal 

The major changes since proposal are identified in the 

following list. The rationale for these and any other 

significant changes can be found below or in “Mandatory 

Greenhouse Gas Reporting Rule: EPA’s Response to Public 

Comments, Subpart TT: Industrial Waste Landfills.” 

 A number of provisions were added to focus on 

industrial waste landfills that have a potential to 

generate significant quantities of methane rather than 

all landfills. These provisions include an exemption 

for landfills that did not accept any waste after 

January 1, 1980, an exemption of landfills with a 

total landfill design capacity of less than 300,000 

metric tons, and an exemption for landfills that only 

receive inert waste materials. 
64

 In addition to direct mass measurements for 

determining waste quantities for current reporting 

years, we also allow volume measurements, mass balance 

procedures, or number of truck loads. 

 Additional model defaults for industrial waste are 

included in the final rule and additional methods are 

provided to estimate DOC content of industrial solid 

waste streams. 

 For landfills with landfill gas recovery, all of the 

changes that were incorporated in the final 40 CFR 

part 98, subpart HH rule (allowing weekly sampling and 

direct flame ionization methods) are also included in 

this final rule for industrial waste landfills (by 

cross-referencing the final requirements in 40 CFR 

part 98, subpart HH). For additional details 

regarding the changes in the landfill gas recovery 

monitoring requirements, see the final preamble for 

the 40 CFR part 98, subpart HH [Municipal Solid Waste 

Landfills] rule at 74 FR 56336. 

3. Summary of Comments and Responses 

This section contains a brief summary of major 

comments and responses. EPA received many comments on this 

subpart covering numerous topics. EPA’s responses to these 

significant comments can be found in the comment response 

document for industrial waste landfills in “Mandatory 

Greenhouse Gas Reporting Rule: EPA’s Response to Public 

Comments, Subpart TT: Industrial Waste Landfills.” 

Definition of Source Category 

Comment: Many commenters stated that landfills 

containing inert industrial wastes should not be subject to 

this proposed rule because inert wastes do not generate 

methane via anaerobic processes. Inert wastes, according 

Deleted: degradable organic 

carbon 
65

to various commenters, include: construction and 

demolition waste, coal combustion residue monofills, 

geothermal filter cake waste landfills, waste rock 

landfills at coal mines, plastics, soils from construction 

and other site activities, hazardous waste landfills, solid 

waste management units (SWMUs) and non-hazardous landfills 

located at refineries, agricultural waste landfills 

associated with sugar mills, pottery cull, gypsum, clays, 

green sand, resin sand, refractory, slag, carbon and 

graphite manufacturing byproducts. 

Several commenters stated that the rule would be very 

burdensome for industrial waste landfills with inert waste 

streams and that EPA has not sufficiently justified its 

decision to make all industrial waste landfills, regardless 

of typical byproduct waste characteristics, meet the 

provisions proposed. 

Rather than listing specific exclusions, several 

commenters stated that EPA should do as suggested by the 

proposed rule and limit the requirements of the rule to 

landfills located at food processing, pulp and paper and 

ethanol production facilities which are known for methane 

gas generation; several commenters also included petroleum 

refineries in this list. One commenter suggested that 

ethanol production facilities should not be required to 
66

report landfill emissions because emissions from landfills 

at these facilities are so small. 

A number of other exemptions were suggested by 

different commenters, including: 

 Exempt inactive landfills, from which emissions are 

small. 

 Exempt facilities that are not required to monitor 

methane or install and operate any methane control 

facilities under State permitting in order to keep the 

requirements simple and not overly burdensome. 

 Exempt on-site industrial waste landfills that have 

been closed under RCRA because they have little or no 

potential for air emissions and would create an 

unnecessary compliance burden. 

Response: We agree that there will be negligible 

methane emissions from landfills that contain only inert 

waste materials because they do not have organic materials 

that would emit methane after being placed in an industrial 

landfill. Therefore, we investigated alternative 

applicability requirements for industrial waste landfills 

to target the reporting requirements to landfills that are 

expected to produce significant amounts of methane. Based 

on an analysis of various options (see the “Technical 

Support Document for Industrial Waste Landfills” in Docket 

No. EPA-HQ-OAR-2008-0508), we decided to exclude from the 

industrial waste landfill reporting requirements landfills 

that are used exclusively to dispose of inert materials or 

“inorganic” wastes. Specific types of wastes that are 

Deleted: s

Deleted: ,
67

expected to be inert in the landfill (e.g., bricks, glass, 

plastics, rocks, and fly ash) are listed. This list of 

inert waste types also includes wastes that contain 0.5 

weight percent (dry basis) or less of volatile solids as a 

means for industrial waste landfill owners and operators to 

characterize a waste stream as “inorganic” if the waste 

stream is not already on the list of inert materials. We 

did not provide exemptions for specific industries nor 

limit coverage to specific industries (e.g., ethanol 

production, food processing, or pulp and paper facilities) 

because the waste material generated and managed in a 

landfill at any given facility can be widely different, 

even within a given industry sector. As such, we 

determined that the waste material exclusions provided a 

better mechanism to exclude inert materials without 

omitting waste materials that have high organic content. 

Additional rationale regarding waste materials that were 

not specifically excluded is provided in the following 

paragraph. 

 Geothermal filter cake. We anticipate that geothermal 

filter cake would be included in the exemption for 

rocks and soil from excavation activities. If this 

filter cake includes other materials, the landfills 

managing this waste may still be exempted if the waste 

can be shown to contain 0.5 weight percent (dry basis) 

or less of volatile solids. We note that this 

exclusion applies to any waste material at any 
68

industrial waste landfill (i.e., any of the following 

bullets). 

 Landfills at petroleum refineries. We did not exclude 

landfills at petroleum refineries because we 

anticipate that refinery waste materials will contain 

significant amounts of DOC.

 Agricultural wastes at sugar mills. Again, we did not 

exclude these wastes because we anticipate that the 

waste may contain significant amounts of DOC(scraps of 

sugar canes). 

 Resin sand. While we excluded green sand (i.e., “nonchemically” bound sand, we did not exclude resin sand 

because resin sand generally contains organic chemical 

binders that can degrade in landfills and generate 

methane emissions. 

 Carbon and graphite wastes. These wastes are expected 

to contain significant amounts of carbon. It is 

unclear if the carbon material can be degraded. 

However, with the information currently available 

regarding this waste stream, we could not conclude 

that these wastes are inert. If the graphite does not 

contain volatile impurities, it may be possible to 

exempt these wastes by demonstrating that the waste 

material contains 0.5 weight percent (dry basis) or 

less of volatile solids. 

We also limited the reporting requirements for 

industrial waste landfills to facilities whose total 

landfill design capacity is greater than or equal to 

300,000 metric tons. Our analysis indicated that there are 

a large number of very small industrial waste landfills. 

Approximately two-thirds of the total number of potentially 

affected industrial waste landfills have a total landfill 

design capacity of less than 300,000 metric tons, and these 

landfills are projected to contribute only 7 percent of the 

total GHG emissions from industrial waste landfills. 

Deleted: degradable organic 

carbon

Deleted: degradable organic 

carbon 
69

Landfills with a design capacity of less than 300,000 

metric tons are expected to have emissions well below 

25,000 metric tons CO2e. Landfills of this size would not 

be required to report emissions if they were not co-located 

at an industrial facility that has other emission sources 

exceeding the reporting threshold. The incremental costs 

for requiring these small co-located industrial waste 

landfills to report their landfill emissions was 

approximately $1.25 per additional metric tons CO2e reported 

(1st year costs), compared to approximately $0.05 per metric 

tons CO2e reported (1st year costs) for facilities with 

landfills whose total landfill design capacity is greater 

than or equal to 300,000 metric tons. 

We also agree that certain inactive landfills can be 

excluded from the GHG reporting requirements. As described 

in the preamble to the final rule for municipal solid waste 

(MSW) landfills (74 FR 56335), landfills that have been 

closed over 30 years represent a small fraction of GHG 

emissions from landfills and are not relevant for purposes 

of policy analysis. Therefore, we also limit the reporting 

requirements for industrial waste landfills to facilities 

that received waste on or after January 1, 1980. 

We disagree that only industrial waste landfills that 

are required to monitor for methane or that are required to 
70

capture and destroy methane emissions should be included in 

the rule. Methane has not traditionally been a pollutant 

for which monitoring or destruction requirements have been 

established. We do not know of any such requirements, and 

available information indicates that few, if any, 

industrial waste landfills have methane capture and 

destruction equipment. Although few industrial landfills 

capture and destroy methane, that does not mean that these 

landfills do not generate methane in significant 

quantities. 

As proposed, the industrial waste landfill source 

category did not include hazardous waste landfills or 

dedicated construction and demolition landfills. The final 

rule also excludes these landfills, however, we have 

clarified that hazardous waste landfills refers to those 

subject to RCRA Subtitle C or TSCA requirements. These 

landfills are excluded due to the landfill design 

requirements, such as “dry tomb” methods, which are 

expected to minimize methane production. 

We have not exempted Comprehensive Environmental 

Response, Compensation, and Liability Act (CERCLA) 

(Superfund) landfills. Generally, landfills become listed 

as CERCLA sites because the landfills were not designed for 

hazardous wastes but some hazardous materials were disposed 
71

of in the landfill and subsequently these materials 

contaminated the groundwater. Thus, these landfills were 

not designed and operated in a manner similar to RCRA 

Subtitle C or TSCA landfills. Furthermore, the remediation 

requirements for CERCLA landfills are determined on a sitespecific basis, and these methods generally do not 

necessarily require significant changes to the landfill. 

For example, clean-up efforts focused on groundwater 

remediation may pump and treat the contaminated groundwater 

and recirculate the treated groundwater to the landfill. 

This technique can be used to clean-up the groundwater and 

leach any other remaining contaminants from the landfill, 

but this technique will enhance rather than limit methane 

generation from the landfill. Consequently, landfills that 

are subsequently listed by States as “hazardous” for the 

purposes of CERCLA (Superfund) or similar State programs 

are not excluded from the industrial waste landfill source 

category. 

In summary, the final industrial waste landfill rule 

does not apply to: 1) industrial waste landfills that have 

not accepted waste on or after January 1, 1980; 2) 

industrial waste landfills that have a total design 

capacity of less than 300,000 metric tons; 3) RCRA Subtitle 

C or TSCA hazardous waste landfills; 4) dedicated 

Deleted: s
72

construction and demolition landfills; and 5) industrial 

waste landfills that receive only one or more of the 

following types of waste materials: coal combustion residue 

(e.g., fly ash); cement kiln dust; rocks and/or soil from 

excavation and construction and similar activities; glass; 

non-chemically bound sand (e.g., green foundry sand); clay, 

gypsum, or pottery cull; bricks, mortar, or cement; furnace 

slag; materials used as refractory (e.g., alumina, silicon, 

fire clay, fire brick); plastics; or other waste material 

that has a volatile solids concentration of 0.5 weight 

percent (on a dry basis) or less. 

Method for Calculating GHG Emissions 

Comment: Several commenters suggested that EPA not 

require direct measurement of the waste entering the 

landfill. One commenter noted that there are materials 

that are conveyed and sluiced to solid waste disposal areas 

that could not be monitored across truck scales. The 

commenters suggested a number of alternatives to direct 

mass measurements, which include: 

 Allow the use of company records. 

 Allow the use of any measurement method specified in 

an applicable permit or any reasonable estimation 

method that is adequately documented. 

 Allow the use of typical waste disposal records and 

other testing on parameters such as density and 

chemical analysis. 
73

 Allow periodic calibration of the trucks hauling 

landfill waste to determine the weight to volume ratio 

of various waste streams provides a practical 

measurement for industrial waste landfills. 

 Allow estimation methods outlined in the proposal to 

calculate previous years’ data be applied in future 

years (i.e., require direct waste measurements for 

only one year). 

Response: Unlike MSW landfills, many industrial waste 

landfills do not directly weigh waste loads as they enter 

the landfill. We reevaluated the cost of requiring direct 

mass measurements for industrial waste landfills. 

According to one of the commenters, the capital cost of 

installing scales could be as much as $50,000 each, with 

operating and driver time resulting in an estimated 

annualized cost of over $23,000. We also considered the 

uncertainty associated with different measuring methods and 

their resulting uncertainty in the overall modeled methane 

generation. Given the significant additional costs for 

requiring direct mass measurements at industrial waste 

landfills and the limited improvement in the uncertainty of 

the reported methane emissions, we revised the rule so that 

direct mass measurements are not required for industrial 

waste landfills. 

In 40 CFR 98.463 of the final rule, industrial waste 

landfills that are subject to the rule are given several 

options for determining the current waste quantities and 
74

historical values for waste quantities and DOC. The types 

of processes that generate the waste, the types of waste 

generated, and the means by which the wastes are 

transported or conveyed to the landfill are very diverse. 

As such, different methods of determining these waste 

quantities are needed. Consequently waste quantities 

determined for years for which emissions reports are 

required may be determined by any of the following methods: 

direct mass measurements; volume measurements and waste 

stream density determined from measurement data or process 

knowledge; mass balance procedures, determining the mass of 

waste as the difference between the mass of the process 

inputs and the mass of the process outputs; and the number 

of loads (e.g., trucks) and the mass of waste per load 

based on the working capacity of the container or vehicle. 

We determined these methods accommodate the approaches 

requested by the commenters except for the last bulleted 

item. We do not agree with the commenter’s request to 

allow projections of waste quantities disposed of after the 

first reporting year based on processing rate correlations 

used to project historical waste quantities. This method 

would not account for processing changes that may reduce 

(or increase) the waste generation rate. Given the 

flexibility in determining waste disposal quantities in a 

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carbon (

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75

given reporting year, we determined that the costs of 

determining these waste quantities as provided in the final 

rule are reasonable and that the provided methods would 

produce more accurate values for the purposes of reporting 

than the “future” projection of waste quantities based on a 

single year of measurement data. 

We also provide a number of methods by which 

historical waste quantities must be determined subject to 

the hierachy of available data. Historical waste 

quantities must be determined using the methods specified 

for current waste quantities when that information is 

available. For years when waste quantity data are not 

available, historical waste quantities must be estimated 

using production or processing rates when these data are 

available. For years when neither waste quantity data nor 

production/processing rate data are available, historical 

waste quantities must be estimated based on the capacity of 

the landfill used and the number of years the landfill has 

accepted waste. 

Comment: Several commenters requested that more 

information be provided in the rule to calculate GHG

emissions from industrial waste landfills, including an 

expansion of the type of information in Table HH-1 of the 

rule, especially if reporting of GHG emissions from 

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76

industrial waste landfills is not limited to the food 

processing, pulp and paper, and ethanol production 

facilities. One commenter suggested that, if there are no 

DOC or k parameters in Table HH-1 for a given waste 

category, such as boiler ashes, reporters should assume 

they are zero and that no CH4 is generated from that waste. 

According to the commenter, this assumption would more 

accurately calculate CH4 emissions from a landfill by 

excluding quantities of inert wastes rather than assuming 

all wastes generate CH4. 

Response: We have specifically included a default DOC 

value of zero for inert materials in Table TT-1. Inert 

material is described as any waste material (such as glass, 

cement, and fly ash) that is specifically listed in 

§98.460(b)(3) paragraphs (i) through (xii). As discussed 

previously, industrial waste landfills that receive only 

inert materials are not required to report, but landfills 

that receive both degradable organic and inert waste 

streams may use the default DOC for the quantity of inert 

material disposed of in the industrial waste landfill. For 

all other (non-inert) waste materials, the final rule 

allows either the use of Table TT-1 to determine the 

default values for DOC or the use of measured, waste 

stream-specific DOC values following the methods provided 
77

in the final rule. In addition to default DOC and k values 

for selected industries, we have also included in Table TT1 of 40 CFR part 98, subpart TT default DOC and k value for 

“other solid industrial waste (not otherwise specified).” 

As such, there should no longer be an “unlisted” waste 

stream. 

Costs 

Comment: One commenter stated that EPA presents its 

summary cost analysis data in the preamble with further 

details in the accompanying regulatory impact analysis 

(RIA) report. The commenter stated that EPA presented cost 

data for each of the subparts separately but fails to 

consider the overall burden per facility of complying with 

multiple subparts, including landfills, as is the case with 

most industrial facilities. 

Response: EPA agrees that the costs facing facilities 

in some sectors include not only process costs but 

additional costs associated with other subparts in the 

rule. While these costs are presented individually in the 

costs tables, where these conditions apply the costs are 

summed across applicable subparts and compared to revenues 

in the economic and small entity impact analyses. In 

response to comments on this issue, we revised the RIA of 

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78

the 2009 final rule to more clearly describe the approach 

taken. The same approach has been taken for this rule. 

III. Other Source Categories Proposed in 2009 

A. Overview

With this action EPA has made the final decision not 

to include Ethanol Production or Food Processing as 

distinct subparts in 40 CFR part 98. This decision does 

not change the applicability requirements under other 

subparts of this rule that may affect these industries. 

Further explanation of this decision is included in Section 

III.B and III.C of this preamble. EPA has also made the 

final decision to not include Suppliers of Coal in 40 CFR 

part 98 at this time. Further explanation of this decision 

is included in Section III.D of this preamble. 

B. Ethanol Production

EPA has made the final decision not to include Ethanol 

Production (proposed as 40 CFR part 98, subpart J) as a 

distinct subpart in 40 CFR part 98. EPA has determined 

that it is not necessary to include 40 CFR part 98, subpart 

J in order to cover ethanol facilities in the final rule. 

Thus, although there is no distinct subpart applicable to 

ethanol production, these facilities will still be subject 

to the final rule (if emissions exceed the applicable 

threshold) and the overall coverage of the final rule 

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regarding these facilities is the same as that of the 

proposed rule. 

The proposal for this subpart (74 FR 16448, April 10, 

2009) did not include any unique requirements for 

monitoring or reporting of process emissions from ethanol 

production facilities. Instead, the proposed subpart 

simply referred to reporting that those facilities might be 

required to do under other subparts, namely, 40 CFR part 

98, subpart C-Stationary Combustion, subpart HH-Landfills, 

and subpart II-Wastewater Treatment. 

EPA received many comments on this subpart covering 

various topics. EPA’s response to these comments can be 

found in the comment response document for ethanol 

production in “Mandatory Greenhouse Gas Reporting Rule: 

EPA’s Response to Public Comments, Subpart J: Ethanol 

Production” 

40 CFR part 98, subpart J was originally included as a 

distinct subpart to clearly indicate that these facilities 

must aggregate emissions from all source categories when 

determining whether emissions exceeded the applicable 

threshold. As structured, the proposed subpart 

specifically required that emissions from stationary 

combustion, on-site landfills, and on-site wastewater 

treatment were to be aggregated in determining the 

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80

reporting threshold and reporting emissions from these 

facilities. 

Upon closer examination of 40 CFR 98.2(a), it is clear 

that ethanol production facilities are already required to 

report if they meet the threshold of 25,000 tons CO2e by 

aggregating emissions from all applicable source categories 

in the rule including stationary combustion, industrial 

wastewater treatment, industrial waste landfills, 

miscellaneous use of carbonates, and any others that may 

apply. In fact, any type of facility not specifically 

identified in a subpart must report their GHG emissions if 

that facility contains source categories itemized by the 

rule and their aggregate emissions meet the applicable 

threshold. 

Note that in this final rule, ethanol production 

facilities are among those specifically identified in 40 

CFR part 98, subpart II – Industrial Wastewater Treatment 

and are required to report if they meet the applicability 

provisions in 40 CFR 98.2(a)(2). Thus for clarity, the 

definition of ethanol production facility is included in 40 

CFR 98.358. 

Again, in sum, EPA has determined that it is not 

necessary to include 40 CFR part 98, subpart J in order to 

cover ethanol facilities in the final rule. Moreover, 

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81

highlighting the ethanol production (and food processing) 

categories as being covered by the rule due to emissions 

covered by other source categories may give the false 

impression that there are not any other types of sources 

that may be covered by the rule due to their aggregate 

emissions from stationary combustion, industrial waste 

landfills and/or industrial wastewater treatment. 

C. Food Processing 

EPA has made the final decision not to include Food 

Processing (proposed as 40 CFR part 98, subpart M) as a 

distinct subpart in 40 CFR part 98. EPA had determined 

that it is not necessary to include 40 CFR part 98, subpart

M in order to cover food processing facilities in 40 CFR 

part 98. Thus, although there is no distinct subpart 

applicable to food processing, these facilities will still 

be subject to the final rule (if emissions exceed the 

applicable threshold) and the overall coverage of the final 

rule regarding these facilities is the same as that of the 

proposed rule. 

The proposal for this subpart (74 FR 16448, April 10, 

2009) did not include any unique requirements for 

monitoring or reporting of process emissions from food 

processing facilities. Instead, the proposed subpart 

simply referred to reporting that those facilities might be 

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82

required to do under other subparts, namely, 40 CFR part 

98, subpart C-Stationary Combustion, subpart HH-Landfills, 

and subpart II-Wastewater Treatment. 

EPA received many comments on this subpart covering 

various topics. EPA’s response to these comments can be 

found in the comment response document for food processing 

in “Mandatory Greenhouse Gas Reporting Rule: EPA’s Response 

to Public Comments, Subpart M: Food Processing” 

40 CFR part 98, subpart M was originally included as a 

distinct subpart to clearly indicate that these facilities 

must aggregate emissions from all source categories when 

determining whether emissions exceeded the applicable 

threshold. As structured, the proposed subpart 

specifically required that emissions from stationary 

combustion, on-site landfills, and on-site wastewater 

treatment were to be aggregated in determining the 

reporting threshold and reporting emissions from these 

facilities. 

Upon closer examination of 40 CFR 98.2(a), it is clear 

that food processing facilities are already required to 

report if they meet the threshold of 25,000 tons CO2e by 

aggregating emissions from all applicable source categories 

in the rule including stationary combustion, industrial 

wastewater treatment, industrial waste landfills, 

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Deleted: .
83

miscellaneous use of carbonates, and any others that may 

apply. In fact, any type of facilities not specifically 

identified in a subpart must report their GHG emissions if 

that facility contains source categories itemized by the 

rule and their aggregate emissions meet the applicable 

threshold. 

Note that in this final rule, food processing 

facilities are among those specifically identified in 40 

CFR part 98, subpart II – Industrial Wastewater Treatment 

and are required to report if they meet the applicability 

provisions in 40 CFR 98.2(a)(2). Thus, for clarity, a 

definition of food processing facility is included in 40 

CFR 98.358. 

Again, in sum, EPA has determined that it is not 

necessary to include 40 CFR part 98, subpart M in order to 

cover food processing facilities in the final rule. 

Moreover, highlighting the food processing (and ethanol 

production) categories as being covered by the rule due to 

emissions covered by other source categories may give the 

false impression that there are not any other types of 

sources that may be covered by the rule due to their 

aggregate emissions from stationary combustion, industrial 

waste landfills and/or industrial wastewater treatment. 

D. Suppliers of Coal

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84

As proposed (74 FR 16448, April 10, 2009) 40 CFR part 

98, subpart KK would have required that all coal mines, 

coal importers and exporters, and coal waste reclaimers 

report the amount of coal produced or supplied to the 

economy annually, as well as the CO2 emissions that would 

result from complete oxidation or combustion of this 

quantity of coal. After reviewing the comments received on 

the proposal as well as other available information, EPA 

has made a final decision not to include Suppliers of Coal 

(proposed as 40 CFR part 98, subpart KK) in 40 CFR part 98

at this time. 

EPA’s rationale for not requiring reporting from coal 

suppliers at this time is that (i) the overlap in reporting 

from upstream coal suppliers and downstream emitters is 

almost 100 percent indicating that double-reporting does 

not provide more complete information to EPA, unlike with

other upstream supplier subparts (e.g., 40 CFR part 98, 

subpart MM and NN), and (ii) the high accuracy of the 

downstream reporting provisions in 40 CFR part 98 provide 

more than adequate emissions data for anticipated near-term 

uses. 

The overall purpose of 40 CFR part 98 is to collect 

information to inform the development of future climate 

policy and programs under the CAA. In the context of GHG 

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85

emissions from coal consumption, EPA seeks information on 

the magnitude and location of facility-level emissions 

across the economy as well as overall emissions at the 

national level. These near-term needs can be met with high 

accuracy and at principally the same coverage through 

existing reporting requirements for direct emitters under 

40 CFR part 98, primarily through reporting under 40 CFR 

part 98, subparts C, D, and Q. For example, the existing 

40 CFR part 98, subpart D, which accounts for approximately 

94 percent of emissions from the use of coal, builds on 

rigorous monitoring requirements of 40 CFR part 75. Coalfired electricity generating units subject to 40 CFR part 

75 typically use continuous emissions monitoring equipment 

that measures actual carbon dioxide emissions hourly. 

Furthermore, 40 CFR part 98 requires rigorous Tier 3 and 

Tier 4 reporting at industrial facilities with large units 

combusting coal and other solid fuels. Reporting 

requirements under 40 CFR part 98, subpart C (general 

stationary combustion) and 40 CFR part 98, subpart D

(electricity generation) will allow EPA to obtain data on 

more than 99 percent of total CO2 emissions from coal 

combustion through existing reporting provisions of 40 CFR 

part 98. The proposed 40 CFR part 98, subpart KK 

procedures would have covered approximately 100 percent of 

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GHG Rreporting Rrule (MRR)

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Deleted: P

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86

coal supplied to the economy and resulting downstream CO2 

combustion emissions. The difference in combustion 

coverage of less than 1 percent is estimated to come from 

the smallest consumers of coal, such as home owners for use 

in heating. 

Furthermore, EPA’s near-term needs regarding the data 

can be met with higher accuracy through existing reporting 

requirements for direct emitters. Under the proposed 40 

CFR part 98, subpart KK, approximately 50 percent of coal 

suppliers would have used engineering calculations to 

correlate HHV from daily coal samples with carbon content 

from either daily or monthly coal samples, assuming those 

are representative of the entire coal stream. For the 

remaining coal mines, the proposed 40 CFR part 98, subpart 

KK procedures would have relied on default CO2 emissions 

values, which are less accurate than direct measurement and 

would not have supplied mine specific data. Furthermore, 

existing reporting procedures for direct emitters account 

for the combustion efficiency of the facility rather than 

assume 100 percent combustion or oxidation as was proposed 

in 40 CFR part 98, subpart KK. 

While EPA believes that the proposal had a pragmatic 

approach to balancing accuracy and cost, it is clear that 

the upstream data under proposed 40 CFR part 98, subpart KK 

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87

would not have been as accurate as the more rigorously 

monitored data reported by direct emitters. In sum, 

including proposed 40 CFR part 98, subpart KK would have 

provided EPA with a near negligible amount of additional 

information on emissions, while not achieving the same 

level of accuracy as the existing reporting downstream. 

Though cost and burden are not reasons for EPA’s 

decision to exclude 40 CFR part 98, subpart KK, EPA notes 

that changing the 40 CFR part 98, subpart KK proposal to 

require more rigorous reporting on par with downstream 

requirements would have raised the costs and burden of 

proposed 40 CFR part 98, subpart KK significantly. In the 

proposed Regulatory Impacts Analysis Cost Appendix Section 

29, EPA assumed that 52 percent of coal mines (706) mines 

would meet 40 CFR part 98, subpart KK requirements by 

sampling and testing for coal content monthly and that 48 

percent (659 mines) would meet requirements by using 

default factors. To raise the reporting rigor, EPA would 

have had to require 100 percent of coal mines (1,365 mines) 

to sample and test coal content daily. 

In addition, there is other information available to 

EPA such as the Inventory of U.S. Greenhouse Gas Emissions 

Deleted: in the MRR GGRR 

Deleted: from the MRRGGRR

Deleted: 

Deleted: In addition, there 

is other information 

available to EPA 
88

and Sinks5

, other data reported by coal-fired electricity 

generating units to EPA’s Acid Rain Program, and the Energy 

Information Administration’s (EIA) detailed coal 

production, consumption, imports and exports data.6 The 

national GHG inventory tracks CO2 emissions from the 

combustion of coal across the entire economy for each year 

since 1990 and breaks down emissions according to economic 

sector. From this data set EPA determined that in 2007, 

electricity generation accounted for approximately 94

percent of all CO2 emissions from coal combustion. The 

remaining emissions from coal consumption come primarily 

from the industrial sector. EIA collects and publishes 

annual data on coal production, consumption, imports and 

exports, thus providing an additional source of information 

to serve as a check on estimates of emissions from this 

sector and to inform potential policies and programs 

related to coal supply. As EPA has stated in this preamble 

and in the original 40 CFR part 98, subpart KK proposal, 

rigorous, direct CO2 emissions measurements of coal 

combustion are preferred by EPA over the use of default CO2

values for informing policies and programs that relate to 

stationary source emissions. However, policies and 

programs of another nature for which default emissions 

 

5 http://www.epa.gov/climatechange/emissions/usinventoryreport.html 6

 http://www.eia.doe.gov/fuelcoal.html

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89

values are more appropriate and have been previously used 

by EPA, such as life cycle emissions considerations for 

National Environmental Policy Act (NEPA) analyses and 

federal government climate change contribution analyses, 

can be adequately informed at this time by existing EIA 

data on coal production and default CO2 emissions values.

EPA views potential double-reporting for emissions 

from other fossil fuels as appropriate where downstream 

reporting of all or the large majority of emissions is 

impractical and where the upstream and downstream reporting 

combine to provide the complete picture. Near complete 

downstream coverage, as is achieved with coal, is not 

possible for downstream users of petroleum, natural gas, or 

industrial gases. In many cases, the fossil fuels and 

industrial GHGs supplied by producers and importers are 

used and ultimately emitted by a large number of small 

sources, particularly in the commercial and residential 

sectors (e.g., HFCs emitted from home air conditioning 

units or CO2 emissions from individual motor vehicles). EPA 

would have had to require reporting by hundreds or 

thousands of small facilities to cover all direct 

emissions. EPA determined it was more appropriate to 

require reporting by the suppliers of petroleum products, 

natural gas and natural gas liquids, and industrial gases 

Deleted: EPA

Deleted: most useful 

Deleted: ,

Deleted: To account for these 

direct emissions would 

Deleted: To avoid this 

impact, the rule does not 

include all of those 

emitters, but instead re

Deleted: s
90

and CO2. As exhibited by Table 5-18 of the RIA of the 

October 2009 Final Rule, the downstream emitters 

requirements of the October 2009 Final Rule account for 

only 20 percent of petroleum supply, approximately 23

percent of natural gas supply and 28 percent of industrial 

gas supply. Comparatively, requiring reporting by 

suppliers of these fuels, accounts for a much larger 

percentage of emissions (100 percent for petroleum and 

industrial gas suppliers and approximately 68 percent for 

natural gas suppliers). 

Some commenters suggested that 40 CFR part 98, subpart 

KK data on the carbon content of all coal supplied would 

have informed the downstream effects of emissions changes 

resulting from the changing carbon intensity of the fuel 

(which in turn assists in analyses such as Best Available 

Control Technology (BACT)). EPA notes that it did not 

propose that facilities affected by 40 CFR part 98, subpart 

KK would report information on their customers because coal 

from multiple suppliers can be blended together and sent to 

multiple customers. Therefore information on downstream 

effect would not have been available for use from the 

proposed 40 CFR part 98, subpart KK. For other upstream 

categories, EPA also did not propose and does not require 

detailed information about specific customers. If EPA 

Deleted: egulatory Impact 

Analysis 

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Deleted: reports by 

Deleted: f

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Deleted: %

Deleted: %

Deleted: %

Deleted: %

Deleted: %

Deleted: subpart

Deleted: rule

Deleted: or National 

Environmental Policy Act 

(NEPA)). Because among 

other things coal from 

multiple suppliers can be 

blended together and sent to 

multiple customers, EPA 

proposed that facilities 

affected by 40 CFR part 98, 

subpart KK would not report 

information on their 

customers. This would have 

made use of the data very 

difficult. 
91

determines that such type of carbon content data are 

necessary for a specific analysis or determination, the 

Agency can request it at that time. The robust data being 

collected now on downstream CO2 emissions are adequate for 

general policy analysis and will assist the Agency in 

targeting additional information requests in the future. 

EPA’s final decision is entirely consistent with the 

language of the various appropriations acts authorizing the 

expenditure of money for the reporting rule. The language 

in the FY2008 Appropriations Act instructed EPA to spend 

the money on a rule requiring reporting “in all sectors of 

the economy.” The Joint Explanatory Statement provided

that EPA should include upstream production “to the extent 

that the Administrator deems appropriate.” The 

appropriations language grants EPA much discretion to 

determine the appropriate source categories to include in 

the reporting rule. 

The phrase “all sectors of the economy” is not further 

elaborated in the FY2008 or later appropriations language. 

The term is ambiguous, and EPA may interpret it in any 

reasonable manner. See Chevron, U.S.A. v. NRDC, 467 U.S. 

837 (1984). Notably, the phrase is not “all industrial

sectors” but rather “all sectors of the economy.” There is 

a difference between an industrial sector and a sector of 

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92

the economy. The former typically refers to a specific 

type of industry, while the latter refers to categories of 

industries or businesses. For example, the North American 

Industrial Classification System (NAICS) is a two- through 

six-digit hierarchical classification system, offering five 

levels of detail, ranging from the broad economic sector to 

the narrower national industry. See

http://www.census.gov/eos/www/naics/faqs/faqs.html#q5 (last 

visited May 10, 2010)(“Each digit in the code is part of a 

series of progressively narrower categories, and the more 

digits in the code signify greater classification detail. 

The first two digits designate the economic sector, the 

third digit designates the subsector, the fourth digit 

designates the industry group, the fifth digit designates 

the NAICS industry, and the sixth digit designates the 

national industry.”).7 

In the proposed rule, EPA used the term “sector” to 

refer both to different types of sectors of the economy and 

specific industrial sectors or source categories. Compare 

74 FR 16467/1 (referring to source categories in the 

“agricultural and land use sectors”) to 74 FR 16488/1 

(referring to “adipic acid production sector”). 

 

7

 Although we cite to the NAICS system as an example illustrating that sectors 

of the economy are considered to be broader than industrial groupings, we are 

not indicating that we think the appropriations language requires EPA to cover 

sources from the 20 sectors covered by the NAICS. 
93

Unfortunately, that usage may have caused some confusion, 

and lead some stakeholders to believe that the two types of 

sectors are interchangeable and equivalent. But as noted 

above, there are differences among between sectors of the 

economy, industrial sectors and source categories in the 

reporting rule. EPA can cover a sector of the economy in 

the reporting rule without covering every type of source in 

that sector of the economy. 

40 CFR part 98 already covers a broad and diverse 

selection of sources and emissions in the various sectors 

of the economy (e.g., fuel and industrial gas suppliers, 

motor vehicle manufacturers, underground coal mines, 

manufacturing facilities, universities and other facilities 

with stationary combustion). While EPA considers it 

reasonable to include more than one source category in any 

given sector of the economy, it is not required to include 

every possible source category.

In any event, the appropriations language at most 

denotes a Congressional intent to ensure that emissions 

from various economic sectors are covered by the rule. As 

noted above, 40 CFR part 98 already adequately covers 

emissions from coal combustion even without getting 

additional information from coal suppliers.

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rule

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rule
94

Finally, the Joint Explanatory Statement already 

contemplated that the Administrator may not “deem[] it 

appropriate” to include all possible upstream production 

and downstream sources. As explained above, the October 

2009 Final Rule already thoroughly covers the emissions 

that result from coal combustion. That information, 

combined with other sources of information regarding the 

coal supply available to EPA, makes EPA’s decision that it 

is not “appropriate” at this time to not include coal 

suppliers in the rule entirely reasonable.

EPA will continue to assess the need for reporting 

from coal suppliers in the future in light of new 

information or identification of policy or program needs. 

If EPA were to decide in the future to add coal suppliers 

to 40 CFR part 98 it would initiate a new rulemaking 

process. 

IV. Economic Impacts on the Rule 

This section of the preamble examines the costs and 

economic impacts of the proposed rulemaking and the 

estimated economic impacts of the rule on affected 

entities, including estimated impacts on small entities. 

Complete detail of the economic impacts of the final rule 

can be found in the text of the EIA in the docket for this 

rulemaking (EPA-HQ-OAR-2008-0508). 

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analysis (

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95

A large number of comments on economic impacts of the 

rule were received covering numerous topics. Responses to 

significant comments received can be found in “Mandatory 

Greenhouse Gas Reporting Rule: EPA’s Response to Public 

Comments, Cost and Economic Impacts of the Rule.” 

Additional subpart specific comments and responses can be 

found in EPA’s Response to Public Comments subpart specific 

documents.

A. How were compliance costs estimated?

1. Summary of Method Used to Estimate Compliance Costs 

EPA used available industry and EPA data to 

characterize conditions at affected sources. Incremental 

monitoring, recordkeeping, and reporting activities were 

then identified for each type of facility and the 

associated costs were estimated. The annual costs reported 

in 2006$. EPA’s estimated costs of compliance are 

discussed below and in greater detail in Section 4 of the 

EIA (EPA-HQ-OAR-2008-0508): 

Labor Costs. The vast majority of the reporting costs 

include the time of managers, technical, and administrative 

staff in both the private sector and the public sector. 

Staff hours are estimated for activities, including: 

 Monitoring (private): staff hours to operate and 

maintain emissions monitoring systems. 

Deleted: s

Deleted: economic impact 

analysis (

Deleted: )
96

 Recordkeeping and Reporting (private): staff hours to 

gather and process available data and reporting it to 

EPA through electronic systems. 

 Assuring and releasing data (public): staff hours to 

quality assure, analyze, and release reports. 

Staff activities and associated labor costs will 

potentially vary over time. Thus, cost estimates are 

developed for start-up and first-time reporting, and 

subsequent reporting. Wage rates to monetize staff time 

are obtained from the Bureau of Labor Statistics (BLS). 

Equipment Costs. Equipment costs include both the 

initial purchase price and any facility modification that 

may be required. Based on expert judgment, the engineering 

costs analyses annualized capital equipment costs with 

appropriate lifetime and interest rate assumptions. Onetime capital costs are amortized over a 10-year cost 

recovery period at a rate of 7 percent. 

B. What are the costs of the rule?

1. Summary of Costs 

The total annualized costs incurred under the 

reporting rule would be approximately $7.0 million in the 

first year and $5.5 million in subsequent years ($2006). 

This includes a public sector burden estimate of $0.3 

million for program implementation and verification 

activities. Table 3 of this preamble shows the first year 

and subsequent year costs by subpart. In addition, it 

Deleted: 7seven
97

presents the relative share of the total cost represented 

by each subpart. 

Table 3. National Annualized Mandatory Reporting Costs 

Estimates (2008$): Subparts T, KK, II, and TT 

First Year 

Subsequent 

Years 

Subpart

2007 

NAICS

Millions 

2006$ Share 

Millions 

2006$ Share 

Subpart T – 

Magnesium 

Production 

331419 and 

331492 $0.1 2% $0.1 2% 

Subpart FFUnderground Coal 

Mines 212112 $4.0 57% $2.8 51% 

II – Industrial 

Wastewater 

Treatment 

322110,322121, 

322122,322130, 

311611,311411, 

311421,325193, 

and 324110 $1.5 21 $1.5 26

Subpart TT –

Industrial Waste 

Landfills

322110,322121, 

322122,322130, 

311611,311411, 

and 311421 $1.1 16% $0.8 15%

Private Sector, 

Total $6.7 96% $5.2 95% 

Public Sector, 

Total $0.3 4% $0.3 5% 

Total $7.0 100% $5.5 100% 

C. What are the economic impacts of the rule?

1. Summary of Economic Impacts 

EPA prepared an economic analysis to evaluate the 

impacts of this rule on affected industries. To estimate 

the economic impacts, EPA first conducted a screening 

assessment, comparing the estimated total annualized 

compliance costs by industry, where industry is defined in 

terms of North American Industry Classification System 

Formatted: Left

Deleted: Fugitive Methane 

Emissions from 

Deleted: Subpart HH – 

Industrial Waste Landfills

Deleted: 322110,322121, 

322122,322130, 

311611,311411, and 311421

Deleted: $1.1

Deleted: 16%

Deleted: $0.8

Deleted: 15%

Deleted: II – Industrial 

Wastewater Treatment ... [1]
98

(NAICS) code, with industry average revenues. Average 

cost-to-sales ratios for establishments in affected NAICS 

codes are typically less than 1 percent. 

These low average cost-to-sales ratios indicate that 

the rule is unlikely to result in significant changes in 

firms’ production decisions or other behavioral changes, 

and thus unlikely to result in significant changes in 

prices or quantities in affected markets. Thus, EPA 

followed its Guidelines for Preparing Economic Analyses 

(EPA, 2002, p.124-125) and used the engineering cost 

estimates to measure the social cost of the rule, rather 

than modeling market responses and using the resulting 

measures of social cost. Table 4 of this preamble 

summarizes cost-to-sales ratios for affected industries. 

Table 4. Estimated Cost-To-Sales Ratios for Affected 

Entities (First Year, 2006$) 

2007 

NAICS NAICS Description Sub-part 

Average Cost 

Per Entity 

($/entity) 

All 

Enterprises 

331419 

Primary Smelting and Refining of 

Nonferrous Metal (except Copper and 

Aluminum) T $10,520 0.1% 

331492 

Secondary Smelting, Refining, and 

Alloying of Nonferrous Metal (except 

Copper and Aluminum) T $10,520 0.1% 

212112 Bituminous Coal Underground Mining FF $34,717 0.2% 

322110 Pulp Mills TT $5,583 <0.1% 

322121 Paper (except Newsprint) Mills TT $5,583 <0.1% 

322122 Newsprint Mills TT $5,583 <0.1% 

322130 Paperboard Mills TT $5,583 <0.1% 

311611 Animal (except Poultry) Slaughtering TT $5,583 <0.1% 

311411 

Frozen Fruit, Juice, and Vegetable 

Manufacturing TT $5,583 

<0.1% 

311421 Fruit and Vegetable Canning TT $5,583 <0.1% 

322110 Pulp Mills II $4,235 <0.1% 

Deleted: HH

Deleted: HH

Deleted: HH

Deleted: HH

Deleted: HH

Deleted: HH

Deleted: HH
99

322121 Paper (except Newsprint) Mills II $4,235 <0.1% 

322122 Newsprint Mills II $4,235 <0.1% 

322130 Paperboard Mills II $4,235 <0.1% 

311611 Animal (except Poultry) Slaughtering II $3,963 <0.1% 

311411 

Frozen Fruit, Juice, and Vegetable 

Manufacturing II $3,963 

<0.1% 

311421 Fruit and Vegetable Canning II $3,963 <0.1% 

325193 Ethyl Alcohol Manufacturing II $5,140 <0.1% 

324110 Petroleum Refineries II $3,963 <0.1% 

D. What are the impacts of the rule on small businesses?

1. Summary of Impacts on Small Businesses 

As required by the RFA and SBREFA, EPA assessed the 

potential impacts of the rule on small entities (small 

businesses, governments, and non-profit organizations). 

(See Section V.C of this preamble for definitions of small 

entities.) 

EPA conducted a screening assessment comparing 

compliance costs for affected industry sectors to industryspecific receipts data for establishments owned by small 

businesses. This ratio constitutes a “sales” test that 

computes the annualized compliance costs of this rule as a 

percentage of sales and determines whether the ratio 

exceeds some level (e.g., 1 percent or 3 percent). 

The cost-to-sales ratios were constructed at the 

establishment level (average reporting program costs per 

establishment/average establishment receipts) for several 

business size ranges. This allowed EPA to account for 
100

receipt differences between establishments owned by large 

and small businesses and differences in small business 

definitions across affected industries. The results of the 

screening assessment are shown in Table 5 of this preamble. 

As shown, the cost-to-sales ratios are typically less 

than 1 percent for establishments owned by small businesses 

that EPA considers most likely to be covered by the 

reporting program (e.g., establishments owned by businesses 

with 100 or more employees). 
101

Table 5. Estimated Cost-To-Sales Ratios by Industry and 

Enterprise Size (First Year,2006$)a

Owned by Enterprises with: 

2007 

NAICS 

NAICS 

Descripti

on 

Su

bpa

rt 

SBA 

Size 

Standar

d 

(effect

ive 

August 

22, 

2008) 

Avera

ge 

Cost 

Per 

Entit

y ($/ 

entit

y) 

All 

Ent

erpri

ses 

1 to 

20 

Employ

eesb

20 to 

99 

Employ

ees 

100 to 

499 

Employ

ees 

500 to 

749 

Employ

ees 

750 to 

999 

Employ

ees 

1,000 

to 

1,499 

Employ

ees 

3314

19

Primary 

Smeltin

g and 

Refinin

g of 

Nonferr

ous 

Metal 

(except 

Copper 

and 

Aluminu

m) T

750 

employe

es 

$10,

520

0.1

% 0.9% 0.2% 0.1% D D D

3314

92

Secondar

y 

Smeltin

g, 

Refinin

g, and 

Alloyin

g of 

Nonferr

ous 

Metal 

(except 

Copper 

and 

Aluminu

m) T

750 

employe

es 

$10,

520

0.1

% 0.7% 0.1% 0.2% D D D

2121

12

Bitumino

us Coal 

Undergr

ound 

Mining FF

500 

employe

es 

$34,

717

0.2

% 3.0% 3.4% 0.2% D D D

3221

10

Pulp 

Mills TT

750 

employe

es 

$5,5

83

<0.

1% 0.4% D D D D D

3221

21

Paper 

(except 

Newspri

nt) 

Mills TT

750 

employe

es 

$5,5

83

<0.

1% D 0.1% D D D D

3221

22

Newsprin

t Mills TT

750 

employe

es 

$5,5

83

<0.

1% D D D NA D D

3221

30

Paperboa

rd 

Mills TT

750 

employe

es 

$5,5

83

<0.

1% 1.1% 0.1% <0.1% NA D D

Deleted: 7

Deleted: HH

Deleted: HH

Deleted: HH

Deleted: HH
102

Owned by Enterprises with: 

2007 

NAICS 

NAICS 

Descripti

on 

Su

bpa

rt 

SBA 

Size 

Standar

d 

(effect

ive 

August 

22, 

2008) 

Avera

ge 

Cost 

Per 

Entit

y ($/ 

entit

y) 

All 

Ent

erpri

ses 

1 to 

20 

Employ

eesb

20 to 

99 

Employ

ees 

100 to 

499 

Employ

ees 

500 to 

749 

Employ

ees 

750 to 

999 

Employ

ees 

1,000 

to 

1,499 

Employ

ees 

3116

11

Animal 

(except 

Poultry

) 

Slaught

ering TT

500 

employe

es 

$5,5

83

<0.

1% 0.5% 0.1% <0.1% D D <0.1%

3114

11

Frozen 

Fruit, 

Juice, 

and 

Vegetab

le 

Manufac

turing TT

500 

employe

es 

$5,5

83

<0.

1% 0.3% 0.1% <0.1% <0.1% D <0.1%

3114

21

Fruit 

and 

Vegetab

le 

Canning TT

500 

employe

es 

$5,5

83

<0.

1% 0.4% 0.1% <0.1% <0.1% <0.1% <0.1%

3221

10

Pulp 

Mills II

750 

employe

es 

$4,2

35

<0.

1% 0.3% D D D D D

3221

21

Paper 

(except 

Newspri

nt) 

Mills II

750 

employe

es 

$4,2

35

<0.

1% D <0.1% D D D D

3221

22

Newsprin

t Mills II

750 

employe

es 

$4,2

35

<0.

1% D D D NA D D

3221

30

Paperboa

rd 

Mills II

750 

employe

es 

$4,2

35

<0.

1% 0.8% <0.1% <0.1% NA D D

3116

11

Animal 

(except 

Poultry

) 

Slaught

ering II

500 

employe

es 

$3,9

63

<0.

1% 0.4% <0.1% <0.1% D D <0.1%

3114

11

Frozen 

Fruit, 

Juice, 

and 

Vegetab

le 

Manufac

turing II

500 

employe

es 

$3,9

63

<0.

1% 0.2% <0.1% <0.1% <0.1% D <0.1%

Deleted: HH

Deleted: HH

Deleted: HH
103

Owned by Enterprises with: 

2007 

NAICS 

NAICS 

Descripti

on 

Su

bpa

rt 

SBA 

Size 

Standar

d 

(effect

ive 

August 

22, 

2008) 

Avera

ge 

Cost 

Per 

Entit

y ($/ 

entit

y) 

All 

Ent

erpri

ses 

1 to 

20 

Employ

eesb

20 to 

99 

Employ

ees 

100 to 

499 

Employ

ees 

500 to 

749 

Employ

ees 

750 to 

999 

Employ

ees 

1,000 

to 

1,499 

Employ

ees 

3114

21

Fruit 

and 

Vegetab

le 

Canning II

500 

employe

es 

$3,9

63

<0.

1% 0.3% <0.1% <0.1% <0.1% <0.1% <0.1%

3251

93

Ethyl 

Alcohol 

Manufac

turing II

1000 

employe

es 

$5,1

40

<0.

1% D D D D NA D

3241

10

Petroleu

m 

Refiner

ies II

1500 

employe

esx

$3,9

63

<0.

1% 0.1% <0.1% <0.1% <0.1% D D

3314

19

Primary 

Smeltin

g and 

Refinin

g of 

Nonferr

ous 

Metal 

(except 

Copper 

and 

Aluminu

m) T

750 

employe

es 

$10,

520

0.1

% 0.9% 0.2% 0.1% D D D

Note: D denotes that receipt data was not disclosed. NA denotes that the enterprise 

category is not applicable (i.e., no enterprises were reported within this category). 

Receipt data in Table 5-7 has been adjusted to 2006$ using the latest GDP implicit price 

deflator reported by the U.S. Bureau of Economic Analysis (103.257/92.118=1.121) 

http://www.bea.gov/national/nipaweb/Index.asp (accessed December 21, 2009). 

a

 The Census Bureau defines an enterprise as a business organization consisting of one or 

more domestic establishments that were specified under common ownership or control. The 

enterprise and the establishment are the same for single-establishment firms. Each 

multi-establishment company forms one enterprise—the enterprise employment and annual 

payroll are summed from the associated establishments. Enterprise size designations are 

determined by the summed employment of all associated establishments. 

Since the SBA’s business size definitions (http://www.sba.gov/size) apply to an 

establishment’s ultimate parent company, we assume in this analysis that the enterprise 

definition above is consistent with the concept of ultimate parent company that is 

typically used for Small Business Regulatory Enforcement Fairness Act (SBREFA) screening 

analyses. 

b

 Excludes Statistics of U.S. Businesses (SUSB) employment category for zero employees. 

These entities only operated for a fraction of the year. 

c

 NAICS code 324110 – in addition, the petroleum refiner must not have more than 125,000 

barrels per calendar day total Operable Atmospheric Crude Oil Distillation capacity. 

Capacity includes owned or leased facilities as well as facilities under a processing 

agreement or an arrangement such as an exchange agreement or a throughput. The total 

product to be delivered under the contract must be at least 90 percent refined by the 

successful bidder from either crude oil or bona fide feedstocks. 
104

E. What are the benefits of the rule for society?

EPA examined the potential benefits of 40 CFR part 98. 

EPA’s previous analysis of 40 CFR part 98 discussed the 

benefits of a reporting system with respect to policy 

making relevance, transparency issues, and market 

efficiency. Instead of a quantitative analysis of the 

benefits, EPA conducted a systematic literature review of 

existing studies including government, consulting, and 

scholarly reports. 

A mandatory reporting system will benefit the public 

by increased transparency of facility emissions data. 

Transparent, public data on emissions allows for 

accountability of polluters to the public stakeholders who 

bear the cost of the pollution. Citizens, community 

groups, and labor unions have made use of data from 

Pollutant Release and Transfer Registers to negotiate 

directly with polluters to lower emissions, circumventing 

greater government regulation. Publicly available 

emissions data also will allow individuals to alter their 

consumption habits based on the GHG emissions of producers. 

The greatest benefit of mandatory reporting of 

industry GHG emissions to government will be realized in 

developing future GHG policies. For example, in the EU’s 

Emissions Trading System, a lack of accurate monitoring at 

Deleted: the GHG Reporting 

Rule GGRR

Deleted: the GHG reporting 

rule GGRR
105

the facility level before establishing CO2 allowance permits 

resulted in allocation of permits for emissions levels an 

average of 15 percent above actual levels in every country 

except the United Kingdom. 

Benefits to industry of GHG emissions monitoring 

include the value of having independent, verifiable data to 

present to the public to demonstrate appropriate 

environmental stewardship, and a better understanding of 

their emission levels and sources to identify opportunities 

to reduce emissions. Such monitoring allows for inclusion 

of standardized GHG data into environmental management 

systems, providing the necessary information to achieve and 

disseminate their environmental achievements. 

Standardization will also be a benefit to industry, 

once facilities invest in the institutional knowledge and 

systems to report emissions, the cost of monitoring should 

fall and the accuracy of the accounting should improve. A 

standardized reporting program will also allow for 

facilities to benchmark themselves against similar 

facilities to understand better their relative standing 

within their industry. 

V. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory Planning and Review
106

This action is not a "significant regulatory action" 

under the terms of Executive Order (EO) 12866 (58 FR 51735, 

October 4, 1993) and is therefore not subject to review 

under EO 12866. EPA’s cost analysis, presented in Section 

4 of the EIA, estimates the total annualized cost of the 

rule will be approximately $7.0 million (in 2006$) during 

the first year of the program and $5.5 million in 

subsequent years (including $0.3 million of programmatic 

costs to the Agency). In addition, EPA prepared an 

analysis of the potential costs associated with this 

action. This analysis is contained in the EIA, “Economic 

Impact Analysis for the Mandatory Reporting of Greenhouse 

Gas Emissions: Subparts: T, FF, II, and TT” (EPA-HQ-OAR2008-0508). A copy of the analysis is available in the 

docket for this action 

B. Paperwork Reduction Act

The information collection requirements in this rule 

have been submitted for approval to the Office of 

Management and Budget (OMB) under the Paperwork Reduction 

Act, 44 U.S.C. 3501 et seq. The information collection 

requirements are not enforceable until OMB approves them. 

EPA plans to collect complete and accurate economywide data on facility-level GHG emissions. Accurate and 

timely information on GHG emissions is essential for 

Deleted: the 

Deleted: xecutive 

Deleted: rder

Deleted: Economic Impact 

Analysis (

Deleted: )

Deleted: Economic Impact 

Analysis (

Deleted: )

Deleted: HHa,and
107

informing future climate change policy decisions. Through 

data collected under this rule, EPA will gain a better 

understanding of the relative emissions of specific 

industries, and the distribution of emissions from 

individual facilities within those industries. The 

facility-specific data will also improve our understanding 

of the factors that influence GHG emission rates and 

actions that facilities are already taking to reduce 

emissions. Additionally, EPA will be able to track the 

trend of emissions from industries and facilities within 

industries over time, particularly in response to policies 

and potential regulations. The data collected by this rule 

will improve EPA’s ability to formulate climate change 

policy options and to assess which industries would be 

affected, and how these industries would be affected by the 

options. 

This information collection is mandatory and will be 

carried out under CAA section 114. Information identified 

and marked as CBI will not be disclosed except in 

accordance with procedures set forth in 40 CFR part 2. 

However, emissions data collected under CAA section 114 

cannot generally be claimed as CBI and will be made public. 

For these final subparts, the projected cost and hour 

burden for non-Federal respondents is $5.13 million and 
108

66.0 million hours per year. The estimated average burden 

per response is 29.1 hours; the frequency of response is 

annual for all respondents that must comply with the rule’s 

reporting requirements and the estimated average number of 

likely respondents per year is 683. The cost burden to 

respondents resulting from the collection of information 

includes the total capital cost annualized over the 

equipment’s expected useful life (averaging $0.5 million), 

a total operation and maintenance component (averaging $1.6 

million per year), and a labor cost component (averaging 

$3.6 million per year). 

Burden is defined at 5 CFR 1320.3(b). These cost 

numbers differ from those shown elsewhere in the EIA for 

these subparts because the information collection request 

(ICR) costs represent the average cost over the first three 

years of the rule, but costs are reported elsewhere in the 

EIA for the subparts for the first year of the rule and for 

subsequent years of the rule. In addition, the ICR focuses 

on respondent burden, while the RIA for the final rule 

includes EPA Agency costs. 

An agency may not conduct or sponsor, and a person is 

not required to respond to, a collection of information 

unless it displays a currently valid OMB control number. 

The OMB control numbers for EPA’s regulations in 40 CFR are 

Deleted: Economic Impact 

Analysis (

Deleted: )
109

listed in 40 CFR part 9. When this ICR is approved by OMB, 

the Agency will publish a technical amendment to 40 CFR 

part 9 in the Federal Register to display the OMB control 

number for the approved information collection requirements 

contained in this final rule. 

C. Regulatory Flexibility Act (RFA)

The RFA generally requires an agency to prepare a 

regulatory flexibility analysis of any rule subject to 

notice and comment rulemaking requirements under the 

Administrative Procedure Act or any other statute unless 

the agency certifies that the rule will not have a 

significant economic impact on a substantial number of 

small entities. Small entities include small businesses, 

small organizations, and small governmental jurisdictions. 

For purposes of assessing the impacts of today’s rule 

on small entities, a small entity is defined as a small 

business as defined by the Small Business Administration’s 

regulations at 13 CFR 121.201; according to these size 

standards, criteria for determining if ultimate parent 

companies owning affected facilities are categorized as 

small vary by NAICS. Small entity criteria range from 

total number of employees at the firm fewer than 500 to 

number of employees fewer than 1,500; one affected NAICS, 

324110, the petroleum refiner must have no more than 1,500 
110

employees nor more than 125,000 barrels per calendar day 

total Operable Atmospheric Crude Oil Distillation capacity. 

Capacity includes owned or leased facilities as well as 

facilities under a processing agreement or an arrangement 

such as an exchange agreement or a throughput. The total 

product to be delivered under the contract must be at least 

90 percent refined by the successful bidder from either 

crude oil or bona fide feedstocks. EIA tables 5-10 and 5-

11 present small business criteria and enterprise size 

distribution data for affected NAICS. 

EPA assessed the potential impacts of the final rule 

on small entities using a sales test, defined as the ratio 

of total annualized compliance costs to firm sales. 

Details are provided in Section 5.3 of the EIA. These 

sales tests examine the average establishment’s total 

annualized mandatory reporting costs to the average 

establishment receipts for enterprises within several 

employment categories. The average entity costs used to 

compute the sales test are the same across all of these 

enterprise size categories. As a result, the sales-test 

will overstate the cost-to-receipt ratio for establishments 

owned by small businesses, because the reporting costs are 

likely lower than average entity estimates provided by the 

engineering cost analysis 

Deleted: s
111

The results of the screening analysis show that for 

most NAICS, the costs are estimated to be less than 1

percent of sales in all firm size categories. For one 

NAICS (322130 Paperboard Mills), the costs exceed 1 percent

of sales for the 1-20 employee size category; for another 

NAICS (212112 Bituminous Coal Underground Mining), the 

costs exceed 1 percent of sales for the 1-20 and 20-100 

employee size category. Previous “Regulatory Impact 

Analysis for the Mandatory Reporting of Greenhouse Gas 

Emissions” (EPA-HQ-OAR-2008-0508) illustrated that pulp and 

paper industry enterprises with less than 20 employees were 

unlikely to be covered by the rule. For mining facilities, 

EPA’s initial review of facility data suggests that mines 

owned by enterprises with less than 100 employees would 

also unlikely to be covered by the rule. 

After considering the economic impacts of today’s 

final rule on small entities, I therefore certify that this 

final rule will not have a significant economic impact on a 

substantial number of small entities. 

Although this rule would not have a significant 

economic impact on a substantial number of small entities, 

the Agency nonetheless tried to reduce the impact of this 

rule on small entities, including seeking input from a wide 

range of private- and public-sector stakeholders. When 

Deleted: %

Deleted: %

Deleted: %
112

developing the rule, the Agency took special steps to 

ensure that the burdens imposed on small entities were 

minimal. The Agency conducted several meetings with 

industry trade associations to discuss regulatory options 

and the corresponding burden on industry, such as 

recordkeeping and reporting. The Agency investigated 

alternative thresholds and analyzed the marginal costs 

associated with requiring smaller entities with lower 

emissions to report. The Agency also selected a hybrid 

method for reporting, which provides flexibility to 

entities and helps minimize reporting costs. 

D. Unfunded Mandates Reform Act (UMRA)

Title II of the Unfunded Mandates Reform Act of 1995 

(UMRA), P.L. 104-4, establishes requirements for Federal 

agencies to assess the effects of their regulatory actions 

on state, local, and tribal governments and the private 

sector. Under Section 202 of the UMRA, EPA generally must 

prepare a written statement, including a cost-benefit 

analysis, for final rules with “federal mandates” that may 

result in expenditures to state, local, and tribal 

governments, in the aggregate, or to the private sector, of 

$100 million or more in any one year. 

This final rule does not contain a Federal mandate 

that may result in expenditures of $100 million or more for 

Deleted: f
113

State, local, and tribal governments, in the aggregate, or 

the private sector in any one year. Overall, EPA estimates 

that the total annualized costs of this final rule are 

approximately $6.7 million in the first year, and $5.3

million per year in subsequent years. Thus, this final 

rule is not subject to the requirements of UMRA sections 

202 or 205. 

This final rule is also not subject to the 

requirements of UMRA section 203 because it contains no 

regulatory requirements that might significantly or 

uniquely affect small governments. None of the facilities 

currently known to undertake these activities are owned by 

small governments. 

E. Executive Order 13132: Federalism

These final subparts do not have federalism 

implications. They will not have substantial direct 

effects on the States, on the relationship between the 

national government and the States, or on the distribution 

of power and responsibilities among the various levels of 

government, as specified in EO 13132. 

Entities affected by these final subparts are 

facilities that directly emit GHGs. These final subparts 

do not apply to governmental entities unless the government 

entity owns a facility that directly emits GHGs above 

Deleted: 7

Deleted: 0

Deleted: 5

Deleted: of UMRA

Deleted: of UMRA 

Deleted: xecutive 

Deleted: rder 

Deleted: greenhouses gases

Deleted: greenhouse 

Deleted: gase
114

threshold levels such as a landfill or large stationary 

combustion source, so relatively few government facilities 

would be affected. This regulation also does not limit the 

power of States or localities to collect GHG data and/or 

regulate GHG emissions. Thus, EO 13132 does not apply to 

this rule. 

In the spirit of EO 13132, and consistent with EPA 

policy to promote communications between EPA and State and 

local governments, EPA specifically solicited comments on 

these subparts from State and local officials. For a 

discussion of outreach activities to State, local, or 

Tribal organizations, see Section IX of the preamble to the 

proposed rule (74 FR 16602). 

F. Executive Order 13175: Consultation and Coordination 

with Indian Tribal Governments

This action does not have Tribal implications, as 

specified in EO 13175 (65 FR 67249, November 9, 2000). 

This regulation applies directly to facilities that 

directly emit GHGs. Facilities expected to be affected by 

these final subparts are not expected to be owned by Tribal 

governments. Thus, EO 13175 does not apply to this action. 

Although EO 13175 does not apply to these final 

subparts, EPA sought opportunities to provide information 

to Tribal governments and representatives during 

Deleted: xecutive 

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Deleted: GGRRMandatory GHG 

Rreporting Rrule

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Deleted: rder

Deleted: greenhouse gases

Deleted: xecutive 

Deleted: rder
115

development of the proposed rule, which included these 

subparts being finalized today. See Section IX of the 

preamble to the proposed rule (74 FR 16602). 

G. Executive Order 13045: Protection of Children from 

Environmental Health Risks and Safety Risks

EPA interprets EO 13045 (62 FR 19885, April 23, 1997) 

as applying only to those regulatory actions that concern 

health or safety risks, such that the analysis required 

under section 5-501 of the EO has the potential to 

influence the regulation. This action is not subject to EO 

13045 because it does not establish an environmental 

standard intended to mitigate health or safety risks. 

H. Executive Order 13211: Actions that Significantly 

Affect Energy Supply, Distribution, or Use

This action is not a “significant energy action” as 

defined in EO 13211 (66 FR 28355 (May 22, 2001)), because 

it is not likely to have a significant adverse effect on 

the supply, distribution, or use of energy. Further, we 

have concluded that this rule is not likely to have any 

adverse energy effects. This rule relates to monitoring, 

reporting and recordkeeping at facilities that directly 

emit GHGs and does not impact energy supply, distribution 

or use. Therefore, we conclude that this rule is not 

Deleted: GGRRMandatory GHG 

Rreporting Rrule

Deleted: GGRRMandatory GHG 

Rreporting Rrule

Deleted: xecutive 

Deleted: rder

Deleted: greenhouses gases 
116

likely to have any adverse effects on energy supply, 

distribution, or use. 

I. National Technology Transfer and Advancement Act

Section 12(d) of the National Technology Transfer and 

Section 12(d) of the National Technology Transfer and 

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

12(d) (15 U.S.C. 272 note) directs EPA to use voluntary 

consensus standards in its regulatory activities unless to 

do so would be inconsistent with applicable law or 

otherwise impractical. Voluntary consensus standards are 

technical standards (e.g., materials specifications, test 

methods, sampling procedures, and business practices) that 

are developed or adopted by voluntary consensus standards 

bodies. NTTAA directs EPA to provide Congress, through 

OMB, explanations when the Agency decides not to use 

available and applicable voluntary consensus standards. 

This rulemaking involves technical standards. For 

these final subparts, EPA has decided to use more than a 

dozen voluntary consensus standards from four different 

voluntary consensus standards bodies, including American 

Society for Testing and Materials (ASTM) and American 

Society for Mechanical Engineers (ASME). 

These voluntary consensus standards will help 

facilities monitor, report, and keep records of GHG 
117

emissions. No new test methods were developed for this 

rule. Instead, from existing rules for source categories 

and voluntary GHG programs, EPA identified existing means 

of monitoring, reporting, and keeping records of GHG 

emissions. The existing methods (voluntary consensus 

standards) include a broad range of measurement techniques, 

including methods to measure gas or liquid flow and methods 

to analyze gases by gas chromatography. All except three

of these methods have already been incorporated by 

reference in the October 2009 Final Rule. Thus, we are 

adding entries to 40 CFR 98.7 for new voluntary consensus 

standards and modifying the entries for other voluntary 

consensus standards to reflect their usage in these final 

subparts. Thus, the test methods are incorporated by 

reference into the final rule and are available as 

specified in 40 CFR 98.7. 

By incorporating voluntary consensus standards into 

the subparts, EPA is both meeting the requirements of the 

NTTAA and presenting multiple options and flexibility for 

measuring GHG emissions. 

J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and LowIncome Populations

Deleted: wo

Deleted: final GGRRMandatory 

GHG Rreporting Rrule

Deleted: GGRRMandatory GHG 

Rreporting Rrule
118

EO 12898 (59 FR 7629 (Feb. 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 these final subparts will not 

have disproportionately high and adverse human health or 

environmental effects on minority or low-income populations 

because it does not affect the level of protection provided 

to human health or the environment. These final subparts 

do not affect the level of protection provided to human 

health or the environment because they address information 

collection and reporting procedures. 

K. Congressional Review Act 

The Congressional Review Act, 5 U.S.C. 801 et seq., as 

added by the Small Business Regulatory Enforcement Fairness 

Act of 1996 (SBREFA), generally provides that before a rule 

may take effect, the agency promulgating the rule must 

submit a rule report, which includes a copy of the rule, to 

each House of the Congress and to the Comptroller General 

Deleted: xecutive 

Deleted: rder

Deleted: (EO) 

Deleted: f

Deleted: f
119

of the United States. EPA will submit a report containing 

this rule and other required information to the U.S. 

Senate, the U.S. House of Representatives, and the 

Comptroller General of the U.S. prior to publication of the 

rule in the Federal Register. A major rule cannot take 

effect until 60 days after it is published in the Federal 

Register. This action is not a “major rule” as defined by 

5 U.S.C. 804(2). This rule will be effective [INSERT THE 

DATE 60 DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER].
Mandatory Reporting of GHGs from Magnesium Production, 

Underground Coal Mines, Industrial Wastewater Treatment, 

and Industrial Waste Landfills – Final Rule 

Page 120 of 220 

List of Subjects 40 CFR Part 98

Environmental protection, Administrative practice and 

procedure, Greenhouse gases, Incorporation by reference, 

Suppliers, Reporting and recordkeeping requirements. 

Dated: 

 

Lisa P. Jackson, 

Administrator. 

Deleted: 2
121 

For the reasons stated in the preamble, title 40, 

chapter I, of the Code of Federal Regulations is 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. 

Subpart A—[Amended] 

2. Section 98.1 is amended by revising paragraph (b) 

to read as follows:

§98.1 Purpose and Scope.

* * * * *

(b) Owners and operators of facilities and suppliers 

that are subject to this part must follow the requirements 

of this subpart and all applicable subparts of this part. 

If a conflict exists between a provision in subpart A and 

any other applicable subpart, the requirements of the 

applicable subpart shall take precedence.

3. Section 98.2 is amended by revising paragraphs 

(a)(1), (a)(2), and (a)(4); and revising the third sentence 

of paragraph (i)(3) to read as follows:

§98.2 Who must report?

* * * * *

Formatted: Font: Not Bold

Formatted: Font: Not Bold

Deleted: 2

Deleted: .

Deleted: §98.1 Purpose and 

Scope.¶
122

(1) A facility that contains any source category that 

is listed in Table A-3 of this subpart in any calendar year 

starting in 2010. For these facilities, the annual GHG

report must cover stationary fuel combustion sources 

(subpart C), miscellaneous use of carbonates (subpart U), 

and all applicable source categories listed in Table A-3 

and Table A-4 of this subpart.

(2) A facility that contains any source category that 

is listed in Table A-4 of this subpart that emits 25,000 

metric tons CO2e or more per year in combined emissions from 

stationary fuel combustion units, miscellaneous uses of 

carbonate, and all applicable source categories that are 

listed in Table A-3 and Table A-4 of this subpart. For 

these facilities, the annual GHG report must cover 

stationary fuel combustion sources (subpart C), 

miscellaneous use of carbonates (subpart U), and all

applicable source categories listed in Table A-3 and Table 

A-4 of this subpart.

* * * * *

(4) A supplier that is listed in Table A-5 of this 

subpart. For these suppliers, the annual GHG report must 

cover all applicable products for which calculation 

methodologies are provided in the subparts listed in Table 

A-5 of this subpart. 
123

* * * * * 

(i) * * * 

(3) * * * This paragraph (i)(3) does not apply 

to facilities with municipal solid waste landfills or 

industrial waste landfills, or to underground coal mines. *

 * * 

4. Section 98.3 is amended by:

a. Revising paragraph (b) introductory text.

b. Removing and reserving paragraph (b)(1).

c. Revising paragraphs (b)(2), (c)(4)(i), (c)(4)(ii), 

(c)(4)(iii) introductory text, (c)(7), and (i)(1) to read 

as follows. 

§98.3 What are the general monitoring, reporting, 

recordkeeping and verification requirements of this part?

* * * * * 

(b) Schedule. The annual GHG report must be 

submitted no later than March 31 of each calendar year for 

GHG emissions in the previous calendar year. As an 

example, for a facility that is subject to the rule in 

calendar year 2010, the first report must be submitted on 

March 31, 2011.

(1) [Reserved] 

(2) For a new facility or supplier that begins

operation on or after January 1, 2010 and becomes subject 

Formatted: _Paragraph-Format-GHG

Preamble

Deleted: 3

Deleted: revising paragraph 

Deleted: 
124

to the rule in the year that it becomes operational, report 

emissions beginning with the first operating month and 

ending on December 31 of that year. Each subsequent annual 

report must cover emissions for the calendar year, 

beginning on January 1 and ending on December 31.

* * * * *

(c) * * *

(4) * * *

(i) Annual emissions (excluding biogenic CO2) 

aggregated for all GHG from all applicable source 

categories listed in Tables A-3 and Table A-4 of this 

subpart and expressed in metric tons of CO2e calculated 

using Equation A-1 of this subpart.

(ii) Annual emissions of biogenic CO2 aggregated for

all applicable source categories in listed in Tables A-3 

and Table A-4 of this subpart.

(iii) Annual emissions from each applicable source 

category listed in Tables A-3 and Table A-4 of this 

subpart, expressed in metric tons of each GHG listed in 

paragraphs (c)(4)(iii)(A) through (c)(4)(iii)(E) of this 

section. 

* * * * *
125

(7) A brief description of each “best available 

monitoring method” used according to paragraph (d) of this 

section, the parameter measured using the method, and the 

time period during which the “best available monitoring 

method” was used, if applicable. 

* * * * *

(i) * * *

(1) Except as provided in paragraphs (i)(4) through 

(i)(6) of this section, flow meters and other devices 

(e.g., belt scales) that measure data used to calculate GHG 

emissions shall be calibrated using the procedures 

specified in this paragraph and each relevant subpart of 

this part. All measurement devices must be calibrated 

according to the manufacturer’s recommended procedures, an 

appropriate industry consensus standard, or a method 

specified in a relevant subpart of this part. All 

measurement devices shall be calibrated to an accuracy of 5 

percent. For facilities and suppliers that are subject to 

this part on January 1, 2010, the initial calibration shall 

be conducted by April 1, 2010. For facilities and 

suppliers that become subject to this part after April 1,

2010, the initial calibration shall be conducted by the 

date that data collection is required to begin. Subsequent 

Deleted: (c) * * *¶
126

calibrations shall be performed at the frequency specified 

in each applicable subpart. 

* * * * *

5. Section 98.6 is amended by amending the definition 

of “anaerobic lagoon” and adding definitions for “Cement 

kiln dust,” “Degasification system,” “Destruction device,” 

“Furnace slag,” “Liberated,” “Municipal wastewater

treatment plant,” “Ventilation well or shaft,” “Ventilation 

system,” and “Working capacity.” 

§98.6 Definitions.

* * * * *

Anaerobic lagoon, with respect to subpart JJ of this 

part, means a type of liquid storage system component that 

is designed and operated to stabilize wastes using 

anaerobic microbial processes. Anaerobic lagoons may be 

designed for combined stabilization and storage wih varying 

lengths of retention time (up to a year or greater), 

depending on the climate region, volatile solids loading 

rate, and other operational factors.

* * * * *

Cement kiln dust means non-calcined to fully calcined 

dust produced in the kiln or pyroprocessing line. Cement 

kiln dust is a fine-grained, solid, highly alkaline 

material removed from the cement kiln exhaust gas by 

Formatted: GHG PARAGRAPH

Formatted: Underline

Deleted: 4

Deleted: “Anaerobic process,” 

“Anaerobic reactor,” 

“Anaerobic sludge digester,” 

“Anaerobic wastewater 

treatment process,” 

Deleted: “Dedicated 

construction and demolition 

waste landfill,” 

Deleted: “Ethanol production 

facility,” “Food processing 

facility,” 

Deleted: “Industrial waste 

landfill,” “Industrial 

wastewater,” “Industrial 

wastewater treatment 

sludge,” 

Deleted: “Wastewater 

treatment system,” 

Deleted: Anaerobic process

means the 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.¶

Anaerobic reactor means an 

enclosed vessel used for an 

anaerobic wastewater 

treatment process.¶

Anaerobic sludge digester

means an enclosed vessel in 

which wastewater treatment 

sludges are degraded by 

microorganisms in the 

absence of oxygen, resulting 

in the generation of CO2 and 

CH4.¶

Anaerobic wastewater 

treatment process means a 

process in which organic 

matter in wastewater is 

degraded by micro-organisms 

in the absence of oxygen, 

resulting in the generation 

of CO2 and CH4. Anaerobic 

wastewater treatment 

processes include reactors 

and lagoons.¶

* * * * *¶
127

scrubbers (filtration baghouses and/or electrostatic 

precipitators). 

* * * * * 

Degasification system means the entirety of the 

equipment that is used to drain gas from underground and 

collect it at a common point, such as a vacuum pumping 

station. This includes all degasification wells and gob 

gas vent holes at the underground coal mine. 

Degasification systems include surface pre-mining, 

horizontal pre-mining, and post-mining systems. 

* * * * * 

Destruction device, for the purposes of subparts II 

and TT of this part, means a flare, thermal oxidizer, 

boiler, turbine, internal combustion engine, or any other 

combustion unit used to destroy or oxidize methane 

contained in landfill gas or wastewater biogas. 

* * * * * 

Furnace slag means a by-product formed in metal 

melting furnaces when slagging agents, reducing agents, 

and/or fluxes (e.g., coke ash, limestone, silicates) are 

added to remove impurities from the molten metal. 

* * * * * 

Liberated means released from coal and surrounding 

rock strata during the mining process. This includes both 

Formatted: No underline

Deleted: For the purposes of 

subpart TT, Ddedicated 

construction and demolition

waste landfill means a 

landfill that only receives 

materials generated from the 

construction or destruction 

of structures such as 

buildings, roads, and 

bridges. ¶

Deleted: For the purposes of 

subparts II and TT, Dd

Deleted: 

Deleted: Ethanol production 

facility means a facility 

that produces ethanol from 

the fermentation of sugar, 

starch, grain, or cellulosic 

biomass feedstocks, or 

produces ethanol 

synthetically from 

petrochemical feedstocks, 

such as ethylene or other 

chemicals.¶

* * * * *¶

Food processing facility

means a facility that 

manufactures or processes 

meat, poultry, fruits, 

and/or vegtables. A meat or 

poultry processing or 

rendering facility is a 

facility covered under NAICS 

3116 (Meat Product 

Manufacturing). A fruit or 

vegetable processing 

facility is a facility 

covered under NAICS 3114 

(Fruit and Vegetable 

Preserving and Specialty 

Food Manufacturing). For 

information on NAICS, see 

http://www.census.gov/eos/ww

w/naics/.¶

* * * * *¶

Deleted: For the purposes of 

subpart TT, Iindustrial 

waste landfill means any 

landfill other than a 

municipal solid waste 

landfill, a RCRA Subtitle C 

hazardous waste landfill, or

a TSCA hazardous waste 

landfill, in which 

industrial solid waste, such 

as RCRA Subtitle D wastes 

(non-hazardous industrial 

solid waste, defined in 40 

CFR 257.2), commercial solid 

wastes, or conditionally 

exempt small quantity 

generator wastes, is placed. 

An industrial waste landfill 

includes all disposal areas 

at the facility. ¶

Industrial wastewater means ... [2]
128

methane emitted from the ventilation system and methane 

drained from degasification systems. 

* * * * * 

Municipal wastewater treatment plant means a series of 

treatment processes used to remove contaminants and 

pollutants from domestic, business, and industrial 

wastewater collected in city sewers and transported to a 

centralized wastewater treatment system such as a publicly 

owned treatment works (POTW). 

* * * * * 

Ventilation well or shaft means a well or shaft 

employed at an underground coal mine to serve as the outlet 

or conduit to move air from the ventilation system out of 

the mine. 

Ventilation system means a system that is used to 

control the concentration of methane and other gases within 

mine working areas through mine ventilation, rather than a 

mine degasification system. A ventilation system consists 

of fans that move air through the mine workings to dilute 

methane concentrations. This includes all ventilation 

shafts and wells at the underground coal mine. 

* * * * * 

Working capacity, for the purposes of subpart TT of 

this part, means the maximum volume or mass of waste that 

Formatted: No underline

Deleted: powerful 

Deleted: large volumes of 

Deleted: * * * * *¶

Wastewater treatment system

means the collection of all 

processes that treat or 

remove pollutants and 

contaminants, such as 

soluble organic matter, 

suspended solids, pathogenic 

organisms, and chemicals 

from wastewater prior to its 

reuse or discharge from the 

facility.¶

Deleted: For the purposes of 

subpart TT, Ww
129

is actually placed in the landfill from an individual or 

representative type of container (such as a tank, truck, or 

roll-off bin) used to convey wastes to the landfill, taking 

into account that the container may not be able to be 100 

percent filled and/or 100 percent emptied for each load. 

* * * * * 

6. Section 98.7 is amended by: 

a. Revising paragraphs (d)(1) through (d)(5), and 

(d)(7) through (d)(10).

b. Revising paragraphs (e)(10), (e)(11), (e)(25), and 

(e)(42).

c. Revising paragraph (f)(2).

d. Adding paragraphs (e)(43) and (e)(44).

e. Adding paragraphs (k) through (m). 

§98.7 What standardized methods are incorporated by 

reference into this part?

* * * * * 

(d) * * * 

(1) ASME MFC-3M–2004 Measurement of Fluid Flow in 

Pipes Using Orifice, Nozzle, and Venturi, incorporation by 

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

§98.254(c), §98.324(e), §98.344(c), §98.354(d), §98.354(h), 

and §98.364(e). 

Formatted: Italian (Italy)

Deleted: 5

Deleted: 10

Deleted: ;

Deleted: ,

Deleted: ;

Deleted: and 

Deleted: ;

Deleted: .

Deleted: b

Deleted: through 

Deleted: 5

Deleted: ; and

Deleted: n
130

(2) ASME MFC-4M–1986 (Reaffirmed 1997) Measurement of 

Gas Flow by Turbine Meters, IBR approved for §98.34(b), 

§98.244(b), §98.254(c), §98.324(e), §98.344(c), §98.354(h), 

and §98.364(e). 

(3) ASME MFC-5M–1985 (Reaffirmed 1994) Measurement of 

Liquid Flow in Closed Conduits Using Transit-Time 

Ultrasonic Flowmeters, IBR approved for §98.34(b) and 

§98.244(b), and §98.354(d). 

(4) ASME MFC-6M–1998 Measurement of Fluid Flow in 

Pipes Using Vortex Flowmeters, IBR approved for §98.34(b), 

§98.244(b), §98.254(c), §98.324(e), §98.344(c), §98.354(h), 

and §98.364(e). 

(5) ASME MFC-7M–1987 (Reaffirmed 1992) Measurement of 

Gas Flow by Means of Critical Flow Venturi Nozzles, IBR 

approved for §98.34(b), §98.244(b), §98.254(c), §98.324(e), 

§98.344(c), §98.354(h), and §98.364(e).

* * * * *

(7) ASME MFC-11M-2006 Measurement of Fluid Flow by 

Means of Coriolis Mass Flowmeters, IBR approved for 

§98.244(b), §98.254(c), §98.324(e), §98.344(c), and 

§98.354(h). 

(8) ASME MFC-14M-2003 Measurement of Fluid Flow Using 

Small Bore Precision Orifice Meters, IBR approved for 

Deleted: (6) ASME MFC-9M–

1988 (Reaffirmed 2001) 

Measurement of Liquid Flow 

in Closed Conduits by 

Weighing Method, IBR 

approved for §98.34(b) and 

§98.244(b).¶
131

§98.244(b), §98.254(c), §98.324(e), §98.344(c), §98.354(h), 

and §98.364(e). 

(9) ASME MFC-16-2007 Measurement of Liquid Flow in 

Closed Conduits with Electromagnetic Flowmeters, IBR 

approved for §98.244(b) and §98.354(d). 

(10) ASME MFC-18M-2001 Measurement of Fluid Flow 

Using Variable Area Meters, IBR approved for §98.244(b), 

§98.254(c), §98.324(e), §98.344(c), §98.354(h), and 

§98.364(e). 

* * * * * 

(e) * * * 

(10) ASTM D1945-03 Standard Test Method for Analysis 

of Natural Gas by Gas Chromatography, IBR approved for 

§98.34(b), §98.74(c), §98.164(b), §98.324(d), §98.244(b), 

§98.254(d), §98.344(b), and §98.354(g). 

(11) ASTM D1946-90 (Reapproved 2006) Standard 

Practice for Analysis of Reformed Gas by Gas 

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

§98.164(b), §98.254(d), §98.324(d), §98.344(b), §98.354(g), 

and §98.364(c). 

* * * * * 

(25) ASTM D4891-89 (Reapproved 2006), Standard Test 

Method for Heating Value of Gases in Natural Gas Range by 
132

Stoichiometric Combustion, IBR approved for §98.34(a), 

§98.254(e), and §98.324(d). 

* * * * * 

(42) ASTM UOP539-97 Refinery Gas Analysis by Gas 

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

§98.254(d), §98.324(d), §98.344(b), and §98.354(g). 

(43) ASTM D1941-91 (Reapproved 2007) Standard Test 

Method for Open Channel Flow Measurement of Water with the 

Parshall Flume, approved June 15, 2007, IBR approved for 

§98.354(d). 

(44) ASTM D5614-94 (Reapproved 2008) Standard Test 

Method for Open Channel Flow Measurement of Water with 

Broad-Crested Weirs, approved October 1, 2008, IBR approved 

for §98.354(d). 

(f) * * * 

(2) GPA 2261-00 Analysis for Natural Gas and Similar 

Gaseous Mixtures by Gas Chromatography, IBR approved for 

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

§98.354(g). 

* * * * * 

(k) The following material is available for purchase 

from Standard Methods, at http://www.standardmethods.org, 

(877) 574-1233; or, through a joint publication agreement 

from the American Public Health Association (APHA), PO Box 

Deleted: (43) ASTM D1252-06 

Standard Test Methods for 

Chemical Oxygen Demand 

(Dichromate Oxygen Demand) 

of Water, IBR approved for 

§98.354(b). ¶

Deleted: 4

Deleted: 5

Deleted: (k) The following 

material is available for 

purchase from American 

National Standards Institute 

(ANSI), 25 West 43rd Street, 

Fourth floor, New York, NY 

10036, (212) 642-4900, 

http://www.ansi.org.¶

(1) American National 

Standard on Photographic 

Processing Effluents, April 

2, 1975, IBR approved for 

§98.354(b).¶

(2) [Reserved]¶

(l) The following material 

is available for purchase 

from the Association of 

Official Analytical Chemists 

International, 481 North 

Frederick Avenue, Suite 500, 

Gaithersburg, MD 20877–2417, 

(800) 379-2622, 

http://www.aoac.org.¶

(1) Official Methods of 

Analysis of the Association 

of Official Analytical 

Chemists, Methods Manual, 

Sixteenth Edition, 4th 

Revision, 1998, IBR approved 

for §98.354(b).¶

(2) [Reserved]¶

(ml

Deleted: 800 I Street, NW, 

Washington, D.C. 20001, 
133

933019, Atlanta, GA 31193-3019, (888) 320-APHA (2742), 

http://www.apha.org/publications/pubscontact/.

(1) Method 2540G Total, Fixed, and Volatile Solids in 

Solid and Semisolid Samples, IBR approved for §98.464(b).

(2) [Reserved]

(l) The following material is available from the U.S. 

Department of Labor, Mine Safety and Health Administration, 

1100 Wilson Boulevard, 21st Floor, Arlington, VA 22209-

3939, (202) 693-9400, www.msha.gov. 

(1) General Coal Mine Inspection Procedures and 

Inspection Tracking System, Handbook Number: PH-08-V-1, 

January 1, 2008, IBR approved for §98.324(b). 

(2) [Reserved]

(m) The following material is available from the U.S. 

Environmental Proection Agency, 1200 Pennsylvania Avenue, 

NW, Washington, D.C. 20460, (202) 272-0167, www.epa.gov.

(1) NPDES Compliance Inspection Manual, Chapter 5, 

Sampling, EPA 305-X-04-001, July 2004, 

http://www.epa.gov/compliance/monitoring/programs/cwa/npdes

.html, IBR approved for §98.354(c).

(2) U.S. EPA NPDES Permit Writers’ Manual, Section 

7.1.3, Sample Collection Methods, EPA 833-B-96-003, 

December 1996, http://www.epa.gov/npdes/pubs/owm0243.pdf, 

IBR approved for §98.354(c). 

Deleted: , 

http://www.standardmethods.o

rg.

Deleted: (2) Method 5210B 

Biochemical Oxygen Demand 

(BOD) 5-Day BOD Test (20th 

Edition), IBR approved for 

§98.354(b).¶

(3) Method 5220C Chemical 

Oxygen Demand (COD) Closed 

Reflux, Titrimetric Method, 

IBR approved for §98.354(b).¶

(4) Method 5220D Chemical 

Oxygen Demand (COD) Closed 

Reflux, Colorimetric Method,

IBR approved for §98.354(b). 

Deleted: mn

Deleted: n

Deleted: c
134

7. Subpart A is amended by adding Tables A-3, A-4, 

and A-5 to read as follows:

Table A-3 of Subpart A—Source Category List for §98.2(a)(1)

Source Categoriesa Applicable in 2010 and Future Years

Electricity generation units that report CO2 mass emissions 

year round through 40 CFR part 75 (subpart D)

Adipic acid production (subpart E)

Aluminum production (subpart F)

Ammonia manufacturing (subpart G)

Cement production (subpart H)

HCFC-22 production (subpart O)

HFC-23 destruction processes that are not collocated with a 

HCFC-22 production facility and that destroy more than 2.14 

metric tons of HFC-23 per year (subpart O)

Lime manufacturing (subpart S)

Nitric acid production (subpart V)

Petrochemical production (subpart X)

Petroleum refineries (subpart Y)

Phosphoric acid production (subpart Z)

Silicon carbide production (subpart BB)

Soda ash production (subpart CC)

Titanium dioxide production (subpart EE)

Municipal solid waste landfills that generate CH4 in amounts 

equivalent to 25,000 metric tons CO2e or more per year, as 

determined according to subpart HH of this part

Manure management systems with combined CH4 and N2O emissions 

in amounts equivalent to 25,000 metric tons CO2e or more per 

year, as determined according to subpart JJ of this part.

Additional Source Categoriesa Applicable in 2011 and Future 

Years

Underground coal mines that are subject to quarterly or more 

frequent sampling by Mine Safety and Health Administration 

(MSHA) of ventilation systems (subpart FF)

a Source categories are defined in each applicable subpart.

Deleted: 6. Table A-3 of 

subpart A is amended by 

revising the entry for 

“(Reserved)” to read as 

follows: ¶

¶

Table A-3 of Subpart A—

Source Category List for 

§98.2(a)(1)¶

Source Categories1

Applicable in 2010 and 

Future Years

Deleted: 1

Deleted: 1

Deleted: 1

... [3]
135

Table A-4 of Subpart A—Source Category List for §98.2(a)(2)

Source Categoriesa Applicable in 2010 and Future Years

Ferroalloy production (subpart K)

Glass production (subpart N)

Hydrogen production (subpart P)

Iron and steel production (subpart Q)

Lead production (subpart R)

Pulp and paper manufacturing (subpart AA)

Zinc production (subpart GG)

Additional Source Categoriesa Applicable in 2011 and Future 

Years

Magnesium production (subpart T)

Industrial wastewater treatment (subpart II)

Industrial waste landfills (subpart TT)

a Source categories are defined in each applicable subpart.

Table A-5 of Subpart A—Supplier Category List for 

§98.2(a)(4)

Supplier Categoriesa Applicable in 2010 and Future Years

Coal-to–liquids suppliers (subpart LL): 

 (A) All producers of coal-to–liquid products

 (B) Importers of an annual quantity of coal-to-liquid 

products that is equivalent to 25,000 metric tons CO2e or 

more

 (C) Exporters of an annual quantity of coal-to-liquid 

products that is equivalent to 25,000 metric tons CO2e or 

more

Petroleum product suppliers (subpart MM):

 (A) All petroleum refineries that distill crude oil

 (B) Importers of an annual quantity of petroleum products 

that is equivalent to 25,000 metric tons CO2e or more

 (C) Exporters of an annual quantity of petroleum products 

that is equivalent to 25,000 metric tons CO2e or more

Natural gas and natural gas liquids suppliers (subpart NN):

 (A) All fractionators.

 (B) All local natural gas distribution companies

Deleted: 1

Deleted: 1

Deleted: 1

Deleted: 1
136

Supplier Categoriesa Applicable in 2010 and Future Years

Industrial greenhouse gas suppliers (subpart OO):

 (A) All producers of industrial greenhouse gases

 (B) Importers of industrial greenhouse gases with annual bulk 

imports of N2O, fluorinated GHG, and CO2 that in 

combination are equivalent to 25,000 metric tons CO2e or 

more

 (C) Exporters of industrial greenhouse gases with annual bulk 

exports of N2O, fluorinated GHG, and CO2 that in 

combination are equivalent to 25,000 metric tons CO2e or 

more

Carbon dioxide suppliers (subpart PP):

 (A) All producers of CO2

 (B) Importers of CO2 with annual bulk imports of N2O, 

fluorinated GHG, and CO2 that in combination are 

equivalent to 25,000 metric tons CO2e or more

 (C) Exporters of CO2 with annual bulk exports of N2O, 

fluorinated GHG, and CO2 that in combination are 

equivalent to 25,000 metric tons CO2e or more

Additional Supplier Categories Applicablea in 2011 and Future 

Years

(Reserved)

a Suppliers are defined in each applicable subpart.

 

8. Adding subpart T to read as follows:

Subpart T – Magnesium Production

Sec:

98.200 Definition of source category.

98.201 Reporting thresholds.

98.202 GHGs to report. 

98.203 Calculating GHG emissions. 

98.204 Monitoring and QA/QC requirements.

98.205 Procedures for estimating missing data.

98.206 Data reporting requirements.

98.207 Records that must be retained.

Formatted: Font: Bold

Formatted: No underline

Formatted: No underline

Deleted: 1

Deleted: 1

Deleted: 1

Deleted: 7.

Deleted: Table A-4 of subpart 

A is amended by revising the 

entry for “(Reserved)” to 

read as follows: ¶

Table A-4 of Subpart A—

Source Category List for 

§98.2(a)(2)¶

Source Categories1

Applicable in 2010 and 

Future Years

Deleted: Part 98 is amended 

by a

Deleted: §

Deleted: §

Deleted: §

Deleted: §

Deleted: §

Deleted: §

Deleted: §

Deleted: §

... [4]
137

98.208 Definitions. 

§98.200 Definition of source category.

The magnesium production and processing source 

category consists of the following processes: 

(a) Any process in which magnesium metal is produced 

through smelting (including electrolytic smelting), 

refining, or remelting operations. 

(b) Any process in which molten magnesium is used in 

alloying, casting, drawing, extruding, forming, or rolling 

operations. 

§98.201 Reporting threshold.

You must report GHG emissions under this subpart if 

your facility contains a magnesium production process and 

the facility meets the requirements of either §98.2(a)(1) 

or (2). 

§98.202 GHGs to report.

(a) You must report emissions of the following gases 

in metric tons per year resulting from their use as cover 

gases or carrier gases in magnesium production or 

processing: 

(1) Sulfur hexafluoride (SF6). 

(2) HFC-134a. 

(3) The fluorinated ketone, FK 5-1-12.

(4) Carbon dioxide (CO2). 

Formatted: No underline

Deleted: §

Deleted: ¶

Subpart T—Magnesium 

Production¶

Deleted: S

Deleted: C
138

(5) Any other GHGs (as defined in §98.6). 

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

(General Stationary Fuel Combustion Sources) the CO2, N2O, 

and CH4 emissions from each combustion unit by following the 

requirements of subpart C. 

§98.203 Calculating GHG emissions.

(a) Calculate the mass of each GHG emitted from 

magnesium production or processing over the calendar year 

using either Equation T-1 or Equation T-2 of this section, 

as appropriate. Both of these equations equate emissions 

of cover gases or carrier gases to consumption of cover 

gases or carrier gases. 

(1) To estimate emissions of cover gases or carrier 

gases by monitoring changes in container masses and 

inventories, emissions of each cover gas or carrier gas 

shall be estimated using Equation T-1 of this section: 

 Ex = (IB,x – IE,x + Ax – Dx) * 0.001 (Eq. T-1) 

Where: 

Ex = Emissions of each cover gas or carrier gas, X, in 

metric tons over the reporting year. 

IB,x = Inventory of each cover gas or carrier gas stored 

in cylinders or other containers at the beginning 

of the year, including heels, in kg. 

IE,x = Inventory of each cover gas or carrier gas stored 

in cylinders or other containers at the end of the 

year, including heels, in kg. 

Formatted: Not Superscript/

Subscript

Deleted: on site 

Deleted: calculation 

procedures, monitoring and 

QA/QC methods, missing data 

procedures, reporting 

requirements, and 

recordkeeping 

Deleted: of this part
139

Ax = Acquisitions of each cover gas or carrier gas 

during the year through purchases or other 

transactions, including heels in cylinders or other 

containers returned to the magnesium production or 

processing facility, in kg. 

Dx = Disbursements of each cover gas or carrier gas to 

sources and locations outside the facility through 

sales or other transactions during the year, 

including heels in cylinders or other containers 

returned by the magnesium production or processing 

facility to the gas supplier, in kg. 

0.001= Conversion factor from kg to metric tons 

X = Each cover gas or carrier gas that is a GHG. 

 (2) To estimate emissions of cover gases or carrier 

gases by monitoring changes in the masses of individual 

containers as their contents are used, emissions of each 

cover gas or carrier gas shall be estimated using Equation 

T-2 of this section: 





n

p

GHG QE p

1

001.0* (Eq. T-2) 

Where: 

EGHG = Emissions of each cover gas or carrier gas, X, over 

the reporting year (metric tons). 

Qp = The mass of the cover or carrier gas consumed (kg) 

over the container-use period p, from Equation T-3

of this section. 

n = The number of container-use periods in the year. 

0.001= Conversion factor from kg to metric tons.

X = Each cover gas or carrier gas that is a GHG.

(b) For purposes of Equation T-2 of this section, the 

mass of the cover gas used over the period p for an 

Deleted: 

Deleted: XGHG

Deleted: The e

Deleted: .

Deleted: 
140

individual container shall be estimated by using Equation 

T-3 of this section: 

  MMQ EBp (Eq. T-3) 

Where: 

Qp = The mass of the cover or carrier gas consumed (kg) 

over the container-use period p (e.g., one month). 

MB = The mass of the container's contents (kg) at the 

beginning of period p. 

ME = The mass of the container's contents (kg) at the end 

of period p. 

(c) If a facility has mass flow controllers (MFC) and 

the capacity to track and record MFC measurements to 

estimate total gas usage, the mass of each cover or carrier 

gas monitored may be used as the mass of cover or carrier 

gas consumed (Qp), in kg for period p in Equation T-2 of 

this section. 

§98.204 Monitoring and QA/QC requirements.

(a) For calendar year 2011 monitoring, the facility 

may submit a request to the Administrator to use one or 

more best available monitoring methods as listed in 

§98.3(d)(1)(i) through (iv). The request must be submitted 

no later than [INSERT DATE 90 DAYS AFTER PUBLICATION IN THE 

FEDERAL REGISTER] and must contain the information in 

§98.3(d)(2)(ii). To obtain approval, the request must 

demonstrate to the Administrator’s satisfaction that it is 

Formatted: Subscript

Deleted: utilized 

Deleted: rs

Deleted: emissions value E, 

Deleted: e
141

not reasonably feasible to acquire, install, and operate a 

required piece of monitoring equipment by January 1, 2011. 

The use of best available monitoring methods will not be 

approved beyond December 31, 2011. 

(b) Emissions (consumption) of cover gases and carrier 

gases may be estimated by monitoring the changes in 

container weights and inventories using Equation T-1 of 

this subpart, by monitoring the changes in individual 

container weights as the contents of each container are 

used using Equations T-2 and T-3 of this subpart, or by 

monitoring the mass flow of the pure cover gas or carrier 

gas into the gas distribution system. Emissions must be 

estimated at least annually. 

(c) When estimating emissions by monitoring the mass 

flow of the pure cover gas or carrier gas into the gas 

distribution system, you must use gas flow meters, or mass 

flow controllers, with an accuracy of 1 percent of full 

scale or better. 

(d) When estimating emissions using Equation T-1 of 

this subpart, you must ensure that all the quantities 

required by Equation T-1 of this subpart have been measured 

using scales or load cells with an accuracy of 1 percent of 

full scale or better, accounting for the tare weights of 

the containers. You may accept gas masses or weights 

Deleted: one

Deleted: one
142

provided by the gas supplier (e.g., for the contents of 

containers containing new gas or for the heels remaining in 

containers returned to the gas supplier) if the supplier 

provides documentation verifying that accuracy standards 

are met; however you remain responsible for the accuracy of 

these masses or weights under this subpart. 

(e) When estimating emissions using Equations T-2 and 

T-3 of this subpart, you must monitor and record container 

identities and masses as follows: 

(1) Track the identities and masses of containers 

leaving and entering storage with check-out and check-in 

sheets and procedures. The masses of cylinders returning 

to storage shall be measured immediately before the 

cylinders are put back into storage. 

(2) Ensure that all the quantities required by 

Equations T-2 and T-3 of this subpart have been measured 

using scales or load cells with an accuracy of 1 percent of 

full scale or better, accounting for the tare weights of 

the containers. You may accept gas masses or weights 

provided by the gas supplier (e.g., for the contents of 

cylinders containing new gas or for the heels remaining in 

cylinders returned to the gas supplier) if the supplier 

provides documentation verifying that accuracy standards 

Deleted: one
143

are met; however, you remain responsible for the accuracy 

of these masses or weights under this subpart. 

(f) All flowmeters, scales, and load cells used to 

measure quantities that are to be reported under this 

subpart shall be calibrated using calibration procedures 

specified by the flowmeter, scale, or load cell 

manufacturer. Calibration shall be performed prior to the 

first reporting year. After the initial calibration, 

recalibration shall be performed at the minimum frequency 

specified by the manufacturer. 

§98.205 Procedures for estimating missing data.

(a) A complete record of all measured parameters used 

in the GHG emission calculations is required. Therefore, 

whenever a quality-assured value of a required parameter is 

unavailable, a substitute data value for the missing 

parameter will be used in the calculations as specified in 

paragraph (b) of this section. 

(b) Replace missing data on the emissions of cover or 

carrier gases by multiplying magnesium production during 

the missing data period by the average cover or carrier gas 

usage rate from the most recent period when operating 

conditions were similar to those for the period for which 

the data are missing. Calculate the usage rate for each 

cover or carrier gas using Equation T-4 of this section: 
144

 RGHG = CGHG/Mg * 0.001 (Eq. T-4) 

Where: 

RGHG = The usage rate for a particular cover or carrier 

gas over the period of comparable operation (metric 

tons gas / metric ton Mg). 

CGHG = The consumption of that cover or carrier gas over 

the period of comparable operation (kg). 

Mg = The magnesium produced or fed into the process over 

the period of comparable operation (metric tons). 

0.001 = Conversion factor from kg to metric tons. 

(c) If the precise before and after weights are not 

available, it should be assumed that the container was 

emptied in the process (i.e., quantity purchased should be 

used, less heel). 

§98.206 Data reporting requirements.

In addition to the information required by §98.3(c), 

each annual report must include the following information 

at the facility level: 

(a) Emissions of each cover or carrier gas in metric 

tons. 

(b) Types of production processes at the facility 

(e.g., primary, secondary, die casting). 

(c) Amount of magnesium produced or processed in 

metric tons for each process type. This includes the 

output of primary and secondary magnesium production 

processes and the input to magnesium casting processes. 

Deleted: detailed 

Deleted: for the magnesium 

production and processing
145

(d) Cover and carrier gas flow rate (e.g., standard 

cubic feet per minute) for each production unit and 

composition in percent by volume. 

(e) For any missing data, you must report the length 

of time the data were missing for each cover gas or carrier 

gas, the method used to estimate emissions in their 

absence, and the quantity of emissions thereby estimated. 

(f) The annual cover gas usage rate for the facility

for each cover gas, excluding the carrier gas (kg 

gas/metric ton Mg). 

(g) If applicable, an explanation of any change 

greater than 30 percent in the facility’s cover gas usage 

rate (e.g., installation of new melt protection technology 

or leak discovered in the cover gas delivery system that 

resulted in increased emissions). 

(h) A description of any new melt protection 

technologies adopted to account for reduced or increased 

GHG emissions in any given year. 

§98.207 Records that must be retained. 

In addition to the records specified in §98.3(g), you 

must retain the following information at the facility

level: 

(a) Check-out and weigh-in sheets and procedures for 

gas cylinders. 

Deleted: Typical c

Deleted: facility’s overall

Deleted: (kg gas/metric ton 

Mg) 

Deleted: , for the reporting 

year (e.g., 1 kg SF6 /metric 

ton Mg)

Deleted: for the magnesium 

production or processing 
146

(b) Accuracy certifications and calibration records 

for scales including the method or manufacturer’s 

specification used for calibration. 

(c) Residual gas amounts (heel) in cylinders sent 

back to suppliers. 

(d) Records, including invoices, for gas purchases, 

sales, and disbursements for all GHGs. 

§98.208 Definitions.

All terms used in this subpart have the same meaning 

given in the Clean Air Act and subpart A of this part. 

Additionally, some sector-specific definitions are provided 

below: 

Carrier gas means the gas with which cover gas is 

mixed to transport and dilute the cover gas thus maximizing 

its efficient use. Carrier gases typically include CO2, N2, 

and/or dry air. 

Cover gas means SF6, HFC–134a, fluorinated ketone (FK 

5–1–12) or other gas used to protect the surface of molten 

magnesium from rapid oxidation and burning in the presence 

of air. The molten magnesium may be the surface of a 

casting or ingot production operation or the surface of a 

crucible of molten magnesium that feeds a casting 

operation. 

9. Add subpart FF to read as follows:

Formatted: Indent: Hanging: 108

pt, Bulleted + Level: 4 + Aligned at: 

126 pt + Tab after: 144 pt + Indent

at: 144 pt, Tabs: 54 pt, List tab +

Not at 144 pt

Deleted: is the source of the

Deleted: Part 98 is amended 

by a

Deleted: 9. 

Deleted: ing
147

Subpart FF – Underground Coal Mines

Sec:

98.320 Definition of source category.

98.321 Reporting thresholds.

98.322 GHGs to report. 

98.323 Calculating GHG emissions. 

98.324 Monitoring and QA/QC requirements.

98.325 Procedures for estimating missing data.

98.326 Data reporting requirements.

98.327 Records that must be retained.

98.328 Definitions. 

§98.320 Definition of the source category.

(a) This source category consists of active 

underground coal mines, and any underground mines under 

development that have operational pre-mining degasification 

systems. An underground coal mine is a mine at which coal 

is produced by tunneling into the earth to the coalbed, 

which is then mined with underground mining equipment such 

as cutting machines and continuous, longwall, and shortwall 

mining machines, and transported to the surface. 

Underground coal mines are categorized as active if any one 

of the following five conditions apply:

(1) Mine development is underway.

(2) Coal has been produced within the last 90 days.

Formatted: Font: Bold

Formatted: No underline

Formatted: ___GHG_SECTION

Deleted: §

Deleted: §

Deleted: §

Deleted: §

Deleted: §

Deleted: §

Deleted: §

Deleted: §

Deleted: §

Deleted: Subpart FF—

Underground Coal Mines¶

Deleted: when m

Deleted: ,

Deleted: c

Deleted: ,
148

(3) Mine personnel are present in the mine workings.

(4) Mine ventilation fans are operative. 

(5) The mine is designated as an ”intermittent” mine

by the Mine Safety and Health Administration (MSHA). 

(b) This source category includes the following: 

(1) Each ventilation well or shaft, including both 

those wells and shafts where gas is emitted and those where 

gas is sold, used onsite, or otherwise destroyed (including 

by flaring). 

(2) Each degasification system well or shaft, 

including degasification systems deployed before, during, 

or after mining operations are conducted in a mine area. 

This includes both those wells and shafts where gas is 

emitted, and those where gas is sold, used onsite, or 

otherwise destroyed (including by flaring). 

(c) This source category does not include abandoned 

or closed mines, surface coal mines, or post-coal mining 

activities (e.g., storage or transportation of coal). 

§98.321 Reporting threshold.

You must report GHG emissions under this subpart if 

your facility contains an active underground coal mine and 

the facility meets the requirements of §98.2(a)(1). 

§98.322 GHGs to report.

Deleted: m

Deleted: ,

Deleted: or m

Deleted: For the purposes of 

this rule, MSHA 

Deleted: s

Deleted: 

Deleted: are also considered 

active mines. (See 

definitions in §98.328 of 

this subpart.)

Deleted: .

Deleted: This 

Deleted: es

Deleted: ,
149

(a) You must report CH4 liberated from ventilation and 

degasification systems. 

(b) You must report CH4 destruction from systems where 

gas is sold, used onsite, or otherwise destroyed (including 

by flaring). 

(c) You must report net CH4 emissions from ventilation 

and degasification systems. 

(d) You must report under this subpart the CO2

emissions from coal mine gas CH4 destruction occuring at the 

facility, where the gas is not a fuel input for energy 

generation or use (e.g., flaring). 

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

(General Stationary Fuel Combustion Sources) the CO2, CH4, 

and N2O emissions from each stationary fuel combustion unit 

by following the requirements of subpart C. Report 

emissions from both the combustion of collected coal mine 

CH4 and any other fuels. 

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

part because emissions from source categories described in 

subparts C through PP of this part is not required to 

report emissions under subpart FF of this part unless the 

coal mine is subject to quarterly or more frequent sampling 

of ventilation systems by MSHA. 

§98.323 Calculating GHG emissions.

Deleted: The CH4 liberated is 

the total volume of CH4

released from the coal and 

surrounding rock strata 

during the mining (or premining) process. As stated, 

this is the total determined 

by summing the volume of CH4

emitted from the ventilation 

system and the volume of CH4

drained from the 

degasification system. This 

includes degasification 

systems deployed before, 

during, or after mining 

operations are conducted in 

a mine area, and both those 

wells and shafts where gas 

is emitted, and those where 

gas is sold, used onsite, or 

otherwise destroyed 

(including by flaring). ¶

Deleted: This includes 

degasification systems 

deployed before, during, or 

after mining operations are 

conducted in a mine area. 

Net CH4 emissions are 

determined by deducting the 

CH4 in gas that is sold, 

used onsite, or otherwise 

destroyed (including by 

flaring), from the amount of 

CH4 liberated. 

Deleted: devices

Deleted: This includes

Deleted: 

Deleted: of fugitive CH4

emissions

Deleted: You must follow the 

requirements of subpart C of 

this part.
150

(a) For each ventilation shaft, vent hole, or 

centralized point into which CH4 from multiple shafts and/or 

vent holes are collected, you must calculate the quarterly 

CH4 liberated from the ventilation system using Equation FF1 of this section. You must measure CH4 content, flow rate, 

temperature, pressure, and moisture content of the gas 

using the procedures outlined in §98.324. 















  1,000

0.454

 * 1,440*

atm1

P * TR520

*0.0423 *

100%

C

*V*nCH4V



MCF * (Eq. FF-1) 

Where: 

CH4V = Quarterly CH4 liberated from a ventilation 

monitoring point (metric tons CH4). 

V = Daily volumetric flow rate for the quarter

(scfm) 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”. 

MCF = Moisture correction factor for the 

measurement period, volumetric basis. 

 = 1 when V and C are measured on a dry basis 

or if both are measured on a wet basis. 

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

and C is measured on a dry basis. 

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

basis and C is measured on a wet basis. 

(fH2O) = Moisture content of the methane emitted 

during the measurement period, volumetric 

basis (cubic feet water per cubic feet 

emitted gas) 

C = Daily CH4 concentration of ventilation gas 

for the quarter (%, wet basis). 

Deleted: monitoring point in 

the ventilation system (this 

could be at each 

Deleted: and/or 

Deleted: at more 

Deleted: s

Deleted: )

Deleted: the measured CH4

content and flow rate, and 

Deleted: the

Deleted: Average d

Deleted: measured total 

Deleted: from the ventilation 

monitoring point (scfm)

Deleted: .

Deleted: If the flow rate was 

determined 

Deleted: ,

Deleted: the sampled rate 

will be used for determining 

an estimate for average 

daily flow rate. 

Deleted: the

Deleted: for this measurement

Deleted: Average m

Deleted: Average d

Deleted: measured 

Deleted: during ventilation 

at each monitoring point

Deleted: (%, wet basis)

Deleted: If concentration is 

measured from a single 

sample, it should be assumed 

the the sample concentration 

is the same as the average 

daily value.¶
151

n = The number of days in the quarter where 

active ventilation of mining operations is 

taking place at the monitoring point. 

0.0423 = Density of CH4 at 520°R (60°F) and 1 atm 

(lb/scf). 

520 o

R = 520 degrees Rankine. 

T = Temperature at which flow is measured (°R) 

for the quarter. 

P = Pressure at which flow is measured (atm) 

for the quarter. 

1,440 = Conversion factor (min/day). 

0.454/1,000 = Conversion factor (metric ton/lb). 

(1) Consistent with MSHA inspections, the quarterly 

periods are: 

(i) January 1 – March 31.

(ii) April 1 - June 30.

(iii) July 1 - September 30.

(iv) October 1 - December 31.

(2) Daily values of V, MCF, C, T, and P must be based 

on measurements taken at least once each quarter with no 

fewer than 6 weeks between measurements. If measurements 

are taken more frequently than once per quarter, then use 

the average value for all measurements taken. If continous 

measurements are taken, then use the average value over the 

time period of continuous monitoring. 

(3) If a facility has more than one monitoring point, 

the facility must calculate total CH4 liberated from 

Formatted: Indent: First line: 36 pt

Formatted: Bullets and Numbering

Deleted: Average daily t

Deleted: If temperature is 

measured from a single 

sample, it should be assumed 

that the sample temperature 

is the same as the average 

daily value.¶

Deleted: Average daily p

Deleted: If pressure is 

measured from a single 

sample, it should be assumed 

that the sample pressure is 

the same as the average 

daily value.¶

Deleted: 

Deleted: 

Deleted: Samples are to be 

taken at least once each 

quarter with no fewer than 6 

weeks between measurements. 

The average daily values for 

V, MCF, C, T, and P for the 

quarter are calculated based 

on the frequency of 

measurement. For example, 

if quarterly measurements 

are taken, they should 

represent the average values 

on the day the measurements 

are taken. If weekly 

measurements are taken, they 

represent the average values 

for the week. If continous 

measurements are taken, they 

represent the average values 

over the time period of 

continuous monitoring. 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 perating under 

normal conditions.¶

For the reporting mine, 

Deleted: i
152

ventilation systems (CH4vTotal) as the sum of the CH4 from all 

ventilation monitoring points in the mine, as follows: 





m

i

CH iV

1

4VTotal 4 CH )( (Eq. FF-2) 

Where: 

CH4VTotal = Total quarterly CH4 liberated from ventilation 

systems (metric tons CH4).

CH4V = Quarterly CH4 liberated from each ventilation 

monitoring point (metric tons CH4).

m = Number of ventilation monitoring points.

(b) For each monitoring point in the degasification 

system (this could be at each degasification well and/or 

vent hole, or at more centralized points into which CH4 from 

multiple wells and/or vent holes are collected), you must 

calculate the weekly CH4 liberated from the mine using CH4

measured weekly or more frequently (including by CEMS) 

according to 98.234(c), CH4 content, flow rate, temperature, 

pressure, and moisture content, and Equation FF-3 of this 

section. 















   1,000

0.454 * 1,440* atm1

P * T

R520 *0.0423*

100%

C CH *MCF*V i

i

o

i

i i

1

4D

n

i

(Eq. FF-3) 

Where: 

CH4D = Weekly CH4 liberated from at the

monitoring point(metric tons CH4). 

Vi = Daily measured total volumetric flow rate 

for the days in the week when the 

degasification system is in operation at 

Formatted: Lowered by 14 pt

Formatted: Not Superscript/

Subscript

Formatted: Not Superscript/

Subscript

Formatted: Subscript

Formatted: Lowered by 16 pt

Deleted: CH4VTotal = ΣMonitoring 

Points (CH4V)

Deleted: Q

Deleted: each 

Deleted: monitoring point

Deleted: r

Deleted: b

Deleted: l

Deleted: ¶

Deleted: at that measurement 

point 

Deleted: 





 CH   n *V MC 1

4D

n

Deleted: thea

Deleted: n

Deleted: Average d
153

that monitoring point, based on sampling 

or a flow rate meter (scfm). 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”. 

MCFi = Moisture correction factor for the 

measurement period, volumetric basis. 

 = 1 when Vi and Ci are measured on a dry 

basis or if both are measured on a wet 

basis. 

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

basis and Ci is measured on a dry basis. 

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

basis and Ci is measured on a wet basis. 

(fH2O) = Moisture content of the CH4 emitted during 

the measurement period, volumetric basis 

(cubic feet water per cubic feet emitted 

gas) 

Ci = Daily CH4 concentration of gas for the 

days in the week when the degasification 

system is in operation at that monitoring 

point (%, wet basis). 

n = The number of days in the week that the 

system is operational at that measurement 

point. 

0.0423 = Density of CH4 at 520°R (60°F) and 1 atm 

(lb/scf). 

520 o

R = 520 degrees Rankine. 

Ti = Daily temperature at which flow is 

measured (°R). 

Pi = Daily pressure at which flow is measured 

(atm).

1,440 = Conversion factor (minutes/day). 

0.454/1,000 = Conversion factor (metric ton/lb). 

(1) Daily values for V, MCF, C, T, and P must be 

based on measurements taken at least once each calendar

with at least 3 days between measurements. If measurements 

are taken more frequently than once per week, then use the 

Formatted: Font: (Default) Courier

New

Formatted: Font: (Default) Courier

New, Not Superscript/ Subscript

Formatted

Formatted

Formatted: Subscript

Formatted: Subscript

Deleted: and the continuous 

monitoring equipment is 

properly functioning

Deleted: , or the measured 

temperature when weekly 

sampling is performed.

Deleted: for this measurement 

that

Deleted: n

Deleted: n

Deleted: n

Deleted: n

Deleted: n

Deleted: n

Deleted: n

Deleted: n

Deleted: n

Deleted: n

Deleted: n

Deleted: n

Deleted: Average moisture 

Deleted: n

Deleted: Average d

Deleted: estimated or 

Deleted: and the continuous 

Deleted: n

Deleted: Measured average tT

Deleted: for the days in the 

Deleted: n

Deleted: Measured average pP

Deleted: for the days in the 

Deleted: when the 

Deleted: Average d

Deleted: for the 

Deleted: week are calculated 

Deleted: t

... [6]

... [10]

... [11]

... [12]

... [9]

... [7]

... [8]

... [13]

... [5]
154

average value for all measurements taken that week. If 

continuous measurements are taken, then use the average 

values over the time period of continuous monitoring when 

the continuous monitoring equipment is properly 

functioning. 

(2) Quarterly total CH4 liberated from degasification 

systems for the mine should be determined as the sum of CH4

liberated determined at each of the monitoring points in 

the mine, summed over the number of weeks in the quarter, 

as follows: 

   D ji

w

j

m

i

CH 4 ,

11

CH4DTotal   (Eq. FF-4) 

Where: 

CH4DTotal = Quarterly CH4 liberated from all degasification 

monitoring points (metric tons CH4). 

CH4D = Weekly CH4 liberated from a degasification 

monitoring point (metric tons CH4).

m = Number of monitoring points.

w = Number of weeks in the quarter during which the 

degasification system is operated.

(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 

Formatted: Left

Deleted: If weekly 

measurements are taken, they 

represent the average values 

for the week. Weekly means 

once each calendar week, 

with at least 3 days between 

measurements. 

Deleted: they represent

Deleted: For the reporting 

mine, q

Deleted: CH4DTotal = ΣWeeks in 

Quarter(ΣEmission Points 

(CH4D))¶

Deleted: each

Deleted: sing

Deleted: ,

Deleted: /or
155

Equation FF-5 of this section. You must measure CH4 content 

and flow rate according to the provisions in §98.324. 

 CH4Destroyed = CH4 x DE (Eq. FF-5) 

Where: 

CH4Destroyed = Quarterly CH4 destroyed (metric tons). 

CH4 = Quarterly CH4 routed to the destruction

device or offsite transfer point (metric 

tons). 

DE = Destruction efficiency (lesser of 

manufacturer’s specified destruction 

efficiency and 0.99). If the gas is 

transported off-site for destruction, use 

DE = 1.

(1) Calculate total CH4 destroyed as the sum of the 

methane destroyed at all destruction devices (onsite and 

offsite), using Equation FF-6 of this section.

  Destroyed d

d

i

CH4

1

CH Total 4Destroyed  (Eq. FF-6) 

Where: 

CH4DestroyedTotal = Quarterly total CH4 destroyed at the mine 

(metric tons CH4).

CH4Destroyed = Quarterly CH4 destroyed from each 

destruction device or offsite transfer 

point.

d = Number of onsite destruction devices and 

points of ofsite transport.

Formatted: Not Superscript/

Subscript

Formatted: Lowered by 14 pt

Deleted: liberated from the 

mine that is destroyed at 

each destruction device or 

tranported offsite for 

destruction

Deleted: collected for

Deleted: 

Deleted: For the reporting 

mine, if a facility has more 

than one destruction device 

or point of offsite 

transport to a destruction 

device, the facility must 

calculate total CH4

destroyed (CH4DestroyedTotal), 

determined

Deleted: as follows

Deleted: :

Deleted: CH4DestroyedTotal=ΣDestruc

tion devices (CH4Destroyed)¶

Deleted: sum of the measured 

Deleted: all mine ventilation 

and degasification systems.
156

(d) You must calculate the quarterly measured net CH4

emissions to the atmosphere using Equation FF-7 of this 

section. 

 CH4 emitted (net) = CH4VTotal + CH4DTotal – CH4destroyedTotal(Eq. FF-7) 

Where: 

CH4 emitted (net)= Quarterly CH4 emissions from the mine

(metric tons). 

CH4VTotal = Quarterly sum of the CH4 liberated from 

all mine ventilation monitoring points 

(CH4V), calculated using Equation FF-2 

of this section (metric tons). 

CH4DTotal = Quarterly sum of the CH4 liberated from 

all mine degasification monitoring 

points(CH4D), calculated using Equation 

FF-4 of this section (metric tons). 

CH4DestroyedTotal = Quarterly sum of the measured CH4

destroyed from all mine ventilation and 

degasification systems, calculated 

using Equation FF-6 of this section 

(metric tons). 

(e) For the methane collected from degasification 

and/or ventilation systems that is destroyed on site and is 

not a fuel input for energy generation or use (those 

emissions are monitored and reported under Subpart C of 

this part), you must estimate the CO2 emissions using 

Equation FF-8 of this section. 

 CO2 = CH4Destroyedonsite * 44/16 (Eq. FF-8) 

Where: 

CO2 = Total quarterly CO2 emissions from CH4

destruction (metric tons). 

Formatted: Subscript

Deleted: in the quarter 

summed over all mine 

ventilation and 

degasification monitoring 

points
157

CH4Destroyedonsite = Quarterly sum of the CH4 destroyed, 

calculated as the sum of CH4 destroyed 

for each onsite, non-energy use, as 

calculated individually in Equation FF5 of this section (metric tons). 

44/16 = Ratio of molecular weights of CO2 to 

CH4. 

§98.324 Monitoring and QA/QC requirements. 

(a) For calendar year 2011 monitoring, the facility 

may submit a request to the Administrator to use one or 

more best available monitoring methods as listed in 

§98.3(d)(1)(i) through (iv). The request must be submitted 

no later than [INSERT DATE 90 DAYS AFTER PUBLICATION IN THE 

FEDERAL REGISTER] and must contain the information in 

§98.3(d)(2)(ii). To obtain approval, the request must 

demonstrate to the Administrator’s satisfaction that it is 

not reasonably feasible to acquire, install, and operate a 

required piece of monitoring equipment by January 1, 2011. 

The use of best available monitoring methods will not be 

approved beyond December 31, 2011. 

(b) For CH4 liberated from ventilation systems, 

determine whether CH4 will be monitored from each 

ventilation well and shaft, from a centralized monitoring 

point, or from a combination of the two options. Operators 

are allowed flexibility for aggregating emissions from more 

than one ventilation well or shaft, as long as emissions 

from all are addressed, and the methodology for calculating 

Formatted: Subscript

Formatted: Subscript

Formatted: Subscript
158

total emissions documented. Monitor by one of the 

following options: 

(1) Collect quarterly or more frequent grab samples 

(with no fewer than 6 weeks between measurements) and make

quarterly measurements of flow rate, temperature, and 

pressure. 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, airflow, temperature, and pressure measured, the 

hand-held methane and oxygen readings (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. 

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

continuous emission monitoring systems (CEMS). If 

operators use CEMS as the basis for emissions reporting, 

they must provide documentation on the process for using 

Deleted: Monitor emissions 

from each ventilation well 

or shaft or centralized 

monitoring point where 

ventilation is taking place 

by c

Deleted: ing

Deleted: ing

Deleted: in 

Deleted: ile
159

data obtained from their CEMS to estimate emissions from 

their mine ventilation systems. 

(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 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). 

(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 and 

methane composition from these degasification wells and gob 

gas vent holes. Methane composition should be determined 

either by submitting samples to a lab for analysis, or from 

the use of methanometers at the degasification well site. 

Follow the sampling protocols for sampling of methane 

emissions from ventilation shafts, as described in 

§98.324(b)(1). 

Deleted: Direct monitoring 

using continuous wellbore 

monitors of gas recovered 

from mine degasification 

systems, where such systems 

are already in place. This 

includes both measurement of 

the gas volume recovered, 

along with measurements of 

methane concentrations in 

recovered gas volumes

Deleted: The c

Deleted: ion

Deleted: of 

Deleted: This includes both 

measurement of the gas 

volume emitted and 

recovered, along with 

measurements of methane 

concentrations in gas 

volumes recovered or 

emitted. Operators are 

required to d

Deleted: S

Deleted: should be the same 

as that described 

Deleted: Methanometers and 

gas flow meters are required 

to be properly calibrated.
160

(d) Monitoring must adhere to 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). 

(e) All fuel flow meters, gas composition monitors, 

and heating value monitors that are used to provide data 

for the GHG emissions calculations shall be calibrated 

prior to the first reporting year, using the applicable 

methods specified in paragraphs (1) through (7) of this 

section. Alternatively, calibration procedures specified 

by the flow meter manufacturer may be used. Fuel flow 

meters, gas composition monitors, and heating value 

monitors shall be recalibrated either annually or at the 

minimum frequency specified by the manufacturer, whichever 

is more frequent. For fuel, flare, or sour gas flow 

meters, the operator shall operate, maintain, and calibrate 

the flow meter using any of the following test methods or 

follow the procedures specified by the flow meter 

Deleted: (Reapproved 2006)
161

manufacturer. Flow meters must meet the accuracy 

requirements in 98.3(i). 

(1) ASME MFC–3M–2004, Measurement of Fluid Flow in 

Pipes Using Orifice, Nozzle, and Venturi (incorporated by 

reference, see §98.7). 

(2) ASME MFC–4M–1986 (Reaffirmed 1997), Measurement 

of Gas Flow by Turbine Meters (incorporated by reference, 

see §98.7). 

(3) ASME MFC–6M–1998, Measurement of Fluid Flow in 

Pipes Using Vortex Flowmeters (incorporated by reference, 

see §98.7). 

(4) ASME MFC–7M–1987 (Reaffirmed 1992), Measurement 

of Gas Flow by Means of Critical Flow Venturi Nozzles 

(incorporated by reference, see §98.7). 

(5) ASME MFC-11M-2006 Measurement of Fluid Flow by 

Means of Coriolis Mass Flowmeters (incorporated by 

reference, see §98.7). 

(6) ASME MFC-14M-2003 Measurement of Fluid Flow Using 

Small Bore Precision Orifice Meters (incorporated by 

reference, see §98.7). 

(7) ASME MFC-18M-2001 Measurement of Fluid Flow using 

Variable Area Meters (incorporated by reference, see 

§98.7). 
162

(f) For CH4 destruction, CH4 must be monitored at each 

onsite destruction device and each point of offsite 

transport for combustion using continuous monitors of gas 

routed to the device or point of offsite transport.

(g) All temperature and pressure monitors must be 

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, and pressure 

measurements. These procedures include, but are not 

limited to, calibration of fuel flow meters, and other 

measurement devices. The estimated accuracy of 

measurements, and the technical basis for the estimated 

accuracy shall be recorded. 

§98.325 Procedures for estimating missing data.

(a) A complete record of all measured parameters used 

in the GHG emissions calculations is required. Therefore, 

whenever a quality-assured value of a required parameter is 

unavailable (e.g., if a meter malfunctions during unit 

operation or if a required fuel sample is not taken), a 

substitute data value for the missing parameter shall be 

used in the calculations, in accordance with paragraph (b) 

of this section. 

Deleted: f

Deleted: g
163

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

rate, temperature, and pressure for ventilation and 

degasification systems, the substitute data value shall be 

the arithmetic average of the quality-assured values of 

that parameter immediately preceding and immediately 

following the missing data incident. If, for a particular 

parameter, no quality-assured data are available prior to 

the missing data incident, the substitute data value shall 

be the first quality-assured value obtained after the 

missing data period. 

§98.326 Data reporting requirements. 

In addition to the information required by §98.3(c), 

each annual report must contain the following information 

for each mine: 

(a) Quarterly CH4 liberated from each ventilation 

monitoring point (CH4Vm), (metric tons CH4). 

(b) Weekly CH4 liberated from each degasification 

system monitoring point (metric tons CH4).

(c) Quarterly CH4 destruction at each ventilation and 

degasification system destruction device or point of 

offsite transport (metric tons CH4). 

(d) Quarterly CH4 emissions (net) from all ventilation 

and degasification systems (metric tons CH4). 

Formatted: Subscript

Formatted: Subscript

Formatted: Subscript

Formatted: Subscript

Deleted: (See definitions for 

Equations FF-1 through FF-5 

for the definitions of the 

terms in parentheses) 

Deleted: and from each 

degasification system 

monitoring point (this 

includes degasification 

systems deployed before, 

during, or after mining 

operations are conducted in 

a mine area)(CH4V and CH4D), 

reported in

Deleted: 

Deleted: m

Deleted: 

Deleted: (CH4Destroyed), reported 

in

Deleted: c

Deleted: this includes 

degasification systems 

deployed before, during, or 

after mining operations are 

conducted in a mine area) 

(CH4 emitted (net)), 

reported in 
164

(e) Quarterly CO2 emissions from on-site destruction 

of coal mine gas CH4, where the gas is not a fuel input for 

energy generation or use (e.g., flaring) (metric tons CO2). 

(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). 

(g) Quarterly CH4 concentration for each ventilation 

monitoring point, dates and locations of each measurement 

and method of measurement (sampling or continuous 

monitoring). 

(h) Weekly volumetric flow used to calculate CH4

liberated from degasification systems (scf) and method of 

measurement (sampling or continuous monitoring).

(i) Quarterly CEMS CH4 concentration (%) used to 

calculate CH4 liberated from degasification systems (average 

from daily data), or quarterly CH4 concentration data based 

on results from weekly sampling data)(C).

(j) Weekly volumetric flow used to calculate CH4

destruction for each destruction device and each point of 

offsite transport (scf).

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

destruction (C).

Formatted: Subscript

Formatted: Indent: Left: 0 pt, First

line: 36 pt, Numbered + Level: 1 +

Numbering Style: a, b, c, ... + Start

at: 10 + Alignment: Left + Aligned

at: 36 pt + Tab after: 108.75 pt +

Indent at: 108.75 pt, Tabs: 72 pt,

List tab + Not at 108.75 pt

Formatted: Subscript

Formatted: Indent: First line: 36 pt

Formatted: Subscript

Formatted: Subscript

Deleted: d

Deleted: (CO2), reported in 

Deleted: e

Deleted: (scfm) 

Deleted: including 

Deleted: (s)

Deleted: (s)

Deleted: whether based on 

quarterly sampling or 

continuous monitoring (V)

Deleted: f

Deleted: (%) 

Deleted: including

Deleted: (

Deleted: )

Deleted: (

Deleted: )

Deleted: , whether based on 

quarterly

Deleted: (C)

Deleted: g

Deleted: Quarterly sum of 

CEMS

Deleted: data 

Deleted: (summed from daily 

CEMS data) 

Deleted: ,

Deleted: or quarterly 

reporting of volumetric flow 

data (scf) based on results 

from weekly 

Deleted: data)(V).

Deleted: h
165

(l) Dates in quarterly reporting period where active 

ventilation of mining operations is taking place. 

(m) Dates in quarterly reporting period where 

degasification of mining operations is taking place. 

(n) Dates in quarterly reporting period when 

continuous monitoring equipment is not properly 

functioning, if applicable. 

(o) Temperatures (°R) and pressure (atm) at which 

each sample is collected. 

(p) For each destruction device, a description of the 

device, including an indication of whether destruction 

occurs at the coal mine or off-site. If destruction occurs 

at the mine, also report an indication of whether a back-up 

destruction device is present at the mine, the annual 

operating hours for the primary destruction device, the 

annual operating hours for the back-up destruction device 

(if present), and the destruction efficiencies assumed 

(percent). 

(q) A description of the gas collection system 

(manufacturer, capacity, and number of wells) the surface 

area of the gas collection system (square meters), and the 

annual operating hours of the gas collection system. 

(r) Identification information and description for 

each well and shaft, indication of whether the well or 

Deleted: i

Deleted: 

Deleted: j

Deleted: 

Deleted: k

Deleted: l

Deleted: values 

Deleted: the time, location 

(shaft or vent, 

degasification well or 

measurement point), and at 

the conditions for which 

measurements are made (T and 

P)

Deleted: m

Deleted: n

Deleted: , etc.

Deleted: ,

Deleted: o
166

shaft is monitored individually, or as part of a 

centralized monitoring point. Note which method (sampling 

or continuous monitoring) was used. 

(s) For each centralized monitoring point, 

identification of the wells and shafts included in the 

point. Note which method (sampling or continuous 

monitoring) was used. 

§98.327 Records that must be retained.

In addition to the information required by §98.3(g), 

you must retain the following records: 

(a) Calibration records for all monitoring equipment, 

including the method or manufacturer’s specification used 

for calibration. 

(b) Records of gas sales. 

(c) Logbooks of parameter measurements. 

(d) Laboratory analyses of samples. 

§98.328 Definitions.

All terms used in this subpart have the same meaning 

given in the Clean Air Act and subpart A of this part. 

10. Add subpart II to read as follows.

Subpart II – Industrial Wastewater Treatment

Sec:

98.350 Definition of source category.

98.351 Reporting thresholds.

Formatted: Indent: First line: 36 pt,

Tabs: 72 pt, Left

Formatted: Indent: First line: 0 pt

Formatted: Font: Bold

Deleted: p

Deleted: 9

Deleted: 10. 

Deleted: Part 98 is amended 

by a

Deleted: ing

Deleted: T

Deleted: §

Deleted: §
167

98.352 GHGs to report. 

98.353 Calculating GHG emissions. 

98.354 Monitoring and QA/QC requirements.

98.355 Procedures for estimating missing data.

98.356 Data reporting requirements.

98.357 Records that must be retained.

98.358 Definitions. 

Table II-1 of Subpart II–Emission Factors

Table II-2 of Subpart II-Collection Efficiencies of 

Anaerobic Processes

§98.350 Definition of Source Category

(a) This source category consists of anaerobic 

processes used to treat industrial wastewater and 

industrial wastewater treatment sludge at facilities that 

perform the operations listed in this paragraph.

(1) Pulp and paper manufacturing.

(2) Food processing.

(3) Ethanol production.

(4) Petroleum refining. 

(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 

Formatted: No underline

Formatted: ___GHG_SECTION

Formatted: Underline

Deleted: §

Deleted: §

Deleted: §

Deleted: §

Deleted: §

Deleted: §

Deleted: §

Deleted: s

Deleted: A

Deleted: Subpart II—

Industrial Wastewater 

Treatment¶

Deleted: applies to

Deleted: e

Deleted: p

Deleted: mills

Deleted: ,

Deleted: f

Deleted: facilities,

Deleted: 

Deleted: e

Deleted: facilities,

Deleted: and p

Deleted: eries

Deleted: 
168

CH4. This source category consists of the following: 

anaerobic reactors, anaerobic lagoons, anaerobic sludge 

digesters, and biogas destruction devices (for example, 

burners, boilers, turbines, flares, or other devices). 

(1) An anaerobic reactor is an enclosed vessel used 

for anaerobic wastewater treatment (e.g., upflow anaerobic 

sludge blanket, fixed film).

(2) An anaerobic sludge digester is an enclosed vessel 

in which wastewater treatment sludge is degraded 

anaerobically.

(3) An anaerobic lagoon is a lined or unlined earthen 

basin used for wastewater treatment, in which oxygen is 

absent throughout the depth of the basin, except for a 

shallow surface zone. Anaerobic lagoons are not equipped 

with surface aerators. Anaerobic lagoons are classified as 

deep (depth more than 2 meters) or shallow (depth less than 

2 meters).

(c) This source category does not include municipal 

wastewater treatment plants or separate treatment of 

sanitary wastewater at industrial sites. 

§98.351 Reporting threshold.

You must report GHG emissions under this subpart if 

your facility meets all of the conditions under paragraphs 

(a) or (b) of this section: 

Formatted: Underline

Formatted: No underline

Formatted: No underline

Deleted: processes

Deleted: s are

Deleted: facilities

Deleted: (c) This source 

category consists of the 

following: anaerobic 

reactors, anaerobic lagoons, 

anaerobic sludge digesters, 

and biogas destruction 

devices (including, for 

example, burners, boilers, 

turbines, and flares). ¶
169

(a) Petroleum Refineries and Pulp and Paper 

Manufacturing. 

(1) The facility is subject to reporting under 

subpart Y of this part (Petroleum Refineries) or subpart AA 

of this part (Pulp and Paper Manufacturing). 

(2) The facility meets the requirements of either 

§98.2(a)(1) or (2). 

(3) The facility operates an anaerobic process to 

treat industrial wastewater and/or industrial wastewater 

treatment sludge. 

(b) Ethanol Production and Food Processing Facilities 

(1) The facility performs an ethanol production or 

food processing operation, as defined in §98.358 of this 

subpart. 

(2) The facility meets the requirements of 

§98.2(a)(2). 

(3) The facility operates an anaerobic process to 

treat industrial wastewater and/or industrial wastewater 

treatment sludge. 

§98.352 GHGs to report.

(a) You must report CH4 generation, CH4 emissions, and 

CH4 recovered from treatment of industrial wastewater at 

each anaerobic lagoon and anaerobic reactor. 

Deleted: contains

Deleted: meets a definition 

Deleted: 6

Deleted: using

Deleted: s

Deleted: or

Deleted: s
170

(b) You must report CH4 emissions and CH4 recovered 

from each anaerobic sludge digester. 

(c) You must report CH4 emissions and CH4 destruction 

resulting from each biogas collection and biogas 

destruction device. 

(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 landfill gas destruction device, if 

present, by following the requirements of subpart C of this 

part. 

§98.353 Calculating GHG emissions.

(a) For each anaerobic reactor and anaerobic lagoon,

estimate the annual mass of CH4 generated according to the 

applicable requirements in paragraphs (a)(1) through (a)(2) 

of this section. 

(1) If you measure the concentration of organic 

material entering the anaerobic reactors or anaerobic 

lagoon using methods for the determination of chemical 

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

generated using Equation II-1 of this section. 

 



 

52

1

4 001.0 w

GCH n Floww ow MCFBCOD (Eq. II-1) 

Where: 

Deleted: s

Deleted: s

Deleted: all

Deleted: wastewater treatment 

processes

Deleted: ,

Deleted: except anaerobic 

sludge digesters, 

Deleted: wastewater treatment 

processes (specifically 

anaerobic 

Deleted: and

Deleted: s)

Deleted: for each process
171

CH4Gn = Annual mass CH4 generated from the nth anaerobic 

wastewater treatment process (metric tons).

n = Index for processes at the facility, used in 

Equation II-7.

w = Index for weekly measurement period.

Floww = Volume of wastewater sent to an anaerobic 

wastewater treatment process in week w (m3

/week), 

measured as specified in §98.354(d). 

CODw = Average weekly concentration of chemical oxygen 

demand of wastewater entering an anaerobic 

wastewater treatment process (for week w)(kg/m3

), 

measured as specified in §98.354(b) and (c). 

B0 = Maximum CH4 producing potential of wastewater (kg 

CH4/kg COD), use the value 0.25. 

MCF = CH4 conversion factor, based on relevant values 

in Table II-1 of this subpart. 

0.001 = Conversion factor from kg to metric tons. 

(2) If you measure the concentration of organic 

material entering an anaerobic reactors 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. 

  

 

52

1

4 ,5 001.0 w

GCH n Floww ow MCFBBOD (Eq. II-2) 

Where: 

CH4Gn = Annual mass of CH4 generated from the anaerobic 

wastewater treatment process (metric tons).

n = Index for processes at the facility, used in 

Equation II-7.

w = Index for weekly measurement period.

Floww = Volume of wastewater sent to an anaerobic 

wastewater treatment process in week w(m3/week), 

measured as specified in §98.354(d). 

Deleted: ¶

w = Index for weekly 

measurement period.

Deleted: wastewater treatment 

processes (specifically 

anaerobic 

Deleted: and

Deleted: s)

Deleted: for each process

Deleted: ¶

Deleted: n
172

BOD5,w = Average weekly concentration of 5-day 

biochemical oxygen demand of wastewater entering 

an anaerobic wastewater treatment process for 

week w(kg/m3

), measured as specified in 

§98.354(b) and (c). 

B0 = Maximum CH4 producing potential of wastewater (kg 

CH4 /kg BOD5), use the value 0.6. 

MCF = CH4 conversion factor, based on relevant values 

in Table II-1 of this subpart. 

0.001 = Conversion factor from kg to metric tons. 

(b) For each anaerobic reactor and anaerobic lagoon

from which biogas is not recovered, estimate annual CH4

emissions using Equation II-3 of this section. 

 CH4En = CH4Gn (Eq. II-3) 

Where: 

CH4En = Annual mass of CH4 emissions from the wastewater 

treatment process n from which biogas is not 

recovered (metric tons). 

CH4Gn = Annual mass of CH4 generated from the wastewater 

treatment process n, as calculated in Equation 

II-1 or II-2 of this section(metric tons). 

(c) For each anaerobic 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 gas flow rate as specified in 

§98.354(f) and (h). 

Formatted: Subscript

Formatted: Subscript

Deleted: month n

Deleted: w = Index for weekly 

measurement period.¶

Deleted: wastewater treatment 

process (anaerobic 

Deleted: )

Deleted: n

Deleted: n

Deleted: n

Deleted: process (such as 

anaerobic 

Deleted: )
173

(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 content requires only the 

summing of results of all monitoring periods for a given 

year. 

Rn = 







 



  M

1m

m

m

mCH4

m mMC 1,000

 0.454 * 

atm 1

(P) * 

(T)

R520 * 0.0423 * 

100%

)(C * )(K * (V) (Eq. II-4) 

Where: 

Rn = Annual quantity of CH4 recovered from the 

nth anaerobic reactor, digester, or lagoon 

(metric tons CH4/yr)

n = Index for processes at the facility, used 

in Equation II-7.

M = Total number of measurement periods in a 

year. Use M=365 (M=366 for leap years) for 

daily averaging of continuous monitoring, 

as provided in paragraph(c)(1)of this 

section. Use M=52 for weekly sampling, as 

provided in paragraph(c)(2)of this section. 

m = Index for measurement period. 

Vm = Cumulative volumetric flow for the 

measurement period in actual cubic 

feet(acf). If no biogas was recovered 

during a monitoring period, use zero. 

Formatted: Subscript

Formatted: Subscript

Deleted: n

Deleted: n

Deleted: nN

Deleted: ¶

= 365

Deleted: n

Deleted: nN

Deleted: n

Deleted: ¶

=

Deleted: n
174

(KMC)m = Moisture correction term for the 

measurement period, volumetric basis. 

 = 1 when (V)m and (CCH4)m are measured on a dry 

basis or if both are measured on a wet 

basis. 

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

basis and (CCH4)m is measured on a dry basis. 

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

basis and (CCH4)m is measured on a wet basis. 

(fH2O)m = Average moisture content of biogas during 

the measurment period, volumetric basis, 

(cubic feet water per cubic feet biogas). 

(CCH4)m = Average CH4 concentration of biogas during 

the measurement period, (volume %). 

0.0423 = Density of CH4 lb/cf at 520°R or 60°F and 1 

atm. 

520 o

R = 520 degrees Rankine. 

Tm = Temperature at which flow is measured for 

the measurement period(°R). If the flow 

rate meter automatically corrects for 

temperature replace “520° R/Tm” with “1”. 

Pm = Pressure at which flow is measured for the 

measurement period (atm). If the flow rate 

meter automatically corrects for pressure, 

replace “Pm/1” with “1”. 

0.454/1,000 = Conversion factor (metric ton/lb). 

(2) If you do not continuously monitor CH4 

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

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)(iii) of this section and calculate the 

Formatted: Subscript

Deleted: n
175

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

(i) Continuously monitor gas 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. 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)(iii) of this 

section. 

(ii) 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 once each calendar week, with at 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)(2)(i) of this 

section, is zero. 

(iii) 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 

Deleted: §98.353
176

in a location near or representative of the location of the 

gas flow meter once each calendar week, with 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 once 

each calendar week that the cumulative biogas flow measured 

as specified in §98.354(h) is greater than zero, with at 

least three days between measurements. 

(d) For each anaerobic 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) Estimate the annual mass of CH4 that is generated, 

but not recovered, using Equation II-5 of this section. 





 



  1

CE

1 4 RLCH nn (Eq. II-5) 

Formatted: Subscript

Deleted: process (such as 

anaerobic 

Deleted: )
177

Where: 

CH4Ln = Leakage at the anaerobic process n (metric tons 

CH4). 

n = Index for processes at the facility, used in 

Equation II-7.

Rn = Annual quantity of CH4 recovered from the nth 

anaerobic reactor, anaerobic lagoon, or 

anaerobic digester, as calculated in Equation 

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

CE = CH4 collection efficiency of anaerobic process n, 

as specified in Table II-2 of this subpart 

(decimal). 

(2) For each anaerobic 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. 

      4 nn4 n1_1 2_2 -1 R LCHECH -1 R n Dest Dest   fDE   fDE (Eq. II-6) 

Where: 

CH4En = Annual quantity of CH4 emitted from the process n

from which biogas is recovered (metric tons/yr).

n = Index for processes at the facility, used in 

Equation II-7.

CH4Ln = Leakage at the anaerobic process n, as calculated 

in Equation II-5 of this section (metric tons 

CH4). 

Rn = Annual quantity of CH4 recovered from the nth

anaerobic reactor or anaerobic 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 gas is 

transported off-site for destruction, use DE=1. 

Formatted: Subscript

Deleted: process (such as 

anaerobic 

Deleted: )

Deleted: rn

Deleted: anaerobic 

Deleted: n

Deleted: n

Deleted: n

Deleted: nth
178

fDest_1 = Fraction of hours the primary destruction device 

was operating (device operating hours/hours in 

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

for destruction, use fDest=1. 

DE2 = Back-up destruction device CH4 destruction 

efficiency (lesser of manufacturer’s specified 

destruction efficiency and 0.99). 

fDest_2 = Fraction of hours the back-up destruction device 

was operating (device operating hours/hours in 

the year). 

(e) Estimate the total mass of CH4 emitted from all 

anaerobic processes from which biogas is not recovered 

(calcluated in Eq. II-3) and all anaerobic processes from 

which some biogas is recovered (calculated in Equation II6) using Equation II-7 of this section. 





j

n

T ECHECH n

1

4 4 (Eq. II-7) 

Where: 

CH4ET = Annual mass CH4 emitted from all anaerobic 

processes at the facility (metric tons).

n = Index for processes at the facility.

CH4En = Annual mass of CH4 emissions from process n

(metric tons).

j = Total number of processes from which methane is 

emitted. 

§98.354 Monitoring and QA/QC requirements. 

(a) For calendar year 2011 monitoring, the facility 

may submit a request to the Administrator to use one or 

more best available monitoring methods as listed in 

Formatted: Lowered by 14 pt

Formatted: Subscript

Formatted: Subscript

Formatted: Subscript

Formatted: Subscript

Formatted: Subscript

Formatted: Subscript

Deleted: some any

Deleted: .

Deleted: 

Deleted: 

j

i

T ECHECH n

1

4  4



Deleted: N

Deleted: CH4ET = Annual 

quantity of CH4 emitted from 

the anaerobic process from 

which biogas is recovered 

(metric tons/yr).n = Index 

for processes at the 

facility.¶

¶

Deleted: the wastewater 

treatment 

Deleted: from which biogas 

is not recoverd 
179

§98.3(d)(1)(i) through (iv). The request must be submitted 

no later than [INSERT DATE 90 DAYS AFTER PUBLICATION IN THE 

FEDERAL REGISTER] and must contain the information in 

§98.3(d)(2)(ii). To obtain approval, the request must 

demonstrate to the Administrator’s satisfaction that it is 

not reasonably feasible to acquire, install, and operate a 

required piece of monitoring equipment by January 1, 2011. 

The use of best available monitoring methods will not be 

approved beyond December 31, 2011. 

(b) You must determine the concentration of organic 

material in wastewater treated anaerobically using 

analytical methods for COD or BOD5 specified in 40 CFR part 

136.3 Table 1B. For the purpose of determining 

concentrations of wastewater influent to the anaerobic 

wastewater treatment process, samples may be diluted to the 

concentration range of the approved method, but the 

calculated concentration of the undiluted wastewater must 

be used for calcuations and reporting required by this 

subpart. 

(c) You must collect samples representing wastewater 

influent to the anaerobic wastewater treatment process, 

following all preliminary and primary treatment steps 

(e.g., after grit removal, primary clarfication, oil-water 

separation, dissolved air flotation, or similar solids and 
180

oil separation processes). You must collect and analyze 

samples for COD or BOD5 concentration once each calendar 

week that the anaerobic wastewater treatment process is 

operating, with at least three days between measurements. 

You must collect a sample that represents the average COD 

or BOD5 concentration of the waste stream over a 24-hour 

sampling period. You must collect a minimum of four sample 

aliquots per 24-hour period and composite the aliquots for 

analysis. Collect a flow-proportional composite sample 

(either constant time interval between samples with sample 

volume proportional to stream flow, or constant sample 

volume with time interval between samples proportional to 

stream flow). Follow sampling procedures and techniques 

presented in Chapter 5, Sampling, of the “NPDES Compliance 

Inspection Manual,” (incorporated by reference, see §98.7)

or Section 7.1.3, Sample Collection Methods, of the “U.S. 

EPA NPDES Permit Writers’ Manual,” (incorporated by 

reference, see §98.7) . 

(d) You must measure the flowrate of wastewater 

entering anaerobic wastewater treatment process once each 

calendar week that the process is operating, with 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 

Deleted: EPA 305-X-04-001, 

July 2004

Deleted: EPA 833-B-96-003, 

December 1996
181

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. 

(1) ASME MFC–3M–2004 Measurement of Fluid Flow in 

Pipes Using Orifice, Nozzle, and Venturi (incorporated by 

reference, see §98.7). 

(2) ASME MFC–5M–1985 (Reaffirmed 1994) Measurement of 

Liquid Flow in Closed Conduits Using Transit-Time 

Ultrasonic Flowmeters (incorporated by reference, see 

§98.7). 

(3) ASME MFC–16–2007 Measurement of Liquid Flow in 

Closed Conduits with Electromagnetic Flowmeters 

(incorporated by reference, see §98.7). 

(4) ASTM D1941-91 (Reapproved 2007) Standard Test 

Method for Open Channel Flow Measurement of Water with the 

Parshall Flume, approved June 15, 2007, (incorporated by 

reference, see §98.7). 

(5) ASTM D5614-94 (Reapproved 2008) Standard Test 

Method for Open Channel Flow Measurement of Water with 

Broad-Crested Weirs, approved October 1, 2008,

(incorporated by reference, see §98.7). 

Deleted: 

Deleted: 
182

(e) All wastewater flow measurement devices must be 

calibrated prior to the first year of reporting and 

recalibrated either biennially (every 2 years) or at the 

minimum frequency specified by the manufacturer. 

Wastewater flow measurement devices must be calibrated 

using the procedures specified by the device manufacturer. 

(f) For each anaerobic process (such as anaerobic 

reactor, digester, or lagoon) from which biogas is 

recovered, you must continuously measure the gas flow rate 

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

the cumulative volume of gas recovered as specified in 

Equation II-4 of this subpart. You must also 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. As specified in §98.353(c) and paragraph (h)

of this section, you must also determine temperature, 

pressure, and moisture content as necessary to accurately 

Deleted: §98.354

Deleted: §98.354

Deleted: m

Deleted: §98.354

Deleted: §98.354
183

determine the gas 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 

temperature or pressure. You must measure moisture content 

of the recovered biogas if the gas 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 gas 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, 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. 

(1) Method 18 at 40 CFR part 60, appendix A-6. 

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

of Natural Gas by Gas Chromatography (incorporated by 

reference, see §98.7). 

(3) ASTM D1946-90 (Reapproved 2006), Standard 

Practice for Analysis of Reformed Gas by Gas Chromatography 

(incorporated by reference, see §98.7). 
184

(4) GPA Standard 2261-00, Analysis for Natural Gas 

and Similar Gaseous Mixtures by Gas Chromatography 

(incorporated by reference, see §98.7). 

(5) ASTM UOP539-97 Refinery Gas Analysis by Gas 

Chromatography (incorporated by reference, see §98.7). 

(6) As an alternative to the gas chromatography 

methods provided in paragraphs(g)(1) through (g)(5) of this 

section, you may use total gaseous organic concentration 

analyzers and calculate the CH4 concentration following the 

requirements in paragraphs (g)(6)(i) through (g)(6)(iii) of 

this section. 

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

A-7 to determine total gaseous organic concentration. You 

must calibrate the instrument with 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). 

(ii) Determine a non-methane organic carbon 

correction factor at the routine sampling location no less 

frequently than once a reporting year following the 

requirements in paragraphs (g)(6)(ii)(A) through 

(g)(6)(ii)(C) of this section. 

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

biogas with a minimum of 20 minutes between samples and 
185

determine the methane composition of the biogas using one 

of the methods specified in paragraphs (g)(1) through 

(g)(5) of this section. 

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

collected and prior to the collection of a subsequent grab 

sample, determine the total gaseous organic concentration 

of the biogas using either Method 25A or 25B at 40 CFR part 

60, appendix A-7 as specified in paragraph (g)(6)(i) of 

this section. 

(C) Determine the arithmetic average methane 

concentration and the arithmetic average total gaseous 

organic concentration of the samples analyzed according to 

paragraphs (g)(6)(ii)(A) and (g)(6)(ii)(B) of this section, 

respectively, and calculate the non-methane organic carbon 

correction factor as the ratio of the average methane 

concentration to the average total gaseous organic 

concentration. If the ratio exceeds 1, use 1 for the nonmethane organic carbon correction factor. 

(iii) Calculate the CH4 concentration as specified in 

Equation II-8 of this section. 

 CCH4 = fNMOC x CTGOC (Eq. II-8) 

Where: 

CCH4 = Methane (CH4) concentration in the 

biogas(volume %) for use in Equation II-4 of 

this subpart. 

Formatted: Tabs: 72 pt, Left + Not

at 99 pt

Deleted: 

Deleted: e
186

fNMOC = Non-methane organic carbon correction factor 

from the most recent determination of the nonmethane organic carbon correction factor as 

specified in paragraph (g)(6)(ii) of this 

section (unitless). 

CTGOC = Total gaseous organic carbon concentration

measured using Method 25A or 25B at 40 CFR 

part 60, appendix A-7 during routine 

monitoring of the biogas (volume %). 

(h) For each anaerobic process (such as an anaerobic 

reactor, 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. 

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. 

(1) ASME MFC-3M-2004, Measurement of Fluid Flow in 

Pipes Using Orifice, Nozzle, and Venturi (incorporated by 

reference, see §98.7). 

(2) ASME MFC-4M-1986 (Reaffirmed 1997), Measurement 

of Gas Flow by Turbine Meters (incorporated by reference, 

see §98.7). 

Formatted: Indent: Hanging: 99 pt

Formatted: Tabs: 108 pt, Left +

Not at 93.6 pt

Deleted: 

Deleted: 
187

(3) ASME MFC-6M-1998, Measurement of Fluid Flow in 

Pipes Using Vortex Flowmeters (incorporated by reference, 

see §98.7). 

(4) ASME MFC-7M-1987 (Reaffirmed 1992), Measurement 

of Gas Flow by Means of Critical Flow Venturi Nozzles 

(incorporated by reference, see §98.7). 

(5) ASME MFC-11M-2006 Measurement of Fluid Flow by 

Means of Coriolis Mass Flowmeters (incorporated by 

reference, see §98.7). The mass flow must be corrected to 

volumetric flow based on the measured temperature, 

pressure, and gas composition. 

(6) ASME MFC-14M-2003 Measurement of Fluid Flow Using 

Small Bore Precision Orifice Meters (incorporated by 

reference, see §98.7). 

(7) ASME MFC-18M-2001 Measurement of Fluid Flow using 

Variable Area Meters (incorporated by reference, see 

§98.7). 

(8) Method 2A or 2D at 40 CFR part 60, appendix A-1. 

(i) All temperature, pressure, and, moisture content 

monitors required as specified in paragraph (f) of this 

section must be calibrated using the procedures and 

frequencies where specified by the device manufacturer, if 

not specified use an industry accepted or industry standard 

practice. 

Deleted: §98.354
188

(j) All equipment (temperature, pressure, and 

moisture content monitors and gas flow meters and gas 

composition monitors) must be maintained as specified by 

the manufacturer. 

(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, gas flow rate, gas 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. 

§98.355 Procedures for estimating missing data

A complete record of all measured parameters used in 

the GHG emissions calculations is required. Therefore, 

whenever a quality-assured value of a required parameter is 

unavailable (e.g., if a meter malfunctions during unit 

operation or if a required sample is not taken), a 

substitute data value for the missing parameter must be 

used in the calculations, according to the following 

requirements in paragraphs (a) through (c) of this section: 
189

(a) For each missing weekly value of COD or BOD5 or 

wastewater flow entering an anaerobic wastewater treatment 

process, the substitute data value must be the arithmetic 

average of the quality-assured values of those parameters 

for the week immediately preceding and the week immediately 

following the missing data incident. 

(b) For each missing value of the CH4 content or gas 

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. 

(c) If, for a particular parameter, no qualityassured data are available prior to the missing data 

incident, the substitute data value must be the first 

quality-assured value obtained after the missing data 

period. If, for a particular parameter, the “after” value 

is not obtained by the end of the reporting year, you may 

use the last quality-assured value obtained “before” the 

missing data period for the missing data substitution. You 

must document and keep records of the procedures you use 

for all such estimates. 

§98.356 Data reporting requirements. 
190

In addition to the information required by §98.3(c), 

each annual report must contain the following information 

for each wastewater treatment system. 

(a) A description or diagram of the industrial 

wastewater treatment system, identifying the processes used 

to treat industrial wastewater and industrial wastewater 

treatment sludge. Explain 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 all anaerobic lagoons, and 

indicate whether biogas generated by each anaerobic process 

is recovered. The anaerobic processes must be identified 

as: 

(1) Anaerobic reactor. 

(2) Anaerobic deep lagoon (depth more than 2 meters). 

(3) Anaerobic shallow lagoon (depth less than 2 

meters). 

(4) Anaerobic sludge digester. 

(b) For each anaerobic wastewater treatment process 

(reactor, deep lagoon, or shallow lagoon) you must report: 

(1) Weekly average COD or BOD5 concentration of 

wastewater entering each anaerobic wastewater treatment 

process, for each week the anaerobic process was operated. 

Deleted: the 

Deleted: systemprocess

Deleted: sludges
191

(2) Volume of wastewater entering each anaerobic 

wastewater treatment process for each week the anaerobic 

process was operated. 

(3) Maximum CH4 production potential (B0) used as an 

input to Equation II-1 or II-2 of this subpart. 

(4) Methane conversion factor (MCF) used as an input 

to Equation II-1 or II-2 of this subpart. 

(5) Annual mass of CH4 generated by each anaerobic 

wastewater treatment process, calculated using Equation II1 or II-2 of this subpart. 

(c) For each anaerobic wastewater treatment process 

from which biogas is not recovered, you must report the 

annual CH4 emissions, calculated using Equation II-3 of this 

subpart. 

(d) For each anaerobic wastewater treatment process 

and anaerobic digester from which some biogas is recovered, 

you must report: 

(1) Annual quantity of CH4 recovered from the 

anaerobic process calculated using Equation II-4 of this 

subpart. 

(2) Cummulative volumentric biogas flow for each week 

that biogas is collected for destruction. 

(3) Weekly average CH4 concentration for each week 

that biogas is collected for destruction. 
192

(4) Weekly average 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. 

(5) Whether flow was measured on a wet or dry basis, 

whether CH4 concentration was measured on a wet or dry 

basis, and if required for Equation II-4 of this subpart, 

weekly average moisture content for each week at which flow 

is measured for biogas collected for destruction, or 

statement that moisture content is incorporated into 

monitoring equipment internal calculations. 

(6) Weekly average 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. 

(7) CH4 collection efficiency (CE) used in Equation 

II-5 of this subpart. 

(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 

Deleted: An indication as to 

w

Deleted: an indication as to 

Deleted: e

Deleted: An indication of w
193

destruction efficiency for the backup destruction device 

(if present). 

(9) For each anaerobic process from which some biogas 

is recovered, you must report the annual CH4 emissions, as 

calculated by Equation II-6 of this subpart. 

(e) The total mass of CH4 emitted from all anaerobic 

processes from which biogas is not recovered (calcluated in 

Equation II-3 of this supbart) and from all anaerobic 

processes from which some biogas is recovered (calculated 

in Equation II-6 of this subpart) using Equation II-7 of 

this subpart. 

§98.357 Records that must be retained. 

In addition to the information required by §98.3(g), 

you must retain the calibration records for all monitoring 

equipment, including the method or manufacturer’s 

specification used for calibration. 

§98.358 Definitions.

Except as provided below, all terms used in this 

subpart have the same meaning given in the CAA and subpart 

A of this part. 

Biogas means the combination of CO2, CH4, and other 

gases produced by the biological breakdown of organic 

matter in the absence of oxygen. 

Deleted: .

Deleted: .

Deleted: 

Deleted: ¶

Deleted: Anaerobic lagoon

means a lined or unlined 

earthen basin used for 

wastewater treatment, in 

which oxygen is absent 

throughout the depth of the 

basin, except for a shallow 

surface zone. Anaerobic 

lagoons are not equipped 

with surface aerators. 

Anaerobic lagoons are 

classified as deep (depth 

more than 2 meters) or 

shallow (depth less than 2 

meters).¶
194

Ethanol production means an operation that produces 

ethanol from the fermentation of sugar, starch, grain, or 

cellulosic biomass feedstocks, or the production of ethanol 

synthetically from petrochemical feedstocks, such as 

ethylene or other chemicals.

Food processing means an operation used to manufacture 

or process meat, poultry, fruits, and/or vegtables as 

defined under NAICS 3116 (Meat Product Manufacturing) or

NAICS 3114 (Fruit and Vegetable Preserving and Specialty 

Food Manufacturing). For information on NAICS codes, see 

http://www.census.gov/eos/www/naics/.

Industrial wastewater means water containing wastes 

from an industrial process. Industrial wastewater includes

water which comes into direct contact with or results from 

the storage, production, or use of any raw material, 

intermediate product, finished product, by-product, or 

waste product. Examples of industrial wastewater include, 

but are not limited to, paper mill white water, wastewater 

from equipment cleaning, wastewater from air pollution 

control devices, rinse water, contaminated stormwater, and 

contaminated cooling water. 

Industrial wastewater treatment sludge means solid or 

semi-solid material resulting from the treatment of 

Formatted: _Paragraph-Format-GHG

Preamble

Deleted: the 

Deleted: tion

Deleted: the

Deleted: ing

Deleted: ing of
195

industrial wastewater, including but not limited to 

biosolids, screenings, grit, scum, and settled solids.

Wastewater treatment system means the collection of 

all processes that treat or remove pollutants and 

contaminants, such as soluble organic matter, suspended 

solids, pathogenic organisms, and chemicals from wastewater 

prior to its reuse or discharge from the facility.

Table II-1 of Subpart II—Emission Factors 

Factors Default value Units 

B0 – for facilities monitoring 

COD 

0.25 Kg CH4/kg COD 

B0 – for facilities monitoring 

BOD5 

0.60 Kg CH4/kg BOD5 

MCF – anaerobic reactor 0.8 Fraction 

MCF – anaerobic deep lagoon 

(depth more than 2 m) 

0.8 Fraction 

MCF – anaerobic shallow lagoon 

(depth less than 2 m) 

0.2 Fraction 

Table II-2 of Subpart II—Collection Efficiencies of 

Anaerobic Processes 

Anaerobic Process Type Cover Type 

Methane 

Collection 

Efficiency 

Bank to bank, 

impermeable 

Covered anaerobic lagoon 0.975 

(biogas capture) 

Modular, impermeable 0.70 

Anaerobic sludge 

digester; anaerobic 

reactor 

Enclosed Vessel 0.99 

11. Add subpart TT to read as follows:

Subpart TT – Industrial Waste Landfills

Sec:

Formatted: _Dash-GHG Preamble,

Indent: Hanging: 108 pt, Bulleted +

Level: 4 + Aligned at: 126 pt + Tab

after: 144 pt + Indent at: 144 pt,

Tabs: Not at 144 pt

Formatted: Font: Bold

Formatted: Indent: First line: 0 pt

Deleted: ¶

¶

Deleted: (e.g., upflow 

anaerobic sludge blanket, 

fixed film)

Deleted: 11. 

Deleted: Part 98 is amended 

by a

Deleted: ing
196

98.460 Definition of source category.

98.461 Reporting thresholds.

98.462 GHGs to report. 

98.463 Calculating GHG emissions. 

98.464 Monitoring and QA/QC requirements.

98.465 Procedures for estimating missing data.

98.466 Data reporting requirements.

98.467 Records that must be retained.

98.468 Definitions. 

Table TT-1 of Subpart TT-Default DOC and Decay Rate Values 

for Industrial Waste Landfills

§98.460 Definition of the source category.

(a) This source category applies to industrial waste 

landfills that accepted waste on or after January 1, 1980, 

and that are located at a facility whose total landfill 

design capacity is greater than or equal to 300,000 metric 

tons. 

(b) An industrial waste landfill is a landfill other 

than a municipal solid waste landfill, a RCRA Subtitle C

hazardous waste landfill, or a TSCA hazardous waste 

landfill, in which industrial solid waste, such as RCRA 

Subtitle D wastes (non-hazardous industrial solid waste, 

defined in 40 CFR 257.2), commercial solid wastes, or 

conditionally exempt small quantity generator wastes, is 

Formatted: No underline

Formatted: ___GHG_SECTION

Formatted: Indent: Left: 0 pt, First

line: 36 pt, Numbered + Level: 1 +

Numbering Style: a, b, c, ... + Start

at: 1 + Alignment: Left + Aligned at: 

36 pt + Tab after: 108.75 pt +

Indent at: 108.75 pt, Tabs: 0 pt,

List tab + Not at 108.75 pt

Formatted: Indent: First line: 36 pt

Deleted: §

Deleted: §

Deleted: §

Deleted: §

Deleted: §

Deleted: §

Deleted: §

Deleted: §

Deleted: §

Deleted: Subpart TT—

Industrial Waste Landfills¶

Deleted: (a) 
197

placed. An industrial waste landfill includes all disposal 

areas at the facility. 

(c) This source category does not include: 

(1) Dedicated construction and demolition waste 

landfills. A dedicated construction and demolition waste 

landfill receives materials generated from the construction 

or destruction of structures such as buildings, roads, and 

bridges. 

(2) Industrial waste landfills that only receive one 

or more of the following inert waste materials: 

(i) Coal combustion residue (e.g., fly ash). 

(ii) Cement kiln dust. 

(iii) Rocks and/or soil from excavation and 

construction and similar activities. 

(iv) Glass. 

(v) Non-chemically bound sand (e.g., green foundry 

sand). 

(vii) Clay, gypsum, or pottery cull. 

(viii) Bricks, mortar, or cement. 

(ix) Furnace slag. 

(x) Materials used as refractory (e.g., alumina, 

silicon, fire clay, fire brick). 

Deleted: b

Deleted: Resource 

Conservation and Recovery 

Act (RCRA Subtitle C or 

Toxic Substances Control Act 

(TSCA) hazardous waste 

landfills.¶

(2) 

Deleted: 3
198

(xi) Plastics (e.g., polyethylene, polypropylene, 

polyethylene terephthalate, polystyrene, polyvinyl 

chloride). 

(xii) Other waste material that has a volatile solids 

concentration of 0.5 weight percent (on a dry basis) or 

less. 

(d) This source category consists of the following 

sources at industrial waste landfills: landfills, gas 

collection systems at landfills, and destruction devices 

for landfill gases (including flares). 

§98.461 Reporting threshold.

You must report GHG emissions under this subpart if 

your facility contains an industrial waste landfill meeting 

the criteria in §98.460 and the facility meets the 

requirements of §98.2(a)(2). For the purposes of 

§98.2(a)(2), the emissions from the industrial waste 

landfill are to be determined using the methane generation 

corrected for oxidation as determined using Equation TT-6 

of this subpart times the global warming potential for 

methane in Table A-1 of subpart A of this part. 

§98.462 GHGs to report.

(a) You must report CH4 generation and CH4 emissions 

from industrial waste landfills. 

Deleted: c

Deleted: section
199

(b) You must report CH4 destruction resulting from 

landfill gas collection and destruction devices, if 

present. 

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

(General Stationary Fuel Combustion Sources) the emissions 

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

associated with the landfill gas destruction device, if 

present, by following the requirements of subpart C of this 

part. 

§98.463 Calculating GHG emissions.

(a) For each industrial waste landfill subject to the 

reporting requirements of this subpart, calculate annual 

modeled CH4 generation according to the applicable 

requirements in paragraphs (a)(1) through (a)(3) of this 

section. Apply Equation TT-1 of this section for each 

waste stream disposed of in the landfill and sum the CH4

generation rates for all waste streams disposed of in the 

landfill to calculate the total annual modeled CH4

generation rate for the landfill. 

(1) Calculate annual modeled CH4 generation using 

Equation TT-1 of this section. 

  



 















   





 1 )()1(

4 12

16 T

Sx

xTk xTk

CH x x xF G DOCW MCF eeFDOC (Eq. TT-1) 

Where: 
200

GCH4 = Modeled methane generation rate in reporting 

year T (metric tons CH4). 

X = Year in which waste was disposed. 

S = Start year of calculation. Use the year 1960 

or the opening year of the landfill, whichever 

is more recent. 

T = Reporting year for which emissions are 

calculated. 

Wx = Quantity of waste disposed in the industrial 

waste landfill in year X from measurement data 

and/or other company records (metric tons, as 

received (wet weight)). 

DOCx = Degradable organic carbon for 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)]. 

DOCF = Fraction of DOC dissimilated (fraction); use 

the default value of 0.5. 

MCF = Methane correction factor (fraction); use the 

default value of 1. 

Fx = Fraction by volume of CH4 in landfill gas 

(fraction, dry basis). If you have a gas 

collection system, use the annual average CH4

concentration from measurement data for the 

given year; otherwise, use the default value 

of 0.5. 

k = Decay rate constant from Table TT-1 of this 

subpart (yr-1). Select the most applicable k 

value for the majority of the past 10 years 

(or operating life, whichever is shorter). 

(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, 

1980 or the year the landfills first accepted waste if 

after January 1, 1980, up until the most recent reporting 

year. The choice of method for determining waste 

quantities will vary according to the availability of 

Deleted: §

Deleted: 98.463(
201

historical data. Beginning in the first emissions 

monitoring year (2011 or later) and for each year 

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 monitoring 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. 

(i) Determine the quantity of waste (in metric tons 

as received, i.e., wet weight) disposed of in the landfill 

separately for each waste stream by any one or a 

combination of the following methods. 

(A) Direct mass measurements. 
202

(B) Direct volume measurements multiplied by waste 

stream density determined from periodic density measurement 

data or process knowledge. 

(C) Mass balance procedures, determining the mass of 

waste as the difference between the mass of the process 

inputs and the mass of the process outputs. 

(D) The number of loads (e.g., trucks) multiplied by 

the mass of waste per load based on the working capacity of 

the container or vehicle. 

(ii) Determine the historical disposal quantities for 

landfills using the Waste Disposal Factor approach in 

paragraphs (a)(2)(ii)(A) and (B) of this section when 

historical production or processing data are available. If 

production or processing data are available for a given 

year, you must use Equation TT-3 of this section for that 

year. Determine historical disposal quantities using the 

method specified in paragraph (a)(2)(ii)(C) of this section 

when historical production or processing data are not 

available, and for waste streams received from an off-site 

facility when historical disposal quantities cannot be 

determined using the methods specified in paragraph 

(a)(2)(i) of this section. 

(A) Determining Waste Disposal Factor: For each 

waste stream disposed of in the landfill, calculate the 
203

average waste disposal rate per unit of production or unit 

throughput using all available waste quantity data and 

corresponding production or processing rates for the 

process generating that waste or, if appropriate, the 

facility, using Equation TT-2 of this section. 





 

















  

2

1

Y

Yx x

x

PN

W WDF (Eq. TT-2) 

Where: 

WDF = Average waste disposal factor as determined for the 

first annual report required for this industrial 

waste landfill (metric tons per production unit). 

X = Year in which waste was disposed. Include only 

those years for which disposal and production data 

are both available; the years do not need to be 

sequential. 

Y1 = First year in which disposal and 

production/throughput data are both available. 

Y2 = First year for which GHG emissions from this 

industrial waste landfill must be reported. 

N = Number of years for which disposal and 

production/throughput data are both available. 

Wx = Quantity of waste placed in the industrial waste 

landfill in year X from measurement data and/or 

other company records (metric tons, as received 

(wet weight)). 

Px = Quantity of product produced or feedstock entering 

the process or facility in year X from measurement 

data and/or other company records (production 

units). You must use the same basis for all years 

in the calculation. That is, Px must be determined 

based on production (quantity of product produced) 

for all “N” years or Px must be determined based on 

throughput (quantity of feedstock) for all “N” 

years. 
204

(B) Calculate waste: For each waste stream disposed 

of in the landfill, calculate the waste disposal quantities 

for historic years in which direct waste disposal 

measurements are not available using historical production 

data and Equation TT-3 of this section. 

x   PWDFW x (Eq. TT-3) 

Where: 

X = Historic year in which waste was disposed. 

Wx = Calculated quantity of waste placed in the 

landfill in year X (metric tons). 

WDF = Average waste disposal factor from Equation TT2 of this section (metric tons per production 

unit). 

Px = Quantity of product produced or feedstock 

entering the process or facility in year X from 

measurement data and/or other company records 

(production units). You must use the same basis 

for Px (either production only or throughput 

only) as used to determine WDF in Equation TT-2 

of this section. 

(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 fixed average annual bulk waste disposal 

quantity for each year for which historic disposal quantity 

and Equation TT-4 of this section. 

   1  YrData YrOpen

LFC Wx (Eq. TT-4) 

Where: 
205

Wx = Quantity of waste placed in the landfill in year 

X (metric tons, wet basis). 

LFC = Landfill capacity or, for operating landfills, 

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). 

YrData = Year in which the landfill last received waste 

or, for operating landfills, the year prior to 

the year when waste disposal data is first 

available from company records or from Equation 

TT-3 of this section. 

YrOpen = Year 1960 or the year in which the landfill 

first received waste from company records, 

whichever is more recent. If no data are 

available for estimating YrOpen for a closed 

landfill, use 1960 as the default “YrOpen” for 

the landfill. 

(3) Degradable organic content (DOC). For any year, 

X, in Equation TT-1 of this section, use either the 

applicable default DOC values provided in Table TT-1 of 

this subpart or determine values for DOCx as specified in 

paragraphs (a)(3)(i) through (iv) of this section. When 

developing historical waste quantity data, you may use 

default DOC values from Table TT-1 of this subpart for 

certain years and determined values for DOCx for other 

years. The historical values for DOC or DOCx must be 

developed only for the first annual report required for the 

industrial waste landfill; and used for all subsequent 

annual reports (e.g., if DOC for year x=1990 was determined 

Deleted: section
206

to be 0.15 in the first reporting year, you must use 0.15 

for the 1990 DOC value for all subsequent annual reports). 

(i) For the first year in which GHG emissions from 

this industrial waste landfill must be reported, determine 

the DOCx value of each waste stream disposed of in the 

landfill no less frequently than once per quarter using the 

methods specified in §98.464(b). Calculate annual DOCx for 

each waste stream as the arithmetic average of all DOCx

values for that waste stream that were measured during the 

year. 

(ii) For subsequent years (after the first year in 

which GHG emissions from this industrial waste landfill 

must be reported), either use the DOCx of each waste stream 

calculated for the most recent reporting year for which DOC 

values were determined according to paragraph (a)(3)(i) of 

this section, or determine new DOC values for that year 

following the requirements in paragraph (a)(3)(i) of this 

section. You must determine new DOC values following the 

requirements in paragraph (a)(3)(i) of this section if 

changes in the process operations occurred during the 

previous reporting year that can reasonably be expected to 

alter the characteristics of the waste stream, such as the 

water content or volatile solids concentration. Should 

changes to the waste stream occur, you must revise the GHG 
207

Monitoring Plan as required in §98.3(g)(5)(iii) and report 

the new DOCx value according to the requirements of §98.466. 

(iii) If DOCx measurement data for each waste stream 

are available according to the methods specified in 

§98.464(b) for years prior to the first year in which GHG 

emissions from this industrial waste landfill must be 

reported, determine DOCx for each waste stream as the 

arithmetic average of all DOCx values for that waste stream 

that were measured in Year X. A single measurement value 

is acceptable for determining DOCx for years prior to the 

first reporting year. 

(iv) For historical years for which DOCx measurement 

data, determined according to the methods specified in 

§98.464(b), are not available, determine the historical 

values for DOCx using the applicable methods specified in 

paragraphs (a)(3)(iv)(A) and (B) of this section. 

Determine these historical values for DOCx only for the 

first annual report required for this industrial waste 

landfill; historical values for DOCx calculated for this 

first annual report should be used for all subsequent 

annual reports. 

(A) For years in which waste stream-specific disposal 

quantities are determined (as required in paragraphs (a)(2) 

(ii)(A) and (B) of this section), calculate the average DOC 
208

value for a given waste stream as the arithmetic average of 

all DOC measurements of that waste stream that follow the 

methods provided in §98.464(b), including any measurement 

values for years prior to the first reporting year and the 

four measurement values required in the first reporting 

year. Use the resulting waste-specific average DOC value 

for all applicable years (i.e., years in which waste 

stream-specific disposal quantities are determined) for 

which direct DOC measurement data are not available. 

(B) For years for which bulk waste disposal 

quantities are determined according to paragraphs 

(a)(2)(ii)(C) of this section, calculate the weighted 

average bulk DOC value according to the following: 

calculate the average DOC value for each waste stream as 

the arithmetic average of all DOC measurements of that 

waste stream that follows the methods provided in 

§98.464(b) (generally, this will include only the DOC 

values determined in the first year in which GHG emissions 

from this industrial waste landfill must be reported); 

calculate the average annual disposal quantity for each 

waste stream as the arithmetic average of the annual 

disposal quantities for each year in which waste streamspecific disposal quantities have been determined; and 

calculate the bulk waste DOC value using Equation TT-5 of 
209

this section. Use the bulk waste DOC value as DOCx for all 

years for which bulk waste disposal quantities are 

determined according to paragraphs (a)(2)(ii)(C) of this 

section. 

 











 N

n

nave

N

n

navenave

bulk

W

DOC W

DOC

1

,

1

, ,

 (Eq. TT-5) 

Where: 

DOCbulk = Degradable organic content value for bulk 

historical waste placed in the landfill (mass 

fraction). 

N = Number of different waste streams placed in the 

landfill 

n = Index for waste stream 

DOCave,n = Average degradable organic content value for 

waste stream “n” based on available measurement 

data (mass fraction). 

Wave,n = Average annual quantity of waste stream “n” 

placed in the landfill for years in which waste 

stream-specific disposal quantities have been 

determined (metric tons per year, wet basis). 

(b) For each landfill, calculate CH4 generation 

(adjusted for oxidation in cover materials) and CH4

emissions (taking into account any CH4 recovery, if 

applicable, and oxidation in cover materials) according to 

the applicable methods in paragraphs (b)(1) through (b)(3) 

of this section. 

(1) For each landfill, calculate CH4 generation, 

adjusted for oxidation, from the modeled CH4 (GCH4 from 
210

Equation TT-1 of this section) using Equation TT-6 of this 

section.

 CH4  OX)- (1 G MG (Eq. TT-6) 

Where: 

MG = Methane generation, adjusted for oxidation, from the 

landfill in the reporting year (metric tons CH4). 

GCH4 = Modeled methane generation rate in reporting year 

from Equation TT-1 of this section (metric tons 

CH4). 

OX = Oxidation fraction. Use the default value of 0.1 

(10 percent). 

(2) For landfills that do not have landfill gas 

collection systems operating during the reporting year, the 

CH4 emissions are equal to the CH4 generation (MG) 

calculated in Equation TT-6 of this section. 

(3) For landfills with landfill gas collection 

systems in operation during any portion of the reporting 

year, perform all of the calculations specified in 

paragraphs (b)(3)(i) through (iv) of this section. 

(i) Calculate the quantity of CH4 recovered according 

to the requirements at §98.343(b). 

(ii) Calculate CH4 emissions using the Equation HH-6 

of §98.343(c)(3)(i), except use GCH4 determined using 

Equation TT-1 of this section in Equation HH-6 of 

§98.343(c)(3)(i). 

Deleted: %

Deleted: §98.463(

Deleted: in

Deleted: of subpart HH 

(Municipal Solid Waste 

Landfills) of this part

Deleted: in

Deleted: of subpart HH 

(Municipal Solid Waste 

Landfills) of this part

Deleted: subpart HH 

(Municipal Solid Waste 

Landfills) of this part
211

(iii) Calculate CH4 generation (MG) from the quantity 

of CH4 recovered using Equation HH-7 of §98.343(c)(3)(ii). 

(iv) Calculate CH4 emissions from the quantity of CH4

recovered using Equation HH-8 of §98.343(c)(3)(ii). 

§98.464 Monitoring and QA/QC requirements. 

(a) For calendar year 2011 monitoring, the facility 

may submit a request to the Administrator to use one or 

more best available monitoring methods as listed in 

§98.3(d)(1)(i) through (iv). The request must be submitted 

no later than [INSERT DATE 90 DAYS AFTER PUBLICATION IN THE 

FEDERAL REGISTER] and must contain the information in 

§98.3(d)(2)(ii). To obtain approval, the request must 

demonstrate to the Administrator’s satisfaction that it is 

not reasonably feasible to acquire, install, and operate a 

required piece of monitoring equipment by January 1, 2011. 

The use of best available monitoring methods will not be 

approved beyond December 31, 2011. 

(b) For each waste stream for which you choose to 

determine volatile solids concentration for the purposes of 

paragraph §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. 

Deleted: in

Deleted: ) of subpart HH 

(Municipal Solid Waste 

Landfills) of this part

Deleted: in

Deleted: of subpart HH 

(Municipal Solid Waste 

Landfills) of this part

Deleted: b

Deleted: 3
212

(1) Develop and follow a sampling plan to collect a 

representative sample of each waste stream for which 

testing is elected. 

(2) Determine the percent total solids and the 

percent volatile solids of each sample following Standard 

Method 2540G “Total, Fixed, and Volatile Solids in Solid 

and Semisolid Samples” (incorporated by reference; see 

§98.7). 

(3) Calculate the volatile solids concentration 

(weight percent on a dry basis) using Equation TT-7 of this 

section. 

 100% 

Solids Total %

 % Volatile Solids VS  C  (Eq. TT-7) 

Where: 

CVS = Volatile solids concentration in the 

waste stream (weight percent, dry 

basis) 

% Volatile Solids = Percent volatile solids determined 

using Standard Method 2540G “Total, 

Fixed, and Volatile Solids in Solid 

and Semisolid Samples” (incorporated 

by reference; see §98.7). 

% Total Solids = Percent total 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-8 of this section. 

Formatted: Font: Courier New

Formatted: Font: Courier New

Formatted: Font: Courier New
213

 DOCx  %F DOC Volatile Solids x (Eq. TT-8) 

Where: 

DOCx = Degradable organic content of waste 

stream in Year X (weight fraction, wet 

basis) 

FDOC = Fraction of the volatile residue that 

is degradable organic carbon (weight 

fraction). Use a default value of 0.6. 

% 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. 

(c) 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). 

(d) 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). 

(e) 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. 

(f) The facility shall document the procedures used 

to ensure the accuracy of the estimates of disposal 

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(Municipal Solid Waste 

Landfills) of this part

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(Municipal Solid Waste 

Landfills) of this part
214

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. 

§98.465 Procedures for estimating missing data.

(a) A complete record of all measured parameters used 

in the GHG emissions calculations is required. Therefore, 

whenever a quality-assured value of a required parameter is 

unavailable (e.g., if a meter malfunctions during unit 

operation or if a required fuel sample is not taken), a 

substitute data value for the missing parameter shall be 

used in the calculations, in accordance with paragraph (b) 

of this section. 

(b) For industrial waste landfills with gas 

collection systems, follow the procedures for estimating 

missing data specified in §98.345(a) and (b). 

§98.466 Data reporting requirements. 

Deleted: §

Deleted: of subpart HH 

(Municipal Solid Waste 

Landfills) of this part.
215

In addition to the information required by §98.3(c), 

each annual report must contain the following information 

for each landfill. 

(a) Report the following general landfill 

information: 

(1) A classification of the landfill as “open” 

(actively received waste in the reporting year) or “closed” 

(no longer receiving waste). 

(2) The year in which the landfill first started 

accepting waste for disposal. 

(3) The last year the landfill accepted waste (for 

open landfills, enter the estimated year of landfill 

closure). 

(4) The capacity (in metric tons) of the landfill. 

(5) An indication of whether leachate recirculation 

is used during the reporting year and its typical frequency 

of use over the past 10 years (e.g., used several times a 

year for the past 10 years, used at least once a year for 

the past 10 years, used occasionally but not every year 

over the past 10 years, not used). 

(b) Report the following waste characterization 

information: 

(1) The number of waste steams (including “Other 

Industrial Solid Waste (not otherwise listed)”) for which 
216

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

CH4 generation. 

(2) A description of each waste stream (including the 

types of materials in each waste stream). 

(c) For each waste stream identified in paragraph (b)

of this section, report the following information: 

(1) The decay rate (k) value used in the 

calculations. 

(2) The method(s) for estimating historical waste 

disposal quantities and the range of years for which each 

method applies. 

(3) If Equation TT-2 of this subpart is used, 

provide: 

(i) The total number of years (N) for which disposal 

and production data are both available. 

(ii) The year, the waste disposal quantity and 

production quantity for each year Equation TT-2 of this 

subpart applies. 

(iii) The average waste disposal factor (WDF) 

calculated for the waste stream. 

(4) If Equation TT-4 of this subpart is used, 

provide: 

(i) The value of landfill capacity (LFC). 

(ii) YrData. 

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217

(iii) YrOpen. 

(d) For each year of landfilling starting with the 

“Start Year” (S) to the current reporting year, report the 

following information: 

(1) The quantity of waste (Wx) disposed of in the 

landfill (metric tons, wet weight) for each waste stream 

identified in paragraph (b) of this section. 

(2) The degradable organic carbon (DOCx) value (mass 

fraction) 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. 

(3) The fraction of CH4 in the landfill gas (volume 

fraction, dry basis) and an indication as to whether this 

was the default value or a value determined through 

measurement data. 

(e) Report the following information describing the 

landfill cover material: 

(1) The type of cover material used (as either 

organic cover, clay cover, sand cover, or other soil 

mixtures). 

(2) For each type of cover material used, the surface 

area (in square meters) at the start of the reporting year 

Deleted: §98.466

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Deleted: 98.466
218

for the landfill sections that contain waste and that are 

associated with the selected cover type. 

(f) The modeled annual methane generation rate for 

the reporting year (metric tons CH4) calculated using 

Equation TT-1 of this subpart. 

(g) For landfills without gas collection systems, 

provide: 

(1) The annual methane emissions (i.e., the methane 

generation, adjusted for oxidation, calculated using 

Equation TT-5 of this subpart), reported in metric tons CH4. 

(2) An indication of whether passive vents and/or 

passive flares (vents or flares that are not considered 

part of the gas collection system as defined in §98.6) are 

present at this landfill. 

(h) For landfills with gas collection systems, in 

addition to the reporting requirements in paragraphs (a) 

through (f) of this section, you must report according to 

§98.346(i). 

§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. 

§98.468 Definitions.

Deleted: , 

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(Municipal Solid Waste 

Landfills) of this part. 
219

Except as provided below, all terms used in this 

subpart have the same meaning given in the CAA and subpart 

A of this part. 

Solid waste has the meaning established by the 

Administrator pursuant to the Solid Waste Disposal Act (42 

U.S.C.A. 6901 et seq.). 

Waste stream means industrial solid waste material 

that is generated by a specific manufacturing process or 

client. For wastes generated at the facility that includes 

the industrial waste landfill, a waste stream is the 

industrial solid waste material generated by a specific 

processing unit at that facility. For industrial solid 

wastes that are received from off-site facilities, a waste 

stream can be defined as each waste shipment or group of 

waste shipments received from a single client or group of 

clients that produce industrial solid wastes with similar 

waste properties. 

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) 

Food Processing 0.22 0.06 0.12 0.18 

Pulp and Paper 0.20 0.02 0.03 0.04 

Wood and Wood Product 0.43 0.02 0.03 0.04 

Construction and Demolition 0.04 0.02 0.03 0.04 

Inert Waste [i.e., wastes 

listed in §98.460(b)(3)] 

0 0 0 0 

Other Industrial Solid Waste 

(not otherwise listed) 

0.20 0.02 0.04 0.06 

Formatted: Underline

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Deleted: ]

Deleted: ,

Deleted: for purposes of 

subpart TT of this part, 

Deleted: 6
220

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 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 

Deleted: s
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II – Industrial 

Wastewater 

Treatment 

322110,322121, 

322122,322130, 

311611,311411, 

311421,325193, 

and 324110 $1.5 16% $1.5 26% 

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For the purposes of subpart TT, Iindustrial waste 

landfill means any landfill other than a municipal solid 

waste landfill, a RCRA Subtitle C hazardous waste landfill, 

or a TSCA hazardous waste landfill, in which industrial 

solid waste, such as RCRA Subtitle D wastes (non-hazardous 

industrial solid waste, defined in 40 CFR 257.2), 

commercial solid wastes, or conditionally exempt small 

quantity generator wastes, is placed. An industrial waste 

landfill includes all disposal areas at the facility. 

Industrial wastewater means water containing wastes 

from an industrial process. Industrial wastewater includes 

water which comes into direct contact with or results from 

the storage, production, or use of any raw material, 

intermediate product, finished product, by-product, or 

waste product. Examples of industrial wastewater include, 

but are not limited to, paper mill white water, wastewater 

from equipment cleaning, wastewater from air pollution 

control devices, rinse water, contaminated stormwater, and 

contaminated cooling water. 

Industrial wastewater treatment sludge means solid or 

semi-solid material resulting from the treatment of 
industrial wastewater, including but not limited to 

biosolids, screenings, grit, scum, and settled solids. 

* * * * * 

Page 134: [3] Deleted Author 

6. Table A-3 of subpart A is amended by revising the 

entry for “(Reserved)” to read as follows: 

Table A-3 of Subpart A—Source Category List for §98.2(a)(1) 

Source Categories1 Applicable in 2010 and Future Years 

* * * * * * * 

Additional Source Categories1 Applicable in 2011 and Future 

Years

Underground coal mines that are subject to quarterly or more 

frequent sampling by MSHA of ventilation systems (subpart FF) 

1 Source categories are defined in each applicable subpart. 

Page 136: [4] Deleted Author 

Table A-4 of subpart A is amended by revising the 

entry for “(Reserved)” to read as follows: 

Table A-4 of Subpart A—Source Category List for §98.2(a)(2) 

Source Categories1 Applicable in 2010 and Future Years 

* * * * * * * 

Additional Source Categories1 Applicable in 2011 and Future 

Years

Magnesium production (subpart T) 

Industrial wastewater treatment (subpart II) 

Industrial waste landfills (subpart TT) 

1 Source categories are defined in each applicable subpart. 

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Average moisture content of the methane emitted during the 

measurement period at that monitoring 

point, 

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estimated or measured 

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and the continuous monitoring equipment is properly 

functioning, or the measured concentration 

when weekly sampling is performed 

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 for the days in the week when the degasification system at 

that monitoring point is in operation and 

the continuous monitoring equipment is 

properly functioning, or the measured 

value when weekly sampling is performed 

(°R) 

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 for the days in the week 

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 when the degasification system at that monitoring point is 

in operation and the continuous monitoring 

equipment is properly functioning, or the 

measured value when weekly sampling is 

performed. 

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week are calculated based on the frequency of 

measurement.