6560.50 

ENVIRONMENTAL PROTECTION AGENCY 

40 CFR Part 98 

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

RIN 2060-AQ03 

Mandatory Reporting of Greenhouse Gases from Magnesium 

Production, Underground Coal Mines, Industrial Wastewater 

Treatment, and Industrial Waste Landfills 

AGENCY: Environmental Protection Agency (EPA). 

ACTION: Final Rule. 

SUMMARY: EPA is promulgating a regulation to require 

monitoring and reporting of greenhouse gas emissions from 

magnesium production, underground coal mines, industrial 

wastewater treatment, and industrial waste landfills. This 

action adds these four source categories to the list of 

source categories already required to report greenhouse gas 

emissions under the Mandatory Reporting program. This 

action requires monitoring and reporting of greenhouse 

gases for these source categories only for sources with 

carbon dioxide equivalent emissions above certain threshold 

levels as described in this regulation. This action does 

not require control of greenhouse gases. 

DATES: The final rule is effective on [INSERT THE 

DATE 60 DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER]. 

The incorporation by reference of certain publications 
2

listed in the rule is approved by the Director of Federal 

Register as of [INSERT THE DATE 60 DAYS AFTER PUBLICATION 

IN THE FEDERAL REGISTER]. 

ADDRESSES: EPA established a single docket under 

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

the previous action promulgated October 30, 2009 (74 FR 

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

www.regulations.gov 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 

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

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

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

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

through Friday, excluding legal holidays. The telephone 

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

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

FOR FURTHER GENERAL INFORMATION CONTACT: Carole Cook, 

Climate Change Division, Office of Atmospheric Programs 
3

(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 

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

You may also contact the Greenhouse Gas Reporting Rule 

Hotline at telephone number: (877) 444-1188; or e-mail: 

ghgmrr@epa.gov. 

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. 
4

Category NAICS Examples of affected facilities 

331492 Secondary magnesium processing 

plants. 

Underground Coal 

Mines 

212113 Underground anthracite coal mining 

operations. 

212112 Underground bituminous coal mining 

operations. 

562212 Solid waste landfills. 

322110 Pulp mills. 

322121 Paper mills. 

322122 Newsprint mills. 

322130 Paperboard mills. 

311611 Meat processing facilities. 

311411 Frozen fruit, juice, and vegetable 

manufacturing facilities. 

311421 Fruit and vegetable canning 

facilities. 

Industrial Waste 

Landfills 

221320 Sewage treatment facilities. 

322110 Pulp mills. 

322121 Paper mills. 

322122 Newsprint mills. 

322130 Paperboard mills. 

311611 Meat processing facilities. 

311411 Frozen fruit, juice, and vegetable 

manufacturing facilities. 

311421 Fruit and vegetable canning 

facilities. 

325193 Ethanol manufacturing facilities. 

Wastewater 

Treatment 

324110 Petroleum refineries. 

Table 1 of this preamble is not intended to be 

exhaustive, but rather provides a guide for readers 

regarding facilities likely to be affected by this action. 

Although Table 1 of this preamble lists the types of 

facilities that EPA is now aware could be potentially 

affected by the reporting requirements, other types of 

facilities not listed in the table could also be subject to 

reporting requirements. To determine whether you are 

affected by this action, you should carefully examine the 
5

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 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. 
6

Source category 

(and main applicable 

subpart) 

Other Subparts in 40 CFR part 98 

recommended for review to determine 

applicability 

Underground Coal Mines 

Subpart C: General Stationary Fuel 

Combustion. 

Subpart C: General Stationary Fuel 

Combustion. 

Subpart Y: Petroleum Refineries. 

Subpart AA: Pulp and Paper 

Manufacturing. 

Industrial Waste 

Landfills1

Subpart II: Industrial Wastewater 

Treatment 

Subpart C: General Stationary Fuel 

Combustion. 

Subpart Y: Petroleum Refineries. 

Subpart AA: Pulp and Paper 

Manufacturing. 

Industrial Wastewater 

Treatment 

Subpart TT: Industrial Waste 

Landfills 

Judicial Review. 

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

this final rule is available only by filing a petition for 

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

Columbia Circuit by [INSERT THE DATE 60 DAYS AFTER 

PUBLICATION IN THE FEDERAL REGISTER]. Under CAA section 

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

raised with reasonable specificity during the period for 

public comment can be raised during judicial review. This 

section also provides a mechanism for us to convene a 

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

 

1 The industrial landfills source category was proposed with Municipal 

Landfills under 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 Landfills (promulgated October 30, 

2009 (74 FR 56374) and subpart TT for industrial landfills. 
7

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 
8

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 

EO Executive Order 

EPA U.S. Environmental Protection Agency 

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

GHG greenhouse gas 

GWP global warming potential 

HCFC-22 chlorodifluoromethane (or CHClF2) 

HFC-23 trifluoromethane (or CHF3) 

HFCs hydrofluorocarbons 

HFEs hydrofluorinated ethers 

ICR information collection request 

kg kilograms 

mmBtu/hr millions British thermal units per hour 

MSHA Mine Safety and Health Administration 

MSW municipal solid waste 

N2O nitrous oxide 

NAICS North American Industry Classification System 

NF3 nitrogen trifluoride 

NPDES National Pollution Discharge Elimination System 

NTTAA National Technology Transfer and Advancement Act 

of 1995 

OMB Office of Management and Budget 

PFCs perfluorocarbons 

QA quality assurance 

QA/QC quality assurance/quality control 
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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 

SF6 sulfur hexafluoride 

SOP standard operating procedure 

TSCA Toxic Substances Control Act 

TSD technical support document 

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 Waste Landfills, and 

Industrial Wastewater Treatment. 

A. Overview 

B. Summary of Changes to the General Provisions of the 

Mandatory GHG Reporting Rule 

C. Magnesium Production 

D. Underground Coal Mines 

E. Industrial Wastewater Treatment 

F. Industrial Waste Landfills 

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 

A. How were compliance costs estimated? 
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B. What are the costs of the rule? 

C. What are the economic impacts of the rule? 

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

businesses? 

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

V. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory Planning and Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act (RFA) 

D. Unfunded Mandates Reform Act (UMRA) 

E. Executive Order 13132: Federalism 

F. Executive Order 13175: Consultation and Coordination 

with Indian Tribal Governments 

G. Executive Order 13045: Protection of Children from 

Environmental Health Risks and Safety Risks 

H. Executive Order 13211: Actions that Significantly 

Affect Energy Supply, Distribution, or Use 

I. National Technology Transfer and Advancement Act 

J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and LowIncome Populations 

K. Congressional Review Act 

I. Background 

A. Organization of This Preamble

This preamble consists of five sections. The first 

section provides a brief history of the Mandatory 

Greenhouse Gas (GHG) Reporting Rule 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 98, 

subpart A and outlines the specific requirements for the 
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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

Today’s action finalizes monitoring and reporting 

requirements for the following four source categories: 

magnesium production, underground coal mines, industrial 
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waste landfills2, and industrial wastewater treatment. With 

today’s action EPA has decided not to include ethanol 

production and food processing as distinct subparts. 

Lastly, EPA has decided 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).3 This Act authorized funding for EPA 

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

reporting of greenhouse gas emissions above appropriate 

thresholds in all sectors of the economy of the United 

States.” An accompanying joint explanatory statement 

directed EPA to "use its existing authority under the Clean 

Air Act" to develop a mandatory GHG reporting rule. 

EPA proposed the Mandatory GHG Reporting Rule on April 

10, 2009 (74 FR 16448) and held two public hearings in 

 

2 The industrial landfills source category was proposed with Municipal 

Landfills under 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 Landfills (promulgated October 30, 

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

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

1844, 2128. Congress reaffirmed interest in a GHG reporting rule, and 

provided additional funding, in the 2009 and 2010 Appropriations Acts 

(Consolidated Appropriations Act, 2009, Public Law 110-329, 122 Stat. 

3574-3716 and Consolidated Appropriations Act, 2010, Public Law 111-

117, 123 Stat. 3034-3408). 
13

April 2009. The public comment period ended on June 9, 

2009. The final Mandatory GHG Reporting Rule (40 CFR part 

98) was signed by the EPA Administrator on September 22, 

2009 and published in the Federal Register on October 30, 

2009 (74 FR 56260). The Mandatory GHG Reporting 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 11 source categories 

that were not finalized in the October 30, 2009 action. 

This action includes monitoring and reporting requirements 

for four of the 11 source categories that were proposed but 

not finalized in the October 30, 2009 action, and amends 

the general provisions for the Mandatory GHG Reporting Rule 

(40 CFR part 98, subpart A) to incorporate T (Magnesium 

Production), FF (Underground Coal Mines), II (Industrial 

Wastewater Treatment), and TT (Industrial Waste Landfills). 

This action also provides EPA’s final decision not to 

include ethanol production and food processing as distinct 

subparts in the Mandatory GHG Reporting Rule, as well as 

the final decision not to include suppliers of coal in the 

Mandatory GHG Reporting rule at this time4. 

 

4 The remaining four source categories included in the April 2009 

proposal but not included here are being reproposed in Proposed 

Mandatory Reporting of Greenhouse Gases: Petroleum and Natural Gas 
14

During the comment period, EPA received a number of 

detailed comments on the proposed Mandatory GHG Reporting 

Rule, 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 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 the Mandatory Greenhouse Gas Reporting Rule 

because these facilities will already be covered under the 

rule due to their combustion, industrial wastewater, and 

industrial landfill emissions. Moreover, EPA has also 

decided to not include coal suppliers in the Mandatory 

Greenhouse Gas Reporting Rule because the vast majority of 

 

Systems(75 FR 18608) and Proposed Mandatory Reporting of Greenhouse 

Gases: Additional Sources of Fluorinate GHGs (75 FR 18652) 
15

emissions from combustion of coal in the United States is 

already covered by the rule through reporting by direct 

emitters. Further explanation of these decisions is 

provided in more detail in the discussions of the proposed 

individual source categories in Section III of this 

preamble. 

Summaries of comments on other aspects of the 

reporting rule, such as the verification approach and 

selection of source categories, are included and were 

responded to in the preamble to the final Mandatory GHG 

Reporting 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 subparts T, FF, TT, and II under the 

existing CAA authorities provided in CAA sections 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 
16

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 

greenhouse gases. 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 

facilities 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 

section 103(g) of the CAA regarding improvements in sector 

based nonregulatory strategies and technologies for 

preventing or reducing air pollutants. 
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II. Reporting Requirements for Magnesium Production, 

Underground Coal Mines, Industrial Wastewater Treatment, 

and Industrial Waste landfills. 

A. Overview

The Mandatory GHG Reporting Rule 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 greenhouse 

gases, 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 
18

under the Mandatory GHG Reporting Rule, including those 

subject to the reporting requirements in subparts T, FF, 

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

data. 

B. Summary of Changes to the General Provisions of the 

Mandatory GHG Reporting Rule 

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. None of 

the amendments change the general provisions applicable to 

those subparts already incorporated into 40 CFR part 98. 

Changes to Applicability. Facilities containing 

magnesium production, industrial waste landfills, and/or 

industrial wastewater treatment facilities, are subject to 

the Mandatory GHG Reporting Rule 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 
19

amending Table A-4 in subpart A of 40 CFR part 98 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 

the Mandatory GHG Reporting Rule regardless of the actual 

facility emissions. In today’s action, we are amending 

Table A-3 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 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 subparts T, FF, 

II, and TT for the reporting year 2010 or report it in 

2011. 
20

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 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 
21

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 

subparts TT and II, are already required to report under 

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 final Mandatory GHG Reporting Rule 

published in October 2009. 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. 
22

Best Available Monitoring Methods. In the final 

Mandatory GHG Reporting 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 [INSERT DATE 90 DAYS AFTER 

PUBLICATION IN THE FEDERAL REGISTER] and must contain the 

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

information regarding the use of BAMM is included in the 

Monitoring and QA/QC Requirements section of each subpart 

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

use of BAMM for these source categories will not be 

approved beyond December 31, 2011. 

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 
23

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 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, 

TT, and II and to clarify the meaning of certain terms for 

purposes of 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 (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. 
24

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 tons of gas per year resulting 

from their use as cover gases or carrier gases in magnesium 

production or processing: 

Χ SF6

Χ HFC-134a 

Χ FK 5-1-12 

Χ CO2

Χ 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 
25

of cover gases and carrier gases using one of three 

methods: 

Χ 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. 

Χ Monitor the changes in the mass of individual 

containers as the gases are used. 

Χ 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 
26

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. Fugitive Methane Emissions from Underground Coal Mines 

(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 Mine Safety and 

Health Administration (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. 
27

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: 

Χ Quarterly CH4 liberation from ventilation and 

degasification systems 

Χ 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). 
28

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 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 
29

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 
30

used to calculate GHG emissions. A list of specific data 

to be reported for this source category is contained in 40 

CFR 98.326, 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 data to be reported for 

this source category is contained in 40 CFR 98.327, 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 

subpart FF can be found below or in “Mandatory Greenhouse 

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

Subpart FF: Underground Coal Mines.” 

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

mine ventilation systems was added. 

Χ 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. 

Χ 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. 
31

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 removed 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, mines 

with CH4 collection systems, since they are generally 
32

monitoring the amount of CH4 collected in these systems, 

provide an effective internal validation method by which 

they can assess their 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 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 
33

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 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 
34

measure fugitive CH4 emissions from surface mines at this 

time. Measuring fugitive emissions at specific locations 

would not adequately capture the emissions from the entire 

mine, would be expensive and resource-intensive, and 

difficult for mine operators to implement on a periodic 

basis. EPA may reconsider including surface mines in this 

rule should additional information become available 

demonstrating that monitoring is feasible. 

Comment: One commenter expressed concern that even 

the most accurate instrumentation will have accuracy 

difficulties based upon varying conditions, calling into 

question the accuracy of the measurements. Because of this, 

they recommended that degasification wells be exempt from 

the rule. 

 Response: EPA does not agree with the commenter that 

CH4 degasification wells should be exempt. While the 

factors mentioned in the comment may indeed influence the 

accuracy of measurement of CH4 from degasification wells, 

EPA considered this issue when including this source 

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

it provides valuable information for characterizing CH4 

emissions from underground coal mining options. This 

information is also of value to mine owners, because those 
35

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 emissionsbased thresholds, and determined that reporting should be 

required for those coal mines for which CH4 emissions from 

the ventilation system are sampled quarterly by MSHA. MSHA 

conducts quarterly testing of CH4 concentration and flow at 

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

This threshold was selected because subjecting underground 

mine operators to a new emissions-based threshold would be 

unnecessarily burdensome and perhaps confusing, since these 

mines are already subject to MSHA regulations and therefore 

would be able to comply with this rule without having to 

separately determine applicability. 
36

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. 
37

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. EPA determined that coal mining operations do not 
38

generally vary much from quarter to quarter for mine 

ventilation systems. 

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 
39

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, 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 
40

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 found in docket EPA-OAR2008-0508. 

E. Industrial Wastewater Treatment (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 sludges 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 
41

and wastewater treatment sludges 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: 

Χ The amount of CH4 generated, recovered, and emitted 

from treatment of industrial wastewater using 

anaerobic lagoons or anaerobic reactors; 

Χ The amount of CH4 recovered and emitted from anaerobic 

sludge digesters; and 

Χ 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 
42

digester apparatus. Further, operators of anaerobic sludge 

digesters are required 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: 

Χ Volume of wastewater sent to an anaerobic treatment 

process; 

Χ Average concentration of chemical oxygen demand (COD) 

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

entering an anaerobic treatment process; 

Χ Maximum CH4 producing potential of wastewater (0.25 for 

COD, 0.6 for BOD5); and 

Χ 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: 
43

Χ Cumulative volumetric flow of biogas for the 

monitoring period; 

Χ Average CH4 content of the biogas; and 

Χ 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: 

Χ Mass of CH4 recovered; 

Χ Collection efficiency for the anaerobic process, based 

on the type of anaerobic process; 

Χ Destruction efficiency of the biogas collection and 

combustion system; and 

Χ 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 
44

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.” 

Χ 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 sludges 

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). 

Χ 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. 

Χ Because petrochemical facilities are not known to 

employ anaerobic wastewater treatment, this sector has 

been removed from the final version of the rule. 

Χ 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 5-day biochemical 
45

oxygen demand (BOD5) as an alternative to measuring 

chemical oxygen demand (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 

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 
46

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 sludges. 

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 Subpart II, EPA has removed 

emission factors for aerobic processes used to treat 

industrial wastewater from Table II-1 of rule 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 the GHG Reporting Rule, as was the 

case in the proposed rule. EPA continues to exclude 

municipal wastewater treatment plants from the final rule, 

and has retitled 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 the GHG Reporting Rule. Most 
47

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 the GHG Reporting Rule; 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. Since the purpose of this rule is to collect 

direct GHG emissions data and not data from sources simply 

because they emit VOCs that can convert to CO2 once in the 

atmosphere, this requirement was removed. Please see 
48

“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 
49

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. 

Requiring facilities in the included industry sectors 

to report wastewater treatment emissions will allow each 

reporting facility to estimate their emissions accurately. 

While anaerobic wastewater treatment may in some cases 

result in only a small portion of a facility’s emissions, 

excluding this source from the reporting requirements will 

provide a less than accurate portrayal of the true 

emissions from each facility. 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. 

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 
50

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 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 §98.354 to clarify how facilities 

might meet the stated requirement for the collection of 
51

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 wellmixed 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 flow-weighted 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
52

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 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 
53

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 back-calculate the influent (untreated) 

load. This approach would require EPA to describe all 
54

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 
55

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 (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 
56

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: 

Χ Annual CH4 generation and CH4 emissions from the 

industrial waste landfill. 

Χ 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: 

Χ Measured or estimated values of historic annual waste 

disposal quantities; and 

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

organic carbon 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 
57

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 
58

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.” 

Χ 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 
59

total landfill design capacity of less than 300,000 

metric tons, and an exemption for landfills that only 

receive inert waste materials. 

Χ 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. 

Χ Additional model defaults for industrial waste are 

included in the final rule and additional methods are 

provided to estimate degradable organic carbon content 

of industrial solid waste streams. 

Χ For landfills with landfill gas recovery, all of the 

changes that were incorporated in the final subpart HH 

rule (allowing weekly sampling and direct flame 

ionization methods) are also included in this final 

rule for industrial waste landfills (by crossreferencing the final requirements in subpart HH). 

For additional details regarding the changes in the 

landfill gas recovery monitoring requirements, see the 

final preamble for the 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 
60

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 
61

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: 

Χ Exempt inactive landfills, from which emissions are 

small. 

Χ 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,. 

Χ Exempt on-site industrial waste landfills that have 

been closed under RCRA because they have little or no 

potential for air emissions and would create an 

unnecessary compliance burden. 

Response: We agree that there will be negligible 

methane emissions from landfills that contain only inert 

waste materials because they do not have organic materials 

that would emit methane after being placed in an industrial 

landfill. Therefore, we investigated alternative 

applicability requirements for industrial waste landfills 

to target the reporting requirements to landfills that are 

expected to produce significant amounts of methane. Based 

on an analysis of various options (see the “Technical 

Support Document for Industrial Waste Landfills” in Docket 

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

industrial waste landfill reporting requirements landfills 

that are used exclusively to dispose of inert materials or 
62

“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. 

Χ 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 
63

exclusion applies to any waste material at any 

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

bullets). 

Χ Landfills at petroleum refineries. We did not exclude 

landfills at petroleum refineries because we 

anticipate that refinery waste materials will contain 

significant amounts of degradable organic carbon 

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

exclude these wastes because we anticipate that the 

waste may contain significant amounts of degradable 

organic carbon (scraps of sugar canes). 

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

because resin sand generally contains organic chemical 

binders that can degrade in landfills and generate 

methane emissions. 

Χ 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 
64

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. 
65

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 
66

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 sitespecific basis, and these methods generally do not 

necessarily require significant changes to the landfill. 

For example, clean-up efforts focused on groundwater 

remediation may pump and treat the contaminated groundwater 

and recirculate the treated groundwater to the landfill. 

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

leach any other remaining contaminants from the landfill, 

but this technique will enhance rather than limit methane 

generation from the landfill. Consequently, landfills that 

are subsequently listed by States as “hazardous” for the 

purposes of CERCLA (Superfund) or similar state programs 

are not excluded from the industrial waste landfill source 

category. 

In summary, the final industrial waste landfill rule 

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

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

industrial waste landfills that have a total design 
67

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; 

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

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

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

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

that has a volatile solids concentration of 0.5 weight 

percent (on a dry basis) or less. 

Method for Calculating GHG Emissions

Comment: Several commenters suggested that EPA not 

require direct measurement of the waste entering the 

landfill. One commenter noted that there are materials 

that are conveyed and sluiced to solid waste disposal areas 

that could not be monitored across truck scales. The 

commenters suggested a number of alternatives to direct 

mass measurements, which include: 

Χ Allow the use of company records. 

Χ Allow the use of any measurement method specified in 

an applicable permit or any reasonable estimation 

method that is adequately documented. 
68

Χ Allow the use of typical waste disposal records and 

other testing on parameters such as density and 

chemical analysis. 

Χ 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. 

Χ 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. 
69

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 degradable 

organic carbon (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 
70

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. 
71

Comment: Several commenters requested that more 

information be provided in the rule to calculate greenhouse 

gas 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 
72

material disposed of in the industrial waste landfill. For 

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

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

default values for DOC or the use of measured, waste 

stream-specific DOC values following the methods provided 

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

for selected industries, we have also included in Table TT1 of rule subpart TT default DOC and k value for “other 

solid industrial waste (not otherwise specified).” As 

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

Costs 

Comment: One commenter stated that EPA presents its 

summary cost analysis data in the preamble with further 

details in the accompanying regulatory impact analysis 

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

data for each of the subparts separately but fails to 

consider the overall burden per facility of complying with 

multiple subparts, including landfills, as is the case with 

most industrial facilities. 

Response: EPA agrees that the costs facing facilities 

in some sectors include not only process costs but 

additional costs associated with other subparts in the 

rule. While these costs are presented individually in the 

costs tables, where these conditions apply the costs are 
73

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 Proposed Source Categories 

A. Overview

With this action EPA has made the final decision not 

to include Ethanol Production or Food Processing as 

distinct subparts in the Mandatory Greenhouse Gas Reporting 

Rule. This decision does not change the applicability 

requirements under other subparts of this rule that may 

affects 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 the Mandatory Greenhouse Gas 

Reporting Rule 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 the Mandatory GHG Reporting Rule. EPA 

has determined that it is not necessary to include subpart 
74

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 HH-Landfills, 

and subpart II-Wastewater Treatment. 

EPA received many comments on this subpart covering 

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

found in the comment response document for ethanol 

production in “Mandatory Greenhouse Gas Reporting Rule: 

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

Production” 

Subpart J was originally included as a distinct 

subpart to clearly indicate that these facilities must 

aggregate emissions from all source categories when 
75

determining whether emissions exceeded the applicable 

threshold. As structured, the proposed subpart 

specifically required that emissions from stationary 

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

treatment were to be aggregated in determining the 

reporting threshold and reporting emissions from these 

facilities. 

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

that 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 

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 
76

definition of ethanol production facility is included in 40 

CFR 98.6. 

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

necessary to include 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 the Mandatory Greenhouse Gas Reporting 

Rule. EPA had determined that it is not necessary to 

include subpart M in order to cover food processing 

facilities in the final rule. 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. 
77

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” 

Subpart M was originally included as a distinct 

subpart to clearly indicate that these facilities must 

aggregate emissions from all source categories when 

determining whether emissions exceeded the applicable 

threshold.. As structured, the proposed subpart 

specifically required that emissions from stationary 

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

treatment were to be aggregated in determining the 

reporting threshold and reporting emissions from these 

facilities. 
78

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 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 

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 98.6. 

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

necessary to include 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 
79

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 require 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 the Mandatory Greenhouse 

Gas Reporting Rule at this time. 

EPA’s rationale for not requiring reporting from coal 

suppliers at this time is because (i) the overlap in 

reporting upstream and downstream suppliers is almost 100% 

indicating that double-reporting does not provide more 

complete information to EPA, unlike with subparts MM and 

NN, and (ii) anticipated uses of data on the emissions from 

the combustion of coal, in the near-term, can be met with 
80

high accuracy by the downstream reporting provisions in the 

final MRR. 

The overall purpose of the MRR 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 facility-level emissions 

across the economy as well as overall emissions at the 

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

accuracy and at principally the same coverage through 

existing reporting requirements for direct emitters under 

the Mandatory GHG Reporting Rule (MRR), primarily through 

reporting under subparts C, D, and Q. For example, the 

existing subpart D, which accounts for approximately 94% of 

emissions from the use of coal, builds on rigorous 

monitoring requirements of Part 75. Coal-fired electricity 

generating units subject to Part 75 typically use 

continuous emissions monitoring equipment that measures 

actual carbon dioxide emissions hourly. Furthermore, the 

MRR requires rigorous Tier 3 and Tier 4 reporting at 

industrial facilities with large units combusting coal and 

other solid fuels. Reporting requirements under Subpart C 

(general stationary combustion and Subpart D(electricity 

generation) will allow EPA to obtain more than 99 percent 
81

of total CO2 emissions from coal combustion through existing 

reporting provisions of the MRR. The proposed subpart KK 

procedures would have covered approximately 100% of coal 

supplied to the economy and resulting downstream CO2 

combustion emissions. The difference in combustion 

coverage of less than one percent is estimated to come from 

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

in heating. 

Furthermore, the near-term needs of the MRR can be met 

with higher accuracy through existing reporting 

requirements for direct emitters. Under the proposed 

subpart KK, approximately fifty 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 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. While EPA believes that the 

proposal had a pragmatic approach to balancing accuracy and 

cost, it is clear that the upstream data under proposed 

subpart KK would not have been as accurate as the more 

rigorously monitored data reported by direct emitters. In 
82

sum, including proposed subpart KK in the MRR 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 subpart KK from the MRR, EPA notes that 

changing the subpart KK proposal to require more rigorous 

reporting on par with downstream requirements would have 

raised the costs and burden of proposed 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 subpart KK requirements 

by sampling and testing for coal content mnthly and that 48 

percent (659 mines) would meet requirements by using 

default factors. To raise the reporting rigor, EPA would 

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

sample and test coal content daily. 

EPA can also make use of existing data sources outside 

of the MRR, such as the Inventory of U.S. Greenhouse Gas 

Emissions and Sinks5, other data reported by coal-fired 

electricity generating units to EPA’s Acid Rain Program, 

and the Energy Information Administration’s (EIA) detailed 

 

5 http://www.epa.gov/climatechange/emissions/usinventoryreport.html
83

coal production, consumption, imports and exports data.6 The 

national greenhouse gas 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. 

EPA views double-reporting for emissions from other 

fossil fuels EPA as most useful 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 

 

6 http://www.eia.doe.gov/fuelcoal.html
84

the commercial and residential sectors (e.g., HFCs emitted 

from home air conditioning units or CO2 emissions from 

individual motor vehicles). To account for these direct 

emissions would require reporting by hundreds or thousands 

of small facilities. To avoid this impact, the rule does 

not include all of those emitters, but instead requires 

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 Regulatory Impact 

Analysis of the final rule, reports by downstream emitters 

would 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 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 (which in turn assists in 

analyses such as Best Available Control Technology (BACT) 

or National Environmental Policy Act (NEPA)). EPA notes 

that it did propose that facilities affected by subpart KK 
85

would report information on their customers, making this 

use of the data very difficult. For other upstream 

categories, EPA did not propose and does not require 

detailed information about specific customers. If EPA 

determines that 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 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 the Mandatory GHG Reporting Rule 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 economic impact analysis 
86

(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 

economic impact analysis (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: 
87

Χ Monitoring (private): staff hours to operate and maintain 

emissions monitoring systems. 

Χ Recordkeeping and Reporting (private): staff hours to 

gather and process available data and reporting it to EPA 

through electronic systems. 

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

quality assure, analyze, and release reports. 

Staff activities and associated labor costs will 

potentially vary over time. Thus, cost estimates are 

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

subsequent reporting. Wage rates to monetize staff time 

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

Equipment Costs. Equipment costs include both the 

initial purchase price and any facility modification that 

may be required. Based on expert judgment, the engineering 

costs analyses annualized capital equipment costs with 

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

recovery period at a rate of 7 percent. 

B. What are the costs of the rule?

1. Summary of Costs 

The total annualized costs incurred under the 

reporting rule would be approximately $7.0 million in the 

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

This includes a public sector burden estimate of $0.3 
88

million for program implementation and verification 

activities. Table 3 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 

First Year 

Subsequent 

Years 

Subpart 

2007 

NAICS 

Millions 

2006$ Share 

Millions 

2006$ Share 

Subpart T – 

Magnesium 

Production 

331419 and 

331492 $0.1 2% $0.1 2% 

Subpart FFFugitive Methane 

Emissions from 

Underground Coal 

Mines 212112 $4.0 57% $2.8 51% 

Subpart HH – 

Industrial Waste 

Landfills 

322110,322121, 

322122,322130, 

311611,311411, 

and 311421 $1.1 16% $0.8 15% 

Subpart II – 

Industrial 

Wastewater 

Treatment 

322110,322121, 

322122,322130, 

311611,311411, 

311421,325193, 

and 324110 $1.5 21% $1.5 26% 

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 
89

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. 

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

Entities (First Year, 2006$) 

Average Cost 

Per Entity 

($/entity) 

All 

Enterprises 

2007 

NAICS 

NAICS Description Sub-part 

331419 

Primary Smelting and Refining of 

Nonferrous Metal (except Copper and 

Aluminum) T $10,520 0.1% 
90

331492 

Secondary Smelting, Refining, and 

Alloying of Nonferrous Metal (except 

Copper and Aluminum) T $10,520 0.1% 

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

322110 Pulp Mills HH $5,583 <0.1% 

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

322122 Newsprint Mills HH $5,583 <0.1% 

322130 Paperboard Mills HH $5,583 <0.1% 

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

311411 

Frozen Fruit, Juice, and Vegetable 

Manufacturing HH $5,583 

<0.1% 

311421 Fruit and Vegetable Canning HH $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 
91

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). 
92

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

Enterprise Size (First Year,2006$)a

Owned by Enterprises with: 

2007 

NAICS 

NAICS 

Description 

Subpart

SBA Size 

Standard 

(effective 

August 22, 

2008) 

Average 

Cost 

Per 

Entity 

($/ 

entity) 

All 

Enter

-

prise

s 

1 to 20 

Employeesb

20 to 99 

Employees 

100 to 

499 

Employees 

500 to 

749 

Employees 

750 to 

999 

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

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

212112

Bituminous 

Coal 

Underground 

Mining F

500 

employees $37,717 0.2% 3.0% 3.4% 0.2% D

322110 Pulp Mills HH

750 

employees $5,583 <0.1% 0.4% D D D

322121

Paper 

(except 

Newsprint) 

Mills HH

750 

employees $5,583 <0.1% D 0.1% D D

322122

Newsprint 

Mills HH

750 

employees $5,583 <0.1% D D D NA

322130

Paperboard 

Mills HH

750 

employees $5,583 <0.1% 1.1% 0.1% <0.1% NA

311611

Animal 

(except 

Poultry) 

Slaughterin

g HH

500 

employees $5,583 <0.1% 0.5% 0.1% <0.1% D

311411

Frozen 

Fruit, 

Juice, and 

Vegetable 

Manufacturi

ng HH

500 

employees $5,583 <0.1% 0.3% 0.1% <0.1% <0.1%

311421

Fruit and 

Vegetable 

Canning HH

500 

employees $5,583 <0.1% 0.4% 0.1% <0.1% <0.1% <0.1%

322110 Pulp Mills II

750 

employees $4,235 <0.1% 0.3% D D D
93

Owned by Enterprises with: 

2007 

NAICS 

NAICS 

Description 

Subpart

SBA Size 

Standard 

(effective 

August 22, 

2008) 

Average 

Cost 

Per 

Entity 

($/ 

entity) 

All 

Enter

-

prise

s 

1 to 20 

Employeesb

20 to 99 

Employees 

100 to 

499 

Employees 

500 to 

749 

Employees 

750 to 

999 

Employees

322121

Paper 

(except 

Newsprint) 

Mills II

750 

employees $4,235 <0.1% D <0.1% D D

322122

Newsprint 

Mills II

750 

employees $4,235 <0.1% D D D NA

322130

Paperboard 

Mills II

750 

employees $4,235 <0.1% 0.8% <0.1% <0.1% NA

311611

Animal 

(except 

Poultry) 

Slaughterin

g II

500 

employees $3,963 <0.1% 0.4% <0.1% <0.1% D

311411

Frozen 

Fruit, 

Juice, and 

Vegetable 

Manufacturi

ng II

500 

employees $3,963 <0.1% 0.2% <0.1% <0.1% <0.1%

311421

Fruit and 

Vegetable 

Canning II

500 

employees $3,963 <0.1% 0.3% <0.1% <0.1% <0.1% <0.1%

325193

Ethyl 

Alcohol 

Manufacturi

ng II

1000 

employees $5,140 <0.1% D D D D

324110

Petroleum 

Refineries II

1500 

employeesx $3,963 <0.1% 0.1% <0.1% <0.1% <0.1%

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

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

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

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

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

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

a

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

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

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

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

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

determined by the summed employment of all associated establishments. 

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

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

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

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

analyses. 
94

b

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

These entities only operated for a fraction of the year. 

c

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

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

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

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

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

successful bidder from either crude oil or bona fide feedstocks. 

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

EPA examined the potential benefits of the GHG 

Reporting Rule. EPA’s previous analysis of the GHG 

reporting rule 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. 
95

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 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 
96

facilities to understand better their relative standing 

within their industry. 

V. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory Planning and Review

This action is not a "significant regulatory action" 

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

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

under the Executive Order. EPA’s cost analysis, presented 

in Section 4 of the Economic Impact Analysis (EIA), 

estimates the total annualized cost of the rule will be 

approximately $7.0 million (in 2006$) during the first year 

of the program and $5.5 million in subsequent years 

(including $0.3 million of programmatic costs to the 

Agency). In addition, EPA prepared an analysis of the 

potential costs associated with this action. This analysis 

is contained in the Economic Impact Analysis (EIA), 

“Economic Impact Analysis for the Mandatory Reporting of 

Greenhouse Gas Emissions: Subparts: T, FF, HHa, and II” 

(EPA-HQ-OAR-2008-0508). A copy of the analysis is 

available in the docket for this action 

B. Paperwork Reduction Act

The information collection requirements in this rule 

have been submitted for approval to the Office of 

Management and Budget (OMB) under the Paperwork Reduction 
97

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

requirements are not enforceable until OMB approves them. 

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

timely information on GHG emissions is essential for 

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 
98

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 Economic 

Impact Analysis (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 
99

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 
100

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 within several employment 

categories. The average entity costs used to compute the 
101

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% of 

sales in all firm size categories. For one NAICS (322130 

Paperboard Mills), the costs exceed 1% of sales for the 1-

20 employee size category; for another NAICS (212112 

Bituminous Coal Underground Mining), the costs exceed 1% of 

sales for the 1-20 and 20-100 employee size category. 

Previous Regulatory Impact Analysis for the Mandatory 

Reporting of Greenhouse Gas Emissions (EPA-HQ-OAR-2008-

0508) illustrated that pulp and paper industry enterprises 

with less than 20 employees were unlikely to be covered by 

the rule. For mining facilities, EPA’s initial review of 

facility data suggests that mines owned by enterprises with 

less than 100 employees would also unlikely to be covered 

by the rule. 

After considering the economic impacts of today’s 

final rule on small entities, I therefore certify that this 
102

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), P.L. 104-4, establishes requirements for federal 

agencies to assess the effects of their regulatory actions 

on state, local, and tribal governments and the private 

sector. Under Section 202 of the UMRA, EPA generally must 
103

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 $7.0 million in the first year, and $5.5 

million per year in subsequent years. Thus, this final rule 

is not subject to the requirements of sections 202 or 205 

of UMRA. 

This final rule is also not subject to the 

requirements of section 203 of UMRA because it contains no 

regulatory requirements that might significantly or 

uniquely affect small governments. 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 
104

national government and the States, or on the distribution 

of power and responsibilities among the various levels of 

government, as specified in Executive Order 13132. 

Entities affected by these final subparts are 

facilities that directly emit greenhouses gases. These 

final subparts do not apply to governmental entities unless 

the government entity owns a facility that directly emits 

greenhouse gases above threshold levels such as a landfill 

or large 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 Executive Order 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 Mandatory GHG Reporting 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 Executive Order 13175 (65 FR 67249, November 
105

9, 2000). This regulation applies directly to facilities 

that directly emit greenhouse gases. Facilities expected 

to be affected by these final subparts are not expected to 

be owned by Tribal governments. Thus, Executive Order 

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 Mandatory GHG Reporting Rule, 

which included these subparts being finalized today. See 

Section IX of the preamble to the proposed Mandatory GHG 

Reporting 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
106

This action is not a “significant energy action” as 

defined in Executive Order 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 greenhouses gases 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 

Section 12(d) of the National Technology Transfer and 

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

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

consensus standards in its regulatory activities unless to 

do so would be inconsistent with applicable law or 

otherwise impractical. Voluntary consensus standards are 

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

methods, sampling procedures, and business practices) that 

are developed or adopted by voluntary consensus standards 

bodies. NTTAA directs EPA to provide Congress, through 
107

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 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 two of 

these methods have already been incorporated by reference 

in the final Mandatory GHG Reporting 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 
108

reference into the final Mandatory GHG Reporting Rule and 

are available as specified in 40 CFR 98.7. 

By incorporating voluntary consensus standards into 

the subparts, EPA is both meeting the requirements of the 

NTTAA and presenting multiple options and flexibility for 

measuring GHG emissions. 

J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and LowIncome Populations

Executive Order (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 
109

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 [INSERT THE 

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

Underground Coal Mines, Industrial Wastewater Treatment, 

and Industrial Waste Landfills – Final Rule 

Page 110 of 204 

List of Subjects 40 CFR Part 2

Environmental protection, Administrative practice and 

procedure, Reporting and recordkeeping requirements. 

Dated: 

Lisa P. Jackson, 

Administrator. 
111 

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 98.2 is amended by revising the third 

sentence of paragraph (i)(3) to read as follows. 

§98.1 Purpose and Scope.

* * * * * 

(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. *

* * 

3. Section 98.3 is amended by revising paragraph 

(c)(7) to read as follows. 

§98.3 What are the general monitoring, reporting, 

recordkeeping and verification requirements of this part?

* * * * * 

(c) * * * 
112

(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. 

* * * * * 

4. Section 98.6 is amended by adding definitions for 

“Anaerobic process,” “Anaerobic reactor,” “Anaerobic sludge 

digester,” “Anaerobic wastewater treatment process,” 

“Cement kiln dust,” “Dedicated construction and demolition 

waste landfill,” “Degasification system,” “Destruction 

device,” “Ethanol production facility,” “Food processing 

facility,” “Furnace slag,” “Industrial waste landfill,” 

“Industrial wastewater,” “Industrial wastewater treatment 

sludge,” “Liberated,” “Municipal waste treatment plant,” 

“Ventilation well or shaft,” “Ventilation system,” 

“Wastewater treatment system,” and “Working capacity.” 

§98.6 Definitions.

* * * * * 

Anaerobic process means the procedure in which organic 

matter in wastewater, wastewater treatment sludge, or other 

material is degraded by micro organisms in the absence of 

oxygen, resulting in the generation of CO2 and CH4. 
113

Anaerobic reactor means an enclosed vessel used for an 

anaerobic wastewater treatment process. 

Anaerobic sludge digester means an enclosed vessel in 

which wastewater treatment sludges are degraded by 

microorganisms in the absence of oxygen, resulting in the 

generation of CO2 and CH4. 

Anaerobic wastewater treatment process means a process 

in which organic matter in wastewater is degraded by microorganisms in the absence of oxygen, resulting in the 

generation of CO2 and CH4. Anaerobic wastewater treatment 

processes include reactors and lagoons. 

* * * * * 

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). 

* * * * * 

Dedicated construction and demolition waste landfill

means a landfill that only receives materials generated 

from the construction or destruction of structures such as 

buildings, roads, and bridges. 
114

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 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. 

* * * * * 

Ethanol production facility means a facility that 

produces ethanol from the fermentation of sugar, starch, 

grain, or cellulosic biomass feedstocks, or produces 

ethanol synthetically from petrochemical feedstocks, such 

as ethylene or other chemicals. 

* * * * * 

Food processing facility means a facility that 

manufactures or processes meat, poultry, fruits, and/or 

vegtables. A meat or poultry processing or rendering 

facility is a facility covered under NAICS 3116 (Meat 

Product Manufacturing). A fruit or vegetable processing 
115

facility is a facility covered under NAICS 3114 (Fruit and 

Vegetable Preserving and Specialty Food Manufacturing). 

* * * * * 

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. 

* * * * * 

Industrial waste landfill means any landfill other 

than a municipal solid waste landfill, a RCRA Subtitle C 

hazardous waste landfill, or a TSCA hazardous waste 

landfill, in which industrial solid waste, such as RCRA 

Subtitle D wastes (non-hazardous industrial solid waste, 

defined in 40 CFR 257.2), commercial solid wastes, or 

conditionally exempt small quantity generator wastes, is 

placed. An industrial waste landfill includes all disposal 

areas at the facility. 

Industrial wastewater means water containing wastes 

from an industrial process. Industrial wastewater includes 

water which comes into direct contact with or results from 

the storage, production, or use of any raw material, 

intermediate product, finished product, by-product, or 

waste product. Examples of industrial wastewater include, 

but are not limited to, paper mill white water, wastewater 
116

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. 

* * * * * 

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. 
117

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 powerful fans that move large volumes of air through the 

mine workings to dilute methane concentrations. This 

includes all ventilation shafts and wells at the 

underground coal mine. 

* * * * * 

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. 

* * * * * 

Working capacity 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 roll-off bin) used to convey wastes to the 

landfill, taking into accout that the container may not be 

able to be 100 percent filled and/or 100 percent emptied 

for each load. 

* * * * * 

5. Section 98.7 is amended by: 
118

a. Revising paragraphs (d)(1) through (d)(10), 

(e)(10), (e)(11), (e)(25), (e)(42), and (f)(2). 

b. Adding paragraphs (e)(43) through (e)(45) and (k) 

through (n). 

§98.7 What standardized methods are incorporated by 

reference into this part?

* * * * * 

(d) * * * 

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

Pipes Using Orifice, Nozzle, and Venturi, incorporation by 

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

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

and §98.364(e). 

(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), 
119

§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). 

(6) ASME MFC-9M–1988 (Reaffirmed 2001) Measurement of 

Liquid Flow in Closed Conduits by Weighing Method, IBR 

approved for §98.34(b) and §98.244(b). 

(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). 
120

* * * * * 

(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 D1252-06 Standard Test Methods for Chemical 

Oxygen Demand (Dichromate Oxygen Demand) of Water, IBR 

approved for §98.354(b). 
121

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

Method for Open Channel Flow Measurement of Water with the 

Parshall Flume, IBR approved for §98.354(d). 

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

Method for Open Channel Flow Measurement of Water with 

Broad-Crested Weirs, 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 American National Standards Institute (ANSI), 25 West 

43rd Street, Fourth floor, New York, NY 10036, (212) 642-

4900, http://www.ansi.org. 

(1) American National Standard on Photographic 

Processing Effluents, April 2, 1975, IBR approved for 

§98.354(b). 

(2) [Reserved] 

(l) The following material is available for purchase 

from the Association of Official Analytical Chemists 

International, 481 North Frederick Avenue, Suite 500, 
122

Gaithersburg, MD 20877–2417, (800) 379-2622, 

http://www.aoac.org. 

(1) Official Methods of Analysis of the Association 

of Official Analytical Chemists, Methods Manual, Sixteenth 

Edition, 4th Revision, 1998, IBR approved for §98.354(b). 

(2) [Reserved] 

(m) The following material is available for purchase 

from Standard Methods, (877) 574-1233, 

http://www.standardmethods.org. 

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

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

(2) Method 5210B Biochemical Oxygen Demand (BOD) 5-

Day BOD Test (20th Edition), IBR approved for §98.354(b). 

(3) Method 5220C Chemical Oxygen Demand (COD) Closed 

Reflux, Titrimetric Method, IBR approved for §98.354(b). 

(4) Method 5220D Chemical Oxygen Demand (COD) Closed 

Reflux, Colorimetric Method, IBR approved for §98.354(b). 

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

Department of Labor, Mine Safety and Health Administration, 

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

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

(1) General Coal Mine Inspection Procedures and 

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

January 1, 2008, IBR approved for §98.324(b). 
123

(2) [Reserved] 

6. Table A-3 of subpart A is amended by revising the 

entry for “(Reserved)” to read as follows: 

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

Source Categories1 Applicable in 2010 and Future Years 

* * * * * * * 

Additional Source Categories1 Applicable in 2011 and Future 

Years

Underground coal mines that are subject to quarterly or more 

frequent sampling by MSHA of ventilation systems (subpart FF) 

1 Source categories are defined in each applicable subpart. 

7. Table A-4 of subpart A is amended by revising the 

entry for “(Reserved)” to read as follows: 

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

Source Categories1 Applicable in 2010 and Future Years 

* * * * * * * 

Additional Source Categories1 Applicable in 2011 and Future 

Years

Magnesium production (subpart T) 

Industrial wastewater treatment (subpart II) 

Industrial waste landfills (subpart TT) 

1 Source categories are defined in each applicable subpart. 

8. Part 98 is amended by adding subpart T to read as 

follows: 

Subpart T—Magnesium Production 

§98.200 Definition of Source Category.

The magnesium production and processing source 

category consists of the following processes: 
124

(a) Any process in which magnesium metal is produced 

through smelting (including electrolytic smelting), 

refining, or remelting operations. 

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

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

operations. 

§98.201 Reporting threshold.

You must report GHG emissions under this subpart if 

your facility contains a magnesium production process and 

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

or (2). 

§98.202 GHGs to report.

(a) You must report emissions of the following gases 

in metric tons per year resulting from their use as cover 

gases or carrier gases in magnesium production or 

processing: 

(1) Sulfur hexafluoride (SF6). 

(2) HFC-134a. 

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

(4) Carbon dioxide (CO2). 

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

(b) You must report CO2, N2O, and CH4 emissions from 

each combustion unit on site by following the calculation 

procedures, monitoring and QA/QC methods, missing data 
125

procedures, reporting requirements, and recordkeeping 

requirements of subpart C of this part. 

§98.203 Calculating GHG emissions.

(a) Calculate the mass of each GHG emitted from 

magnesium production or processing over the calendar year 

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

as appropriate. Both of these equations equate emissions 

of cover gases or carrier gases to consumption of cover 

gases or carrier gases. 

(1) To estimate emissions of cover gases or carrier 

gases by monitoring changes in container masses and 

inventories, emissions of each cover gas or carrier gas 

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

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

Where: 

Ex = Emissions of each cover gas or carrier gas in 

metric tons over the 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 
126

sales or other transactions during the year, 

including heels in cylinders or other containers 

returned by the magnesium production or processing 

facility to the gas supplier, in kg. 

0.001 = Conversion factor from kg to metric tons 

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

 (2) To estimate emissions of cover gases or carrier 

gases by monitoring changes in the masses of individual 

containers as their contents are used, emissions of each 

cover gas or carrier gas shall be estimated using Equation 

T-2 of this section: 

∑=

=

n

p

EGHG Qp

1

* 0.001 (Eq. T-2) 

Where: 

EGHG = The emissions of each cover or carrier gas over the 

reporting year (metric tons). 

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

over the container-use period p, from Eq. T-3. 

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

0.001 = Conversion factor from kg to metric tons. 

(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: 

Qp = M B − M E (Eq. T-3) 

Where: 
127

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 utilized as the emissions value E, in 

kg for period p in equation T-2. 

§98.204 Monitoring and QA/QC requirements.

(a) For calendar year 2011 monitoring, the facility 

may submit a request to the Administrator to use one or 

more best available monitoring methods as listed in 

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

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

FEDERAL REGISTER] and must contain the information in 

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

demonstrate to the Administrator’s satisfaction that it is 

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. 
128

(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 one 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 one 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 
129

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 one 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. 

(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 
130

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: 

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

Where: 

RGHG = The usage rate for a particular cover or carrier 

gas over the period of comparable operation (metric 

tons gas / metric ton Mg). 
131

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 detailed 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 

for the magnesium production and processing facility: 

(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) Typical cover and carrier gas flow rate (e.g., 

standard cubic feet per minute) for each production unit 

and composition in percent by volume. 
132

(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 facility’s overall cover gas usage rate (kg 

gas/metric ton Mg) for each cover gas, excluding the 

carrier gas, for the reporting year (e.g., 1 kg SF6 /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 for the magnesium 

production or processing facility: 

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

gas cylinders. 
133

(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 is the source of the 

casting operation. 
134

9. Part 98 is amended by adding subpart FF to read as 

follows: 

Subpart FF—Underground Coal Mines 

§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 when mine 

development is underway, coal has been produced within the 

last 90 days, mine personnel are present in the mine 

workings, or mine ventilation fans are operative. For the 

purposes of this rule, MSHA designated ”intermittent” mines 

are also considered active mines. (See definitions in 

§98.328 of this subpart.) 

(b) This source category includes the following: 

(1) Each ventilation well or shaft. 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). 
135

(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. The CH4 liberated is the total 

volume of CH4 released from the coal and surrounding rock 

strata during the mining (or pre-mining) process. As 

stated, this is the total determined by summing the volume 

of CH4 emitted from the ventilation system and the volume of 

CH4 drained from the degasification system. This includes 

degasification systems deployed before, during, or after 

mining operations are conducted in a mine area, and both 

those wells and shafts where gas is emitted, and those 
136

where gas is sold, used onsite, or otherwise destroyed 

(including by flaring). 

(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. This includes degasification 

systems deployed before, during, or after mining operations 

are conducted in a mine area. Net CH4 emissions are 

determined by deducting the CH4 in gas that is sold, used 

onsite, or otherwise destroyed (including by flaring), from 

the amount of CH4 liberated. 

(d) You must report 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 CO2, CH4, and N2O emissions from 

stationary fuel combustion devices. This includes emissions 

from both the combustion of fugitive CH4 emissions and any 

other fuels. You must follow the requirements of subpart 

C of this part. 

(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 
137

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 monitoring point in the ventilation 

system (this could be at each ventilation shaft and/or vent 

hole, or at more centralized points into which CH4 from 

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

calculate the quarterly CH4 liberated from the ventilation 

system using the measured CH4 content and flow rate, and 

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. 

















=

1,000

0.454

*1,440 *

1 atm

P

*

T

520 R

* 0.0423*

100%

C

CH n* V*

4V

o

MCF * (Eq. FF-1) 

Where: 

CH4V = Quarterly CH4 liberated from the ventilation 

monitoring point (metric tons CH4). 

V = Average daily measured total volumetric 

flow rate from the ventilation monitoring 

point (scfm)for the quarter. If the flow 

rate was determined based on sampling, the 

sampled rate will be used for determining 

an estimate for average daily flow rate. If 

the flow rate meter used for this 

measurement automatically corrects for 

temperature and pressure, replace “520°R/T 

× P/1 atm” with “1”. 
138

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) = Average moisture content of the methane 

emitted during the measurement period, 

volumetric basis (cubic feet water per 

cubic feet emitted gas) 

C = Average daily measured CH4 concentration of 

ventilation gas during ventilation at each 

monitoring point (%, wet basis)for the 

quarter. If concentration is measured from 

a single sample, it should be assumed the 

the sample concentration is the same as the 

average daily value. 

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 oR = 520 degrees Rankine. 

T = Average daily temperature at which flow is 

measured (°R) for the quarter. If 

temperature is measured from a single 

sample, it should be assumed that the 

sample temperature is the same as the 

average daily value. 

P = Average daily pressure at which flow is 

measured (atm) for the quarter. If pressure 

is measured from a single sample, it should 

be assumed that the sample pressure is the 

same as the average daily value. 

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

0.454/1,000 = Conversion factor (metric ton/lb). 
139

Consistent with MSHA inspections, the quarterly 

periods are: 

Χ January 1 – March 31 

Χ April 1 - June 30 

Χ July 1 - September 30 

Χ October 1 - December 31 

Samples are to be taken at least once each quarter 

with no fewer than 6 weeks between measurements. The 

average daily values for V, MCF, C, T, and P for the 

quarter are calculated based on the frequency of 

measurement. For example, if quarterly measurements are 

taken, they should represent the average values on the day 

the measurements are taken. If weekly measurements are 

taken, they represent the average values for the week. If 

continous measurements are taken, they represent the 

average values over the time period of continuous 

monitoring. The sampling and measurements must be made at 

the same locations as MSHA inspection samples are taken, 

and should be taken when the mine is perating under normal 

conditions. 

For the reporting mine, if a facility has more than 

one monitoring point, the facility must calculate total CH4

liberated from ventilation systems (CH4vTotal) as the sum of 
140

the CH4 from all ventilation monitoring points in the mine, 

as follows: 

CH4VTotal = ΣMonitoring Points (CH4V) (Eq. FF-2) 

Where: 

CH4V = Quarterly CH4 liberated from each ventilation 

monitoring point (metric tons CH4). 

(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 at that 

measurement point using CH4 measured weekly or more 

frequently (including by CEMS) according to 98.234(c), CH4 

content, flow rate, temperature, pressure, and moisture 

content, and Equation FF-3 of this section. 

















= ∑ 1,000

0.454 *1,440 *

1 atm

P

*

T

520 R

* 0.0423*

100%

C

CH V * MCF *

n

n

o

n

n n

1

4D

n

(Eq. FF-3) 

Where: 

CH4D = Weekly CH4 liberated from at the 

monitoring point(metric tons CH4). 

Vn = Average daily measured total volumetric 

flow rate for the days in the week when 

the degasification system is in operation 

at that monitoring point and the 

continuous monitoring equipment is 

properly functioning (scfm), or the 

measured temperature when weekly sampling 

is performed. If a flow rate meter is used 
141

for this measurement that automatically 

corrects for temperature and pressure, 

replace “520°R/Tn × Pn/1 atm” with “1”. 

MCFn = Moisture correction factor for the 

measurement period, volumetric basis. 

= 1 when Vn and Cn are measured on a dry 

basis or if both are measured on a wet 

basis. 

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

basis and Cn is measured on a dry basis. 

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

basis and Cn is measured on a wet basis. 

(fH2O)n = Average moisture content of the methane 

emitted during the measurement period at 

that monitoring point, volumetric basis 

(cubic feet water per cubic feet emitted 

gas) 

Cn = Average daily estimated or measured CH4

concentration of gas for the days in the 

week when the degasification system is in 

operation at that monitoring point and the 

continuous monitoring equipment is 

properly functioning, or the measured 

concentration when weekly sampling is 

performed (%, 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 oR = 520 degrees Rankine. 

Tn = Measured average temperature at which flow 

is measured for the days in the week when 

the degasification system at that 

monitoring point is in operation and the 

continuous monitoring equipment is 

properly functioning, or the measured 

value when weekly sampling is performed 

(°R). 

Pn = Measured average pressure at which flow is 

measured (atm) for the days in the week 

when the degasification system at that 

monitoring point is in operation and the 

continuous monitoring equipment is 
142

properly functioning, or the measured 

value when weekly sampling is performed. 

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

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

Average daily values for V, MCF, C, T, and P for the 

week are calculated based on the frequency of measurement. 

If weekly measurements are taken, they represent the 

average values for the week. Weekly means once each 

calendar week, with at least 3 days between measurements. 

If continous measurements are taken, they represent the 

average values over the time period of continuous 

monitoring. 

For the reporting mine, 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: 

CH4DTotal = ΣWeeks in Quarter(ΣEmission Points (CH4D)) 

(Eq. FF-4) 

Where: 

CH4DTotal = Quarterly CH4 liberated from all degasification 

monitoring points (metric tons CH4). 

CH4D = Weekly CH4 liberated from each degasification 

monitoring point (metric tons CH4). 

(c) If gas from degasification system wells or 

ventilation shafts is sold, used onsite, or otherwise 
143

destroyed (including by flaring), you must calculate the 

quarterly CH4 destroyed, for each destruction device and/or 

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. 

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

Where: 

CH4Destroyed = Quarterly CH4 liberated from the mine that 

is destroyed at each destruction device or 

tranported offsite for destruction (metric 

tons). 

CH4 = Quarterly CH4 collected for 

destruction(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.

For the reporting mine, if a facility has more than 

one destruction device or point of offsite transport to a 

destruction device, the facility must calculate total CH4

destroyed (CH4DestroyedTotal), determined as the sum of the 

methane destroyed at all destruction devices (onsite and 

offsite), as follows: 

CH4DestroyedTotal=ΣDestruction devices (CH4Destroyed) 

 (Eq. FF-6) 

Where: 
144

CH4DestroyedTotal = Quarterly total CH4 destroyed at the mine 

(metric tons CH4). 

(d) You must calculate the quarterly measured net CH4

emissions to the atmosphere using Equation FF-7 of this 

section. 

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

Where: 

CH4 emitted (net)= Quarterly CH4 emissions in the quarter 

summed over all mine ventilation and 

degasification monitoring points 

(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), you 

must estimate the CO2 emissions using Equation FF-8 of this 

section. 

CO2 = CH4Destroyedonsite * 44/16 (Eq. FF-8) 
145

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 FF5 (metric tons). 

44/16 = Ratio of molecular weights of CO2 to 

CH4. 

§98.324 Monitoring and QA/QC requirements. 

(a) For calendar year 2011 monitoring, the facility 

may submit a request to the Administrator to use one or 

more best available monitoring methods as listed in 

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

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

FEDERAL REGISTER] and must contain the information in 

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

demonstrate to the Administrator’s satisfaction that it is 

not reasonably feasible to acquire, install, and operate a 

required piece of monitoring equipment by January 1, 2011. 

The use of best available monitoring methods will not be 

approved beyond December 31, 2011. 

(b) For CH4 liberated from ventilation systems, 

determine whether CH4 will be monitored from each 

ventilation well and shaft, from a centralized monitoring 

point, or from a combination of the two options. Operators 
146

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) Monitor emissions from each ventilation well or 

shaft or centralized monitoring point where ventilation is 

taking place by collecting quarterly or more frequent grab 

samples (with no fewer than 6 weeks between measurements) 

and making 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. You must record the airflow, temperature, 

and pressure measured, the hand-held methane and oxygen 

readings in percentile, 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. 
147

(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 by one of the following 

options: 

(1) Direct monitoring using continuous wellbore 

monitors of gas recovered from mine degasification systems, 

where such systems are already in place. This includes both 

measurement of the gas volume recovered, along with 

measurements of methane concentrations in recovered gas 

volumes. 

(2) The collection of weekly (once each calendar 

week, with at least three days between measurements) or 

more frequent samples, for all degasification wells and gob 
148

gas vent holes. This includes both measurement of the gas 

volume emitted and recovered, along with measurements of 

methane concentrations in gas volumes recovered or emitted. 

Operators are required to 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. Sampling 

protocols should be the same as that described for sampling 

of methane emissions from ventilation shafts, as described 

in §98.324(b)(1). Methanometers and gas flow meters are 

required to be properly calibrated. 

(d) Monitoring must adhere to ASTM D1945-03 

(Reapproved 2006), 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 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 
149

for the GHG emissions calculations shall be calibrated 

prior to the first reporting year, using the applicable 

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

section. Alternatively, calibration procedures specified 

by the flow meter manufacturer may be used. Fuel flow 

meters, gas composition monitors, and heating value 

monitors shall be recalibrated either annually or at the 

minimum frequency specified by the manufacturer, whichever 

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

meters, the operator shall operate, maintain, and calibrate 

the flow meter using any of the following test methods or 

follow the procedures specified by the flow meter 

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). 
150

(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) All temperature and pressure monitors must be 

calibrated using the procedures and frequencies specified 

by the manufacturer. 

(g) 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.
151

(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 must contain the following information 

for each mine: (See definitions for Equations FF-1 through 

FF-5 for the definitions of the terms in parentheses) 
152

(a) Quarterly CH4 liberated from each ventilation 

monitoring point, and from each degasification system 

monitoring point (this includes degasification systems 

deployed before, during, or after mining operations are 

conducted in a mine area)(CH4V and CH4D), reported in metric 

tons CH4. 

(b) Quarterly CH4 destruction at each ventilation and 

degasification system destruction device or point of 

offsite transport(CH4Destroyed), reported in metric tons CH4. 

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

and degasification systems (this includes degasification 

systems deployed before, during, or after mining operations 

are conducted in a mine area) (CH4 emitted (net)), reported 

in metric tons CH4. 

(d) Quarterly CO2 emissions from on-site destruction 

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

energy generation or use (e.g., flaring) (CO2), reported in 

metric tons CO2. 

(e) Quarterly volumetric flow rate (scfm) for each 

ventilation monitoring point, including date(s) and 

location(s) of measurement, whether based on quarterly 

sampling or continuous monitoring (V). 

(f) Quarterly CH4 concentration (%) for each 

ventilation monitoring point, including date(s) and 
153

location(s) of measurement, whether based on quarterly 

sampling or continuous monitoring (C). 

(g) Quarterly sum of CEMS volumetric flow data used 

to calculate CH4 liberated from degasification systems 

(summed from daily CEMS data) (scf), or quarterly reporting 

of volumetric flow data (scf) based on results from weekly 

sampling data)(V). 

(h) 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). 

(i) Dates in quarterly reporting period where active 

ventilation of mining operations is taking place . 

(j) Dates in quarterly reporting period where 

degasification of mining operations is taking place . 

(k) Dates in quarterly reporting period when 

continuous monitoring equipment is not properly 

functioning, if applicable. 

(l) Temperatures (°R) and pressure (atm) values at 

the time, location (shaft or vent, degasification well or 

measurement point), and at the conditions for which 

measurements are made (T and P). 

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

device, including an indication of whether destruction 
154

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

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

destruction device is present at the mine, the annual 

operating hours for the primary destruction device, the 

annual operating hours for the back-up destruction device 

(if present), and the destruction efficiencies assumed 

(percent). 

(n) A description of the gas collection system 

(manufacture, capacity, number of wells, etc.), the surface 

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

annual operating hours of the gas collection system. 

(o) 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. 

(p) For each centralized monitoring point, 

identification of the wells and shafts included in the 

point. 

§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. 
155

(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. Part 98 is amended by adding subpart II to read 

as follows. 

Subpart II—Industrial Wastewater Treatment 

§98.350 Definition of Source Category

(a) This source category applies to anaerobic 

processes used to treat industrial wastewater and 

industrial wastewater treatment sludge at pulp and paper 

mills, food processing facilities, ethanol production 

facilities, and petroleum refineries. 

(b) This source category does not include municipal 

wastewater treatment plants or separate treatment of 

sanitary wastewater at industrial facilities. 

(c) This source category consists of the following: 

anaerobic reactors, anaerobic lagoons, anaerobic sludge 

digesters, and biogas destruction devices (including, for 

example, burners, boilers, turbines, and flares). 

§98.351 Reporting threshold.
156

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. 

(b) Ethanol Production and Food Processing Facilities 

(1) The facility meets a definition in §98.6. 

(2) The facility meets the requirements of 

§98.2(a)(2). 

(3) The facility operates an anaerobic process to 

treat industrial wastewater. 

§98.352 GHGs to report.

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

CH4 recovered from treatment of industrial wastewater using 

anaerobic lagoons or anaerobic reactors. 

(b) You must report CH4 emissions and CH4 recovered 

from anaerobic sludge digesters. 
157

(c) You must report CH4 emissions and CH4 destruction 

resulting from biogas collection and biogas destruction 

devices. 

§98.353 Calculating GHG emissions.

(a) For all anaerobic wastewater treatment processes, 

except anaerobic sludge digesters, 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 anaerobic wastewater treatment processes 

(specifically anaerobic reactors and anaerobic lagoons) 

using methods for the determination of chemical oxygen 

demand (COD), for each process estimate annual mass of CH4

generated using Equation II-1 of this section. 

∑[ ]

=

= ∗ ∗ ∗ ∗

52

1

4 0.001

w

CH Gn Floww CODw Bo MCF (Eq. II-1) 

Where: 

CH4Gn = Annual mass CH4 generated from the nth anaerobic 

wastewater treatment process (metric tons). 

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. 
158

MCF = CH4 conversion factor, based on relevant values 

in Table II-1 of this subpart. 

0.001 = Conversion factor from kg to metric tons. 

w = Index for weekly measurement period. 

(2) If you measure the concentration of organic 

material entering anaerobic wastewater treatment processes 

(specifically anaerobic reactors and lagoons) using methods 

for the determination of 5-day biochemical oxygen demand 

(BOD5), for each process estimate annual mass of CH4

generated using Equation II-2 of this section. 

∑[ ]

=

= ∗ ∗ ∗ ∗

52

1

4 5, 0.001

w

CH Gn Floww BOD w Bo MCF (Eq. II-2) 

Where: 

CH4Gn = Annual mass of CH4 generated from the anaerobic 

wastewater treatment process (metric tons). 

Floww = Volume of wastewater sent to an anaerobic 

wastewater treatment process in week n(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 

month n(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. 

w = Index for weekly measurement period. 
159

(b) For each anaerobic wastewater treatment process 

(anaerobic reactor and anaerobic lagoon)from which biogas 

is not recovered, estimate annual CH4 emissions using 

Equation II-3 of this section. 

CH4En = CH4Gn (Eq. II-3) 

Where: 

CH4En = Annual mass of CH4 emissions from the wastewater 

treatment process n (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 process (such as anaerobic 

digester, reactor, or 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 
160

system that directly reports CH4 content requires only the 

summing of results of all monitoring periods for a given 

year. 

Rn = 

∑=











 °

N

m 1

m

m

CH4 m

m MC m

1,000

0.454

 *

1atm

(P)

 * 

(T)

520R

*0.0423 * 

100%

(C )

(V) *(K ) * (Eq. II-4) 

Where: 

Rn = Annual quantity of CH4 recovered from the 

nth anaerobic reactor, digester, or lagoon 

(metric tons CH4/yr) 

N = Total number of measurement periods in a 

year. 

= 365 (N=366 for leap years) for daily 

averaging of continuous monitoring, as 

provided in paragraph(c)(1)of this section. 

= 52 for weekly sampling, as provided in 

paragraph(c)(2)of this section. 

m = Index for measurement period. 

Vn = Cumulative volumetric flow for the 

measurement period in actual cubic 

feet(acf). If no biogas was recovered 

during a monitoring period, use zero. 

KMCm = Moisture correction term for the 

measurement period, volumetric basis. 

= 1 when (V)m and (C)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 (C)n is measured on a dry basis. 

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

basis and (C)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 %). 
161

0.0423 = Density of CH4 lb/cf at 520°R or 60°F and 1 

atm. 

520 oR = 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 II4 of this section. 

(i) Continuously monitor gas flow rate and determine 

the volume of biogas each week and the cumulative volume of 

biogas each year that is collected and routed to a 

destruction device. If the gas flow meter is not equipped 

with automatic correction for temperature, pressure, or, if 

necessary, moisture content, you must determine these 
162

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 specified in §98.353(c)(2)(i), 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 
163

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 process (such as anaerobic 

digester, reactor or lagoon) from which some quantity of 

biogas is recovered, you must estimate both the annual mass 

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

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

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

(1) Estimate the annual mass of CH4 that is generated, 

but not recovered, using Equation II-5 of this section. 













= ∗ −1

CE

1

CH4Ln Rn (Eq. II-5) 

Where: 

CH4Ln = Leakage at the anaerobic process n (metric tons 

CH4). 

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 process (such as anaerobic 

digester, reactor, or lagoon) from which some quantity of 
164

biogas is recovered, estimate the annual mass of CH4 emitted 

using Equation II-6 of this section. 

( ( )) ( ( )) 4 n 4 n n 1 _1 n 2 _2 CH E CH L R 1- R 1- Dest Dest = + DE ∗ f + DE ∗ f (Eq. II-6) 

Where: 

CH4En = Annual quantity of CH4 emitted from process n 

(metric tons/yr). 

CH4Ln = Leakage at 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 

(calcluated in Eq. II-3) and all anaerobic processes from 

which some biogas is recovered (calculated in Eq. II-6 ) 

using Equation II-7 of this section. 
165

∑=

=

j

n

CH ET CH En

1

4 4 (Eq. II-7) 

Where: 

CH4ET = Annual mass CH4 emitted from all anaerobic 

processes at the facility (metric tons). 

n = Index for processes at the facility. 

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 [INSERT DATE 90 DAYS AFTER PUBLICATION IN THE 

FEDERAL REGISTER] and must contain the information in 

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

demonstrate to the Administrator’s satisfaction that it is 

not reasonably feasible to acquire, install, and operate a 

required piece of monitoring equipment by January 1, 2011. 

The use of best available monitoring methods will not be 

approved beyond December 31, 2011. 

(b) You must determine the concentration of organic 

material in wastewater treated anaerobically using 

analytical methods for COD or BOD5 specified in 40 CFR part 

136.3 Table 1B. For the purpose of determining 

concentrations of wastewater influent to the anaerobic 
166

wastewater treatment process, samples may be diluted to the 

concentration range of the approved method, but the 

calculated concentration of the undiluted wastewater must 

be used for calcuations and reporting required by this 

subpart. 

(c) You must collect samples representing wastewater 

influent to the anaerobic wastewater treatment process, 

following all preliminary and primary treatment steps 

(e.g., after grit removal, primary clarfication, oil-water 

separation, dissolved air flotation, or similar solids and 

oil separation processes). You must collect and analyze 

samples for COD or BOD5 concentration once each calendar 

week that the anaerobic wastewater treatment process is 

operating, with at least three days between measurements. 

You must collect a sample that represents the average COD 

or BOD5 concentration of the waste stream over a 24-hour 

sampling period. You must collect a minimum of four sample 

aliquots per 24-hour period and composite the aliquots for 

analysis. Collect a flow-proportional composite sample 

(either constant time interval between samples with sample 

volume proportional to stream flow, or constant sample 

volume with time interval between samples proportional to 

stream flow). Follow sampling procedures and techniques 

presented in “NPDES Compliance Inspection Manual,” EPA 305-
167

X-04-001, July 2004 or “U.S. EPA NPDES Permit Writers’ 

Manual,” EPA 833-B-96-003, December 1996. 

(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). 
168

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

Method for Open Channel Flow Measurement of Water with the 

Parshall Flume (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 (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 §98.354(h) and determine the cumulative 

volume of gas recovered as specified in Equation II-4. You 

must also determine the CH4 concentration of the recovered 

biogas as specified in §98.354(g) 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 cummulative biogas 
169

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

zero, with at least three days between measurements. As 

specified in §98.353(c) and §98.354(h), 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. 
170

(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) UOP539-97 Refinery Gas Analysis by Gas 

Chromatography (incorporated by reference, see §98.7). 

(6) As an alternative to the gas chromatography 

methods provided in paragraphs(g)(1) through (g)(5) of this 

section, you may use total gaseous organic concentration 

analyzers and calculate the CH4 concentration following the 

requirements in paragraphs (g)(6)(i) through (g)(6)(iii) of 

this section. 

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

A-7 to determine total gaseous organic concentration. You 

must calibrate the instrument with CH4 and determine the 

total gaseous organic concentration as carbon (or as CH4; 

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

appendix A-7). 
171

(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 
172

concentration. If the ratio exceeds 1, use 1 for the nonmethane organic carbon correction factor. 

(iii) Calculate the CH4 concentration as specified in 

Equation II-8 of this section. 

CCH4 = fNMOC x CTGOC (Eq. II-8) 

Where: 

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

%) for use in equation II-4. 

fNMOC = Non-methane organic carbon correction factor 

from the most recent determination of the nonmethane organic carbon correction factor as 

specified in paragraph (g)(6)(ii) of this section 

(unitless). 

CTGOC = Total gaseous organic carbon concentration 

measured using Method 25A or 25B at 40 CFR part 

60, appendix A-7 during routine monitoring of the 

biogas (volume %). 

(h) For each anaerobic process (such as an anaerobic 

reactor, digester, or lagoon) from which biogas is 

recovered, install, operate, maintain, and calibrate a gas 

flow meter capable of continuously measuring the volumetric 

flow rate of the recovered biogas using one of the methods 

specified in paragraphs (h)(1) through (h)(8) of this 

section or as specified by the manufacturer. Recalibrate 

each gas flow meter either biennially (every 2 years) or at 

the minimum frequency specified by the manufacturer. 

Except as provided in §98.353(c)(2)(iii), each gas flow 
173

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). 
174

(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 §98.354(f) 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
175

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 qualityassured data are available prior to the missing data 

incident, the substitute data value must be the first 

quality-assured value obtained after the missing data 

period. If, for a particular parameter, the “after” value 
176

is not obtained by the end of the reporting year, you may 

use the last quality-assured value obtained “before” the 

missing data period for the missing data substitution. You 

must document and keep records of the procedures you use 

for all such estimates. 

§98.356 Data reporting requirements. 

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

each annual report must contain the following information 

for the 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 sludges. Explain how the processes are related 

to each other and identify the anaerobic processes. 

Provide a unique identifier for each anaerobic process, 

indicate the average depth in meters of all anaerobic 

lagoons, and indicate whether biogas generated by each 

anaerobic process is recovered. The anaerobic processes 

must be identified as: 

(1) Anaerobic reactor. 

(2) Anaerobic deep lagoon (depth more than 2 meters). 

(3) Anaerobic shallow lagoon (depth less than 2 

meters). 

(4) Anaerobic sludge digester. 
177

(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 II1 or II-2 of this subpart. 

(c) For each anaerobic wastewater treatment process 

from which biogas is not recovered, you must report the 

annual CH4 emissions, calculated using Equation II-3 of this 

subpart. 

(d) For each anaerobic wastewater treatment process 

and anaerobic digester from which some biogas is recovered, 

you must report: 
178

(1) Annual quantity of CH4 recovered from the 

anaerobic process calculated using Equation II-4 of this 

subpart. 

(2) Cummulative volumentric biogas flow for each week 

that biogas is collected for destruction. 

(3) Weekly average CH4 concentration for each week 

that biogas is collected for destruction. 

(4) Weekly average temperature for each week at which 

flow is measured for biogas collected for destruction, or 

statement that temperature is incorporated into monitoring 

equipment internal calcultations. 

(5) An indication as to whether flow was measured on 

a wet or dry basis, an indication as to whether CH4

concentration was measured on a wet or dry basis, and if 

required for Equation II-4, weekly average moisture content 

for each week at which flow is measured for biogas 

collected for destruction, or statement that moisture 

content is incorporated into monitoring equipment internal 

calculations. 

(6) Weekly average pressure for each week at which 

flow is measured for biogas collected for destruction, or 

statement that pressure is incorporated into monitoring 

equipment internal calcultations. 
179

(7) CH4 collection efficiency (CE) used in equation 

II-5 of this subpart. 

(8) An indication of 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 (calcluated in 

Eq. II-3) and from all anaerobic processes from which some 

biogas is recovered (calculated in Eq. II-6 ) 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 
180

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. 

Anaerobic lagoon means a lined or unlined earthen 

basin used for wastewater treatment, in which oxygen is 

absent throughout the depth of the basin, except for a 

shallow surface zone. Anaerobic lagoons are not equipped 

with surface aerators. Anaerobic lagoons are classified as 

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

2 meters). 

Biogas means the combination of CO2, CH4, and other 

gases produced by the biological breakdown of organic 

matter in the absence of oxygen. 

Table II-1 of Subpart II—Emission Factors 

Factors Default value Units 

B0 – for facilities monitoring 

COD 

0.25 Kg CH4/kg COD 

B0 – for facilities monitoring 

BOD5 

0.60 Kg CH4/kg BOD5 

MCF – anaerobic reactor (e.g., 

upflow anaerobic sludge 

blanket, fixed film) 

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 
181

Table II-2 of Subpart II—Collection Efficiencies of 

Anaerobic Processes 

Anaerobic Process Type Cover Type 

Methane 

Collection 

Efficiency 

Bank to bank, 

impermeable 

Covered anaerobic lagoon 0.975 

(biogas capture) 

Modular, impermeable 0.70 

Anaerobic sludge 

digester; anaerobic 

reactor 

Enclosed Vessel 0.99 

11. Part 98 is amended by adding subpart TT to read 

as follows: 

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) This source category does not include: 

(1) Resource Conservation and Recovery Act (RCRA 

Subtitle C or Toxic Substances Control Act (TSCA) hazardous 

waste landfills. 

(2) Dedicated construction and demolition waste 

landfills. 

(3) Industrial waste landfills that only receive one 

or more of the following inert waste materials: 
182

(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. 

(c) 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.
183

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 section 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, 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 
184

modeled CH4 generation according to the applicable 

requirements in paragraphs (a)(1) through (a)(3) of this 

section. Apply Equation TT-1 of this section for each 

waste stream disposed of in the landfill and sum the CH4

generation rates for all waste streams disposed of in the 

landfill to calculate the total annual modeled CH4

generation rate for the landfill. 

(1) Calculate annual modeled CH4 generation using 

Equation TT-1 of this section. 

( ) 























= ∑ × × × × × × −

−

=

− − − − −

1

( 1) ( )

4

12

16 T

x S

k T x k T x

CH x x F x G W DOC MCF DOC F e e (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 or from measurement data [as 

specified in §98.463(a)(3)], 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 
185

collection system, use the annual average CH4

concentration from measurement data for the 

given year; otherwise, use the default value 

of 0.5. 

k = Decay rate constant from Table TT-1 of this 

subpart (yr-1). Select the most applicable k 

value for the majority of the past 10 years 

(or operating life, whichever is shorter). 

(2) Waste stream quantities. Determine annual waste 

quantities as specified in paragraphs (a)(2)(i) through 

(ii) of this section for each year starting with January 1, 

1980 or the year the landfills first accepted waste if 

after January 1, 1980, up until the most recent reporting 

year. The choice of method for determining waste 

quantities will vary according to the availability of 

historical data. Beginning in the first emissions 

monitoring year (2011 or later) and for each year 

thereafter, use the procedures in (a)(2)(i) 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 (a)(2)(i), where waste disposal 

records are available, and use the procedures outlined in 

(a)(2)(ii) 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 
186

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 

(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 
187

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 (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. 

























×

= ∑=

2

1

Y

x Y x

x

N P

W

WDF (Eq. TT-2) 

Where: 

WDF = Average waste disposal factor as determined for the 

first annual report required for this industrial 

waste landfill (metric tons per production unit). 

X = Year in which waste was disposed. Include only 

those years for which disposal and production data 

are both available; the years do not need to be 

sequential. 

Y1 = First year in which disposal and 

production/throughput data are both available. 

Y2 = First year for which GHG emissions from this 

industrial waste landfill must be reported. 

N = Number of years for which disposal and 

production/throughput data are both available. 

Wx = Quantity of waste placed in the industrial waste 

landfill in year X from measurement data and/or 
188

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. 

Wx = WDF × Px (Eq. TT-3) 

Where: 

X = Historic year in which waste was disposed. 

Wx = Calculated quantity of waste placed in the 

landfill in year X (metric tons). 

WDF = Average waste disposal factor from Equation TT2 of this section (metric tons per production 

unit). 

Px = Quantity of product produced or feedstock 

entering the process or facility in year X from 

measurement data and/or other company records 

(production units). You must use the same basis 

for Px (either production only or throughput 

only) as used to determine WDF in Equation TT-2 

of this section. 

(C) For any year in which historic production or 

processing data are not available such that historic waste 

quantities cannot be estimated using Equation TT-3 of this 
189

section, calculate an average annual bulk waste disposal 

quantity using fixed average annual bulk waste disposal 

quantity for each year for which historic disposal quantity 

and Equation TT-4 of this section. 

( − +1)

=

YrData YrOpen

LFC Wx (Eq. TT-4) 

Where: 

Wx = Quantity of waste placed in the landfill in year 

X (metric tons, wet basis). 

LFC = Landfill capacity or, for operating landfills, 

capacity of the landfill used (or the total 

quantity of waste-in-place) at the end of the 

“YrData” from design drawings or engineering 

estimates (metric tons). 

YrData = Year in which the landfill last received waste 

or, for operating landfills, the year prior to 

the year when waste disposal data is first 

available from company records or from Equation 

TT-3 of this section. 

YrOpen = Year 1960 or the year in which the landfill 

first received waste from company records, 

whichever is more recent. If no data are 

available for estimating YrOpen for a closed 

landfill, use 1960 as the default “YrOpen” for 

the landfill. 

(3) Degradable organic content (DOC). For any year, 

X, in Equation TT-1, use either the applicable default DOC 

values provided in Table TT-1 of this section 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 
190

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 
191

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 
192

first annual report should be used for all subsequent 

annual reports. 

(A) For years in which waste stream-specific disposal 

quantities are determined (as required in paragraphs (a)(2) 

(ii)(A) and (B) of this section), calculate the average DOC 

value for a given waste stream as the arithmetic average of 

all DOC measurements of that waste stream that follow the 

methods provided in §98.464(b), including any measurement 

values for years prior to the first reporting year and the 

four measurement values required in the first reporting 

year. Use the resulting waste-specific average DOC value 

for all applicable years (i.e., years in which waste 

stream-specific disposal quantities are determined) for 

which direct DOC measurement data are not available. 

(B) For years for which bulk waste disposal 

quantities are determined according to paragraphs 

(a)(2)(ii)(C) of this section, calculate the weighted 

average bulk DOC value according to the following: 

calculate the average DOC value for each waste stream as 

the arithmetic average of all DOC measurements of that 

waste stream that follows the methods provided in 

§98.464(b) (generally, this will include only the DOC 

values determined in the first year in which GHG emissions 

from this industrial waste landfill must be reported); 
193

calculate the average annual disposal quantity for each 

waste stream as the arithmetic average of the annual 

disposal quantities for each year in which waste streamspecific disposal quantities have been determined; and 

calculate the bulk waste DOC value using Equation TT-5 of 

this section. Use the bulk waste DOC value as DOCx for all 

years for which bulk waste disposal quantities are 

determined according to paragraphs (a)(2)(ii)(C) of this 

section. 

( )

∑

∑

=

=

×

= N

n

ave n

N

n

ave n ave n

bulk

W

DOC W

DOC

1

,

1

, ,

(Eq. TT-5) 

Where: 

DOCbulk = Degradable organic content value for bulk 

historical waste placed in the landfill (mass 

fraction). 

N = Number of different waste streams placed in the 

landfill 

n = Index for waste stream 

DOCave,n = Average degradable organic content value for 

waste stream “n” based on available measurement 

data (mass fraction). 

Wave,n = Average annual quantity of waste stream “n” 

placed in the landfill for years in which waste 

stream-specific disposal quantities have been 

determined (metric tons per year, wet basis). 

(b) For each landfill, calculate CH4 generation 

(adjusted for oxidation in cover materials) and CH4

emissions (taking into account any CH4 recovery, if 
194

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 (1- OX) = CH4 × (Eq. TT-6) 

Where: 

MG = Methane generation, adjusted for oxidation, from the 

landfill in the reporting year (metric tons CH4). 

GCH4 = Modeled methane generation rate in reporting year 

from Equation TT-1 of this section (metric tons 

CH4). 

OX = Oxidation fraction. Use the default value of 0.1 

(10%). 

(2) For landfills that do not have landfill gas 

collection systems operating during the reporting year, the 

CH4 emissions are equal to the CH4 generation (MG) 

calculated in Equation TT-6 of this section. 

(3) For landfills with landfill gas collection 

systems in operation during any portion of the reporting 

year, perform all of the calculations specified in 

paragraphs §98.463(b)(3)(i) through (iv). 
195

(i) Calculate the quantity of CH4 recovered according 

to the requirements in §98.343(b) of subpart HH (Municipal 

Solid Waste Landfills) of this part. 

(ii) Calculate CH4 emissions using the Equation HH-6 

in §98.343(c)(3)(i) of subpart HH (Municipal Solid Waste 

Landfills) of this part, except use GCH4 determined using 

Equation TT-1 of this section in Equation HH-6 of subpart 

HH (Municipal Solid Waste Landfills) of this part. 

(iii) Calculate CH4 generation (MG) from the quantity 

of CH4 recovered using Equation HH-7 in §98.343(c)(3)(ii) of 

subpart HH (Municipal Solid Waste Landfills) of this part. 

(iv) Calculate CH4 emissions from the quantity of CH4

recovered using Equation HH-8 in §98.343(c)(3)(ii) of 

subpart HH (Municipal Solid Waste Landfills) of this part. 

§98.464 Monitoring and QA/QC requirements. 

(a) For calendar year 2011 monitoring, the facility 

may submit a request to the Administrator to use one or 

more best available monitoring methods as listed in 

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

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

FEDERAL REGISTER] and must contain the information in 

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

demonstrate to the Administrator’s satisfaction that it is 

not reasonably feasible to acquire, install, and operate a 
196

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(b)(3)(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. 

 100%

% Total Solids

% Volatile Solids

CVS = × (Eq. TT-7) 

Where: 
197

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. 

 DOCx = FDOC ×% Volatile Solidsx (Eq. TT-8) 

Where: 

DOCx = Degradable organic content of waste 

stream in Year X (weight fraction, wet 

basis) 

FDOC = Fraction of the volatile residue that 

is degradable organic carbon (weight 

fraction). Use a default value of 

0.75. 

% 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 
198

the requirements specified in §98.344(b) of subpart HH 

(Municipal Solid Waste Landfills) of this part. 

(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 in §98.344(c) of subpart HH (Municipal Solid 

Waste Landfills) of this part. 

(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.
199

(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) of subpart HH 

(Municipal Solid Waste Landfills) of this part. 

§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. 
200

(3) The last year the landfill accepted waste (for 

open landfills, enter the estimated year of landfill 

closure). 

(4) The capacity (in metric tons) of the landfill. 

(5) An indication of whether leachate recirculation 

is used during the reporting year and its typical frequency 

of use over the past 10 years (e.g., used several times a 

year for the past 10 years, used at least once a year for 

the past 10 years, used occasionally but not every year 

over the past 10 years, not used). 

(b) Report the following waste characterization 

information: 

(1) The number of waste steams (including “Other 

Industrial Solid Waste (not otherwise listed)”) for which 

Equation TT-1 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 §98.466(b), 

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. 
201

(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 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 §98.466(b). 

(2) The degradable organic carbon (DOCx) value (mass 

fraction) and an indication as to whether this was the 

default value from Table TT-1 or a value determined through 

sampling and calculation for each waste stream identified 

in §98.466(b). 
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(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 
203

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) of subpart HH (Municipal Solid Waste Landfills) 

of this part. 

§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, for purposes of subpart TT of this part, 

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 
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waste material generated by a specific processing unit at 

that facility. For industrial solid wastes that are 

received from off-site facilities, a waste stream can be 

defined as each waste shipment or group of waste shipments 

received from a single client or group of clients that 

produce industrial solid wastes with similar waste 

properties. 

Table TT-1 of Subpart TT—Default DOC and Decay Rate Values 

for Industrial Waste Landfills 

Industry/Waste Type 

DOC 

(weight 

fraction, 

wet basis)

k 

[dry 

climatea] 

(yr-1) 

k 

[moderate 

climatea] 

(yr-1) 

k 

[wet 

climatea] 

(yr-1) 

Food Processing 0.26 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

a The applicable climate classification is determined based on the 

annual rainfall plus the recirculated leachate application rate. 

Recirculated leachate application rates (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