Monday, 

July 12, 2010 

Part II 

Environmental 

Protection Agency 

40 CFR Part 98 

Mandatory Reporting of Greenhouse 

Gases From Magnesium Production, 

Underground Coal Mines, Industrial 

Wastewater Treatment, and Industrial 

Waste Landfills; Final Rule 

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39736 Federal Register / Vol. 75, No. 132 / Monday, July 12, 2010 / Rules and Regulations 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 98 

[EPA–HQ–OAR–2008–0508; FRL–9171–1] 

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. 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 

September 10, 2010. The incorporation 

by reference of certain publications 

listed in the rule is approved by the 

Director of the Federal Register as of 

September 10, 2010. 

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 http://www.regulations.gov Web 

site. Although listed in the index, some 

information is not publicly available, 

e.g., confidential business information 

(CBI) or other information whose 

disclosure is restricted by statute. 

Certain other material, such as 

copyrighted material, is not placed on 

the Internet and will be publicly 

available only in hard copy form. 

Publicly available docket materials are 

available either electronically through 

http://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 INFORMATION CONTACT: 

Carole Cook, Climate Change Division, 

Office of Atmospheric Programs (MC– 

6207J), Environmental Protection 

Agency, 1200 Pennsylvania Ave., NW., 

Washington, DC 20460; telephone 

number: (202) 343–9263; fax number: 

(202) 343–2342; e-mail address: 

GHGReportingRule@epa.gov. For 

technical information and 

implementation materials, please go to 

the Web site http://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 

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

331492 Secondary magnesium processing plants. 

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

212112 Underground bituminous coal mining operations. 

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

322110 Pulp mills. 

322121 Paper mills. 

322122 Newsprint mills. 

322130 Paperboard mills. 

311611 Meat processing facilities. 

311411 Frozen fruit, juice, and vegetable manufacturing facilities. 

311421 Fruit and vegetable canning facilities. 

221320 Sewage treatment facilities. 

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

322121 Paper mills. 

322122 Newsprint mills. 

322130 Paperboard mills. 

311611 Meat processing facilities. 

311411 Frozen fruit, juice, and vegetable manufacturing facilities. 

311421 Fruit and vegetable canning facilities. 

325193 Ethanol manufacturing facilities. 

324110 Petroleum refineries. 

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 as amended by this 

action. If you have questions regarding 

the applicability of this action to a 

particular facility, consult the person 

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Federal Register / Vol. 75, No. 132 / Monday, July 12, 2010 / Rules and Regulations 39737 

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. 

Industrial Waste Landfills a ................................. Subpart C: General Stationary Fuel Combustion. 

Subpart Y: Petroleum Refineries. 

Subpart AA: Pulp and Paper Manufacturing. 

Subpart II: Industrial Wastewater Treatment. 

Industrial Wastewater Treatment ........................ Subpart C: General Stationary Fuel Combustion. 

Subpart Y: Petroleum Refineries. 

Subpart AA: Pulp and Paper Manufacturing. 

Subpart TT: Industrial Waste Landfills. 

aThe 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 

September 10, 2010. Under CAA section 

307(d)(7)(B), only an objection to this 

final rule that was raised with 

reasonable specificity during the period 

for public comment can be raised during 

judicial review. This section also 

provides a mechanism for us to convene 

a proceeding for reconsideration, ‘‘[i]f 

the person raising an objection can 

demonstrate to EPA that it was 

impracticable to raise such objection 

within [the period for public comment] 

or if the grounds for such objection 

arose after the period for public 

comment (but within the time specified 

for judicial review) and if such objection 

is of central relevance to the outcome of 

this rule.’’ Any person seeking to make 

such a demonstration to us should 

submit a Petition for Reconsideration to 

the Office of the Administrator, 

Environmental Protection Agency, 

Room 3000, Ariel Rios Building, 1200 

Pennsylvania Ave., NW., Washington, 

DC 20004, with a copy to the person 

listed in the preceding FOR FURTHER

INFORMATION CONTACT section, and the 

Associate General Counsel for the Air 

and Radiation Law Office, Office of 

General Counsel (Mail Code 2344A), 

Environmental Protection Agency, 1200 

Pennsylvania Ave., NW., Washington, 

DC 20004. Note, under CAA section 

307(b)(2), the requirements established 

by this final rule may not be challenged 

separately in any civil or criminal 

proceedings brought by EPA to enforce 

these requirements. 

Acronyms and Abbreviations. The 

following acronyms and abbreviations 

are used in this document. 

ASME American Society of Mechanical 

Engineers 

ASTM American Society for Testing and 

Materials 

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 

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 Wastewater Treatment (40 

CFR part 98, subpart II) 

III. Other Source Categories Proposed in 2009 

A. Overview 

B. Ethanol Production 

C. Food Processing 

D. Suppliers of Coal 

IV. Economic Impacts of the Rule 

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39738 Federal Register / Vol. 75, No. 132 / Monday, July 12, 2010 / Rules and Regulations 

1The 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. 

2Consolidated Appropriations Act, 2008, Public 

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

reaffirmed interest in a GHG reporting rule, and 

provided additional funding, in the 2009 and 2010 

Appropriations Acts (Consolidated Appropriations 

Act, 2009, Pub. L. 110–329, 122 Stat. 3574–3716 

and Consolidated Appropriations Act, 2010, Pub. L. 

111–117, 123 Stat. 3034–3408). 

3The 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). 

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 Coodination with Indian Tribal 

Governments 

G. Executive Order 13045: Protection of 

Children from Environmental Health 

Risks and Safety Risks 

H. Executive Order 13211: Actions that 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer and 

Advancement Act 

J. Executive Order 12898: Federal Actions 

to Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

K. Congressional Review Act 

I. Background 

A. Organization of This Preamble 

This preamble 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 

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 landfills,1

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 economy. 

This rulemaking was initiated by EPA in 

response to the fiscal year 2008 

Consolidated Appropriations Act 

(Appropriations Act).2 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 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 time.3

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 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 

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Federal Register / Vol. 75, No. 132 / Monday, July 12, 2010 / Rules and Regulations 39739 

responded to in the preamble to the 

October 2009 Final Rule (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 

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 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 

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 

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 rule 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 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 

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39740 Federal Register / Vol. 75, No. 132 / Monday, July 12, 2010 / Rules and Regulations 

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 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 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 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 

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 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. The request must be 

submitted by October 12, 2010 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 

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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. 

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 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. 

– 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) 

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 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, samples of CH4 released from 

the ventilation system(s), using MSHA 

procedures, have these samples 

analyzed for CH4 composition, and use 

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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). 

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 

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 

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 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 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 

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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. 

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 

facility-level 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 

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 emissions-based 

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, 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 

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 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. 

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, 

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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 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 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 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 

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 

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 

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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 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 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. 

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, 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 

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 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 

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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 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 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 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 backcalculate 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, 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 

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. 

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: 

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• 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. 

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. 

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. 

• 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 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 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 

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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 

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 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., ‘‘non-chemically’’ 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. 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 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 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 site-specific 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 

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Federal Register / Vol. 75, No. 132 / Monday, July 12, 2010 / Rules and Regulations 39749 

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 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; nonchemically 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. 

• 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 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 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 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 streamspecific DOC values following the 

methods provided in the final rule. In 

addition to default DOC and k values for 

selected industries, we have also 

included in Table TT–1 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. 

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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 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 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 HHLandfills, 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 onsite 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 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, 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 

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 onsite 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, 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 

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4http://www.epa.gov/climatechange/emissions/ 

usinventoryreport.html. 

5http://www.eia.doe.gov/fuelcoal.html. 

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 

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 emissions from coal 

consumption, EPA seeks information on 

the magnitude and location of facilitylevel 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. Coal-fired 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 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 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 and 

Sinks,4 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.5 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 

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6Although 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. 

emissions 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 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 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 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.’’).6

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’’). 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 

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. 

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 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 

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Federal Register / Vol. 75, No. 132 / Monday, July 12, 2010 / Rules and Regulations 39753 

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). 

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. 

• 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. One-time 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 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 

Subpart 2007 NAICS 

First year Subsequent years 

Millions 

2006$ Share Millions 2006$ Share 

Subpart T—Magnesium 

Production.

331419 and 331492 ....................................................... $0.1 2% $0.1 2% 

Subpart FF—Underground 

Coal Mines.

212112 ............................................................................ 4.0 57% 2.8 51% 

Subpart 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 (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. 

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

[First year, 2006$] 

2007 NAICS NAICS description Subpart 

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 

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 

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). 

TABLE 5—ESTIMATED COST-TO-SALES RATIOS BY INDUSTRY AND ENTERPRISE SIZE (FIRST YEAR, 2006$) a

2007 

NAICS 

NAICS description Subpart 

SBA size 

standard 

(effective 

August 22, 

2008) 

Average 

cost per 

entity 

($/entity) 

All enterprises 

Owned by enterprises with: 

1 to 20 

employees b

20 to 99 

employees 

100 to 499 

employees 

500 to 749 

employees 

750 to 999 

employees 

1,000 to 

1,499 

employees 

331419 .... Primary Smelting and Refining of Nonferrous Metal 

(except Copper and Aluminum).

T .......... 750 employees.$10,520 0.1% 0.9% 0.2% 0.1% D D D 

331492 .... Secondary 

Smelting, Refining, and 

Alloying of 

Nonferrous 

Metal (except 

Copper and 

Aluminum).

T .......... 750 employees.$10,520 0.1% 0.7% 0.1% 0.2% D D D 

212112 .... Bituminous Coal 

Underground 

Mining.

FF ........ 500 employees.$34,717 0.2% 3.0% 3.4% 0.2% D D D 

322110 .... Pulp Mills .......... TT ........ 750 employees.$5,583 <0.1% 0.4% D D D D D 

322121 .... Paper (except 

Newsprint) 

Mills.

TT ........ 750 employees.$5,583 <0.1% D 0.1% D D D D 

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TABLE 5—ESTIMATED COST-TO-SALES RATIOS BY INDUSTRY AND ENTERPRISE SIZE (FIRST YEAR, 2006$) a—Continued 

2007 

NAICS 

NAICS description Subpart 

SBA size 

standard 

(effective 

August 22, 

2008) 

Average 

cost per 

entity 

($/entity) 

All enterprises 

Owned by enterprises with: 

1 to 20 

employees b

20 to 99 

employees 

100 to 499 

employees 

500 to 749 

employees 

750 to 999 

employees 

1,000 to 

1,499 

employees 

322122 .... Newsprint Mills TT ........ 750 employees.$5,583 <0.1% D D D NA D D 

322130 .... Paperboard 

Mills.

TT ........ 750 employees.$5,583 <0.1% 1.1% 0.1% <0.1% NA D D 

311611 .... Animal (except 

Poultry) 

Slaughtering.

TT ........ 500 employees.$5,583 <0.1% 0.5% 0.1% <0.1% D D <0.1% 

311411 .... Frozen Fruit, 

Juice, and 

Vegetable 

Manufacturing.

TT ........ 500 employees.$5,583 <0.1% 0.3% 0.1% <0.1% <0.1% D <0.1% 

311421 .... Fruit and Vegetable Canning.TT ........ 500 employees.$5,583 <0.1% 0.4% 0.1% <0.1% <0.1% <0.1% <0.1% 

322110 .... Pulp Mills .......... II ........... 750 employees.$4,235 <0.1% 0.3% D D D D D 

322121 .... Paper (except 

Newsprint) 

Mills.

II ........... 750 employees.$4,235 <0.1% D <0.1% D D D D 

322122 .... Newsprint Mills II ........... 750 employees.$4,235 <0.1% D D D NA D D 

322130 .... Paperboard 

Mills.

II ........... 750 employees.$4,235 <0.1% 0.8% <0.1% <0.1% NA D D 

311611 .... Animal (except 

Poultry) 

Slaughtering.

II ........... 500 employees.$3,963 <0.1% 0.4% <0.1% <0.1% D D <0.1% 

311411 .... Frozen Fruit, 

Juice, and 

Vegetable 

Manufacturing.

II ........... 500 employees.$3,963 <0.1% 0.2% <0.1% <0.1% <0.1% D <0.1% 

311421 .... Fruit and Vegetable Canning.II ........... 500 employees.$3,963 <0.1% 0.3% <0.1% <0.1% <0.1% <0.1% <0.1% 

325193 .... Ethyl Alcohol 

Manufacturing.

II ........... 1,000 employees.$5,140 <0.1% D D D D NA D 

324110 .... Petroleum Refineries.II ........... 1,500 employees c.

$3,963 <0.1% 0.1% <0.1% <0.1% <0.1% D D 

331419 .... Primary Smelting and Refining of Nonferrous Metal 

(except Copper and Aluminum).

T .......... 750 employees.$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). aThe Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that were specified under common ownership or control. The enterprise and the establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise—the enterprise employment and annual payroll are summed from the associated establishments. Enterprise size designations are determined by the summed employment of 

all associated establishments. 

Since the SBA’s business size definitions (http://www.sba.gov/size) apply to an establishment’s ultimate parent company, we assume in this analysis that the enterprise definition above is consistent with the concept of ultimate parent company that is typically used for Small Business Regulatory Enforcement Fairness Act 

(SBREFA) screening analyses. bExcludes 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. 

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 

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 

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39756 Federal Register / Vol. 75, No. 132 / Monday, July 12, 2010 / Rules and Regulations 

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 

Under Executive Order (EO) 12866 

(58 FR 51735, October 4, 1993) this 

action is a ‘‘significant action’’ because it 

raises novel legal or policy issues 

arising out of legal mandates, the 

President’s priorities, or the principles 

set forth in the EO. Accordingly, EPA 

submitted this action to the Office of 

Management and Budget (OMB) for 

review under EO 12866 and any 

changes made in response to OMB 

recommendations have been 

documented in the docket for this 

action. In addition, EPA prepared an 

analysis of the potential costs and 

benefits associated with this action. 

This analysis is contained in the EIA, 

‘‘Economic Impact Analysis for the 

Mandatory Reporting of Greenhouse Gas 

Emissions: Subparts: T, FF, II, and TT’’. 

A copy of the analysis is available in the 

docket for this action (Docket Item EPA– 

HQ–OAR–2008–0508–2313) and the 

analysis is briefly summarized here. 

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). 

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 economy-wide data on facilitylevel GHG emissions. Accurate and 

timely information on GHG emissions is 

essential for informing future climate 

change policy decisions. Through data 

collected under this rule, EPA will gain 

a better understanding of the relative 

emissions of specific industries, and the 

distribution of emissions from 

individual facilities within those 

industries. The facility-specific data will 

also improve our understanding of the 

factors that influence GHG emission 

rates and actions that facilities are 

already taking to reduce emissions. 

Additionally, EPA will be able to track 

the trend of emissions from industries 

and facilities within industries over 

time, particularly in response to policies 

and potential regulations. The data 

collected by this rule will improve 

EPA’s ability to formulate climate 

change policy options and to assess 

which industries would be affected, and 

how these industries would be affected 

by the options. 

This information collection is 

mandatory and will be carried out under 

CAA 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 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 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 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 

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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. 

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 be 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 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), Public 

Law 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 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 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 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 likely 

to have any adverse effects on energy 

supply, distribution, or use. 

I. National Technology Transfer and 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (NTTAA), Public Law 104– 

113, 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 

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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 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 

Low-Income Populations 

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 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 

September 10, 2010. 

List of Subjects in 40 CFR Part 98 

Environmental protection, 

Administrative practice and procedure, 

Greenhouse gases, Incorporation by 

reference, Suppliers, Reporting and 

recordkeeping requirements. 

Dated: June 28, 2010. 

Lisa P. Jackson, 

Administrator. 

■ For the reasons stated in the preamble, 

title 40, chapter I, of the Code of Federal 

Regulations is amended as follows: 

PART 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? 

(a) * * * 

(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 of this part), miscellaneous 

use of carbonates (subpart U of this 

part), 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 of this part), 

miscellaneous use of carbonates 

(subpart U of this part), 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. 

* * * * * 

(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 

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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 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. 

* * * * * 

(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 calibrations shall be 

performed at the frequency specified in 

each applicable subpart. 

* * * * * 

■ 5. Section 98.6 is amended by revising 

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 with 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 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 

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 

is actually placed in the landfill from an 

individual or representative type of 

container (such as a tank, truck, or rolloff 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. Adding paragraphs (e)(43) and 

(e)(44). 

■ d. Revising paragraph (f)(2). 

■ 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), 

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§ 98.254(c), § 98.324(e), § 98.344(c), 

§ 98.354(d), § 98.354(h), and § 98.364(e). 

(2) ASME MFC–4M–1986 (Reaffirmed 

1997) Measurement of Gas Flow by 

Turbine Meters, IBR approved for 

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

§ 98.324(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 § 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 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), P.O. Box 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, http://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 

Protection Agency, 1200 Pennsylvania 

Avenue, NW., Washington, DC 20460, 

(202) 272–0167, http://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). 

■ 7. Add Tables A–3, A–4, and A–5 to 

Subpart A to read as follows: 

TABLE A–3 TO 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. 

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TABLE A–3 TO SUBPART A—SOURCE CATEGORY LIST FOR § 98.2(a)(1)—Continued 

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 Categories a 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). 

aSource categories are defined in each applicable subpart. 

TABLE A–4 TO SUBPART A—SOURCE CATEGORY LIST FOR § 98.2(a)(2) 

Source Categories a 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 Categories a Applicable in 2011 and Future Years 

Magnesium production (subpart T). 

Industrial wastewater treatment (subpart II). 

Industrial waste landfills (subpart TT). 

aSource categories are defined in each applicable subpart. 

TABLE A–5 TO SUBPART A—SUPPLIER CATEGORY LIST FOR § 98.2(a)(4) 

Supplier Categories a 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. 

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 Applicable a in 2011 and Future Years 

(Reserved) 

aSuppliers are defined in each applicable subpart. 

■ 8. Add subpart T to read as follows: 

Subpart T—Magnesium Production 

Sec. 

98.200 Definition of source category. 

98.201 Reporting threshold. 

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. 

98.208 Definitions. 

Subpart T—Magnesium Production 

§ 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. 

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(3) The fluorinated ketone, FK 5–1– 

12. 

(4) Carbon dioxide (CO2). 

(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: 

E I I AD x Bx Ex x x = − +− ( ) ∗ , , 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. 

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: 

E Q GHG p

p

n

= ∗ ∑ 0 001 . (Eq. T-2) =1

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 individual 

container shall be estimated by using 

Equation T–3 of this section: 

QMM p BE = − (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 

October 12, 2010 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) 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 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 are met; however, you remain 

responsible for the accuracy of these 

masses or weights under this subpart. 


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(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: 

R C Mg GHG GHG = ∗ / . 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. 

(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. 

(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: 

Subpart FF—Underground Coal Mines 

Sec. 

98.320 Definition of the source category. 

98.321 Reporting threshold. 

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. 

(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. 

(a) You must report CH4 liberated 

from ventilation and degasification 

systems. 


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39764 Federal Register / Vol. 75, No. 132 / Monday, July 12, 2010 / Rules and Regulations 

(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. 

(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 FF–1 

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. 

CH n V C

100% atm 4V =∗ ∗ ∗ ∗ ∗ ∗ ∗ ∗ ⎛

⎝

MCF 0 0423 520

1

1 440 0 454

1 000 . , .

,

o

R

T

P ⎜ ⎞

⎠

⎟ (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). 

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 °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 

ventilation systems (CH4VTotal) as the 

sum of the CH4 from all ventilation 

monitoring points in the mine, as 

follows: 

CH4 4 VTotal

1

= ( ) =

∑ CH V i i

m

(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. 

CH V C

100% atm 4D i

i = ∗∗ ∗ ∗ ∗∗∗ MCF R

T

P i

o

i 0 0423 520

1

1 440 0 454

1 000 . , .

,

⎛

⎝

⎜ ⎞

⎠

⎟ =

∑i

n

1

(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 

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 °R = 520 degrees Rankine. 


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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 

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: 

CH4 4 DTotal D

11

= ( ) ==

∑∑ CH i, j

j

w

i

m

(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 Equation FF–5 of this 

section. You must measure CH4 content 

and flow rate according to the 

provisions in § 98.324. 

CH CH DE (Eq. FF-5) 4Destroyed 4 = ×

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. 

CH (Eq. FF-6) 4Destroyed Total = ( ) =

∑ CH Destroyed d i

d

4

1

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 offsite transport. 

(2) [Reserved] 

(d) You must calculate the quarterly 

measured net CH4 emissions to the 

atmosphere using Equation FF–7 of this 

section. 

CH emitted (net) CH CH CH (Eq 4 =+− 4VTotal 4DTotal 4destroyedTotal . 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. 

CO (Eq. FF-8) 2 = ∗ CH4Destroyedonsite 4416/

Where: 

CO2 = Total quarterly CO2 emissions from 

CH4 destruction (metric tons). 

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 FF–5 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 

October 12, 2010 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, 


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39766 Federal Register / Vol. 75, No. 132 / Monday, July 12, 2010 / Rules and Regulations 

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 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 

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). 

(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 (e)(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 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). 

(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. 

(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 

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Federal Register / Vol. 75, No. 132 / Monday, July 12, 2010 / Rules and Regulations 39767 

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). 

(e) Quarterly CO2 emissions from onsite 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). 

(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 backup 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 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 threshold. 

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 to Subpart II–Emission Factors 

Table II–2 to Subpart II–Collection 

Efficiencies of Anaerobic Processes 

Subpart II—Industrial Wastewater 

Treatment 

§ 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 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: 

(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. 

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39768 Federal Register / Vol. 75, No. 132 / Monday, July 12, 2010 / Rules and Regulations 

§ 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. 

(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. 

CH G Flow COD B MCF 4 n w w o

w

= ∗ ∗∗ ∗ [ ] =

∑ 0 001 1

52

. (. Eq II-1)

Where: 

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 the 

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. 

CH G Flow BOD B MCF 4 n w w o

w

= ∗ ∗∗ ∗ ⎡

⎣ ⎤⎦ =

∑ 5

1

52

0 001 2 , . (. Eq II- )

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). 

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. 

CH (Eq. II-3) 4E CH G n n = 4

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). 

(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. 

R (V)

C

100% atm n m

CH4 = ∗( ) ∗ ( ) K ∗ ∗ ∗∗ R

T

P MC m

m

o

m

m 0 0423 520

1

0 45 . ( )

( ) . 4

1 1 000 ,

⎡

⎣

⎢

⎢

⎤

⎦

⎥ = ⎥ ∑

m

M

(Eq. II-4)


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Federal Register / Vol. 75, No. 132 / Monday, July 12, 2010 / Rules and Regulations 39769 

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. 

(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 °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 quantity of 

CH4 recovered for destruction using 

Equation II–4 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 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. 

CH L R 4n n =∗ − ⎛

⎝

⎜ ⎞

⎠

⎟ 1 1

CE (Eq. II-5)

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. 

CH E CH L R 44 1 n n Rn 2 1 1 n D = +−∗ ( ) ( ) DE f est D 1 2 +−∗ ( ) ( ) DE f est (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. 

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 

(calculated in Eq. II–3) and all anaerobic 

processes from which some biogas is 

recovered (calculated in Equation II–6) 

using Equation II–7 of this section. 

CH E CH E 4 T n

n

j

=

=

∑ 4

1

(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). 


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39770 Federal Register / Vol. 75, No. 132 / Monday, July 12, 2010 / Rules and Regulations 

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 § 98.3(d)(1)(i) through (iv). The 

request must be submitted no later than 

October 12, 2010 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 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 

calculations 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 clarification, oil-water 

separation, dissolved air flotation, or 

similar solids and 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 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). 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 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). 

(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 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). 

(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 

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Federal Register / Vol. 75, No. 132 / Monday, July 12, 2010 / Rules and Regulations 39771 

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 

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 non-methane organic carbon 

correction factor. 

(iii) Calculate the CH4 concentration 

as specified in Equation II–8 of this 

section. 

C f CH NMOC 4 = ×C (Eq. II-8) TGOC

Where: 

CCH4 = Methane (CH4) concentration in the 

biogas (volume %) for use in Equation 

II–4 of this subpart. 

fNMOC = Non-methane organic carbon 

correction factor from the most recent 

determination of the non-methane 

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). 

(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. 

(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: 

(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 

quality-assured 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 qualityassured 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. 

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). 


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(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. 

(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 II–1 

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) Cumulative volumetric 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. 

(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 calculations. 

(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 

calculations. 

(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 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 (calculated 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. 

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 vegetables 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 

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 TO 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. 

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TABLE II–2 TO SUBPART II—COLLECTION EFFICIENCIES OF ANAEROBIC PROCESSES

Anaerobic process type Cover type 

Methane collection efficiency 

Covered anaerobic lagoon (biogas capture) ................................................................ Bank to bank, impermeable ...................... 0.975 

Modular, impermeable .............................. 0.70 

Anaerobic sludge digester; anaerobic reactor ............................................................. Enclosed Vessel ....................................... 0.99 

■ 11. Add and reserve subparts QQ, RR, 

and SS. 

■ 12. Add subpart TT to read as follows: 

Subpart TT—Industrial Waste Landfills 

Sec. 

98.460 Definition of the source category. 

98.461 Reporting threshold. 

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 to Subpart TT–Default DOC and 

Decay Rate Values for Industrial Waste 

Landfills 

Subpart TT—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 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). 

(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. 

(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. 

G W DOC MCF DOC e e CH x x F

kT x kT x

x

4 = × × × ××× − ( ) ⎧

⎨

⎩

⎫

⎬

⎭

− −− − − Fx

16

12

( ) () 1

=

−

∑

⎡

⎣

⎢ ⎤

⎦

⎥ S

T 1

(Eq. TT-1)

Where: 

GCH4 = Modeled methane generation rate in 

reporting year T (metric tons CH4). 

X = Year in which waste was disposed. 

S = Start year of calculation. Use the year 

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 


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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 

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. 

(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 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. 

WDF W

N P

x

x

Y

= ×

⎧

⎨

⎩

⎫

⎬

⎭

⎡

⎣

⎢

⎢

⎤

⎦

⎥ = ⎥ ∑x Y1

2

( . 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. 

(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. 

W WDF P x 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 TT–2 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. 

W LFC

YrData YrOpen+ x = ( ) − (Eq. TT-4) 1

Where: 

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. 


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(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 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 

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 streamspecific disposal quantities are 

determined (as required in paragraphs 

(a)(2) (ii)(A) and (B) of this section), 

calculate the average DOC 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 wastespecific 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 stream-specific disposal 

quantities have been determined; and 

calculate the bulk waste DOC value 

using Equation TT–5 of 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. 

DOC

DOC W

W

bulk

ave,n ave,n

n

N

ave,n

n

N =

( ) ×

=

=

∑

∑

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 Equation 

TT–1 of this section) using Equation 

TT–6 of this section. 

MG G OX Eq = ×− CH4 ( ) ( . TT-6) 1

Where: 

MG = Methane generation, adjusted for 

oxidation, from the landfill in the 

reporting year (metric tons CH4). 

GCH4 = Modeled methane generation rate in 

reporting year from Equation 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. 


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(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). 

(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 

October 12, 2010 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. 

(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. 

CVS = ×

% % Volatile Solids

% Total Solids

100 (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. 

DOC F x DOC = ×% Volatile Solids (Eq. TT-8) x

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 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. 

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 


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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 

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. 

(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 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. 

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 TO SUBPART TT—DEFAULT DOC AND DECAY RATE VALUES FOR INDUSTRIAL WASTE LANDFILLS

Industry/Waste Type 

DOC 

(weight fraction, 

wet basis) 

k 

[dry climatea] 

(yr¥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 

aThe applicable climate classification is determined based on the annual rainfall plus the recirculated leachate application rate. Recirculated 

leachate application rate (in inches/year) is the total volume of leachate recirculated 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. 

[FR Doc. 2010–16488 Filed 7–9–10; 8:45 am] 

BILLING CODE 6560–50–P 

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