6560.50 

ENVIRONMENTAL PROTECTION AGENCY 

40 CFR Parts 86 and 98 

[EPA-HQ-OAR-2010-0109; FRL-xxxx-x] 

RIN 2060-A079 

Mandatory Reporting of Greenhouse Gases 

AGENCY: Environmental Protection Agency (EPA). 

ACTION: Final rule. 

SUMMARY: EPA is amending specific provisions in the 2009 

Final Mandatory Greenhouse Gas Reporting rule to correct 

certain technical and editorial errors that have been 

identified since promulgation and to clarify and update 

certain provisions that have been the subject of questions 

from reporting entities. These final changes include 

additional information to better or more fully understand 

compliance obligations, corrections to data reporting 

elements so they more closely conform to the information 

used to perform emission calculations, and other 

corrections and amendments. 

DATES: The final rule amendments are effective on [INSERT 

THE DATE 30 DAYS AFTER THE DATE OF PUBLICATION IN THE 

FEDERAL REGISTER]. The incorporation by reference of 

certain publications listed in the final rule amendments 

are approved by the director of the Federal Register as of 
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[INSERT THE DATE 30 DAYS AFTER THE DATE OF PUBLICATION IN 

THE FEDERAL REGISTER]. 

ADDRESSES: EPA has established a docket under Docket ID 

No. EPA–HQ–OAR–2010-0109 for this action. All documents in 

the docket are listed on the http://www.regulations.gov

index. Although listed in the index, some information is 

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

whose disclosure is restricted by statute. Certain other 

material, such as copyrighted material, is not placed on 

the Internet and will be publicly available only in hard 

copy form. Publicly available docket materials are 

available either electronically through 

http://www.regulations.gov or in hard copy at EPA’s Docket 

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

1301 Constitution Ave., NW., Washington, DC. This Docket 

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

through Friday, excluding legal holidays. The telephone 

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

the telephone number for the Air Docket is (202) 566–1742. 

FOR FURTHER GENERAL INFORMATION CONTACT: Carole Cook, 

Climate Change Division, Office of Atmospheric Programs 

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

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

number: (202) 343-9263; fax number: (202) 343-2342; e-mail 
Page 3 of 246 

address: GHGReportingRule@epa.gov. For technical 

information and implementation materials, please go to the 

Greenhouse Gas Reporting Program website 

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

emissions/ghgrulemaking.html. To submit a question, select 

Rule Help Center, followed by Contact Us. 

SUPPLEMENTARY INFORMATION: 

Regulated Entities. The Administrator determined that 

this action is subject to the provisions of Clean Air Act 

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

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

as the Administrator may determine”). These are final 

amendments to existing regulations. These amended 

regulations affect owners or operators of certain fossil 

fuel suppliers, direct emitters of greenhouse gases, and 

manufacturers of highway heavy-duty vehicles. 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 

Adipic Acid 

Production 

325199 Adipic acid manufacturing 

facilities. 

Cement 

Production 

327310 Portland cement manufacturing 

plants. 

Ferroalloy 

Production 

331112 Ferroalloys manufacturing 

facilities. 

327211 Flat glass manufacturing 

facilities. 

Glass Production

327213 Glass container manufacturing 

facilities. 
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Category NAICS Examples of affected facilities 

327212 Other pressed and blown glass and 

glassware manufacturing facilities. 

HCFC-22 

Production and 

HFC-23 

Destruction 

325120 Chlorodifluoromethane manufacturing 

facilities. 

Hydrogen 

Production 

325120 Hydrogen manufacturing facilities. 

Iron and Steel 

Production 

331111 

Integrated iron and steel mills, 

steel companies, sinter plants, 

blast furnaces, basic oxygen 

process furnace shops. 

Lime Production 327410 

Calcium oxide, calcium hydroxide, 

dolomitic hydrates manufacturing 

facilities. 

Nitric Acid 

Production 

325311 Nitric acid manufacturing 

facilities. 

Phosphoric Acid 

Production 

325312 Phosphoric acid manufacturing 

facilities. 

325181 Alkali and chlorine manufacturing 

Soda Ash facilities. 

Manufacturing 

212391 Soda ash, natural, mining and/or 

beneficiation. 

Titanium Dioxide 

Production 

325188 Titanium dioxide manufacturing 

facilities. 

331419 Primary zinc refining facilities. 

Zinc Production 

331492 

Zinc dust reclaiming facilities, 

recovering from scrap and/or 

alloying purchased metals. 

Municipal Solid 562212 Solid Waste Landfills 

Waste Landfills 221320 Sewage Treatment Facilities 

Suppliers of 

Coal Based 

Liquids Fuels 

211111 Coal liquefaction at mine sites. 

221210 Natural gas distribution 

facilities. 

Suppliers of 

Natural Gas and 

NGLs 211112 Natural gas liquid extraction 

facilities. 

Table 1 of this preamble is not intended to be 

exhaustive, but rather provides a guide for readers 

regarding facilities likely to be affected by this action. 

Table 1 of this preamble lists the types of facilities that 

EPA is now aware could be potentially affected by the 
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reporting requirements. Other types of facilities than 

those listed in the table could also be subject to 

reporting requirements. To determine whether you are 

affected by this action, you should carefully examine the 

applicability criteria found in 40 CFR part 98, subpart A 

or the relevant criteria in the sections related to fossil 

fuel suppliers, direct emitters of GHGs, and manufacturers 

of highway heavy-duty vehicles. If you have questions 

regarding the applicability of this action to a particular 

facility, consult the person listed in the preceding FOR 

FURTHER GENERAL INFORMATION CONTACT section. 

Judicial Review. Under section 307(b)(1) of the Clean 

Air Act (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 (the 

Court) by [INSERT THE DATE 60 DAYS AFTER THE DATE OF

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. 

Section 307(d)(7)(B) of the CAA also provides a mechanism 

for EPA to convene a proceeding for reconsideration, “[i]f 

the person raising an objection can demonstrate to EPA that 

it was impracticable to raise such objection within [the 
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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 the 

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 20460, 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. 

AFPC Association of Fertilizer and Phosphate Chemists 

AOD argon-oxygen decarburization 

API American Petroleum Institute 

ASTM American Society for Testing and Materials 

C&D Construction and demolition 

CAA Clean Air Act 

CaO calcium oxide 
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CBI confidential business information 

CEMS continuous emission monitoring system 

CFR Code of Federal Regulations 

CH4 methane 

CKD cement kiln dust 

CO2 carbon dioxide 

DE destruction efficiency 

DOC degradable organic carbon 

EAF electric arc furnace 

EF emission factor 

EIA Energy Information Administration 

EPA U.S. Environmental Protection Agency 

FR Federal Register 

GHG greenhouse gas 

HHV higher heating value 

ID identification 

kg kilograms 

lb pound 

LNG liquefied natural gas 

LMPs Lime manufacturing plants 

MCF Methane Correction Factor 

MgO magnesium oxide 

Mscf thousand standard cubic feet 

MSW municipal solid waste 

MSWLF municipal solid waste landfill 

N2O nitrous oxide 

NAICS North American Industry Classification System 

NGLs natural gas liquids 

NOx nitrogen oxides 

NTTAA National Technology Transfer and Advancement Act 

OMB Office of Management and Budget 

QA/QC quality assurance/quality control 

RCRA Resource Conservation and Recovery Act 

RFA Regulatory Flexibility Act 
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SBREFA Small Business Regulatory Enforcement Fairness 

Act 

SWDS solid waste disposal site 

TSCA Toxic Substances Control Act (TSCA) 

U.S. United States 

UMRA Unfunded Mandates Reform Act of 1995 

VOD vacuum oxygen decarburization 

Table of Contents 

I. Background

A. How is this preamble organized?

B. Background on this action

C. Legal authority

D. How will these amendments apply to 2011 reports?

II. Final Amendments and Responses to Public Comments

A. Mobile Sources

B. Subpart A – General Provisions

C. Subpart E – Adipic Acid Production

D. Subpart H – Cement Production

E. Subpart K – Ferroalloy Production

F. Subpart N – Glass Production

G. Subpart O - HCFC-22 Production and HFC-23 Destruction

H. Subpart P - Hydrogen Production

I. Subpart Q – Iron and Steel Production

J. Subpart S – Lime Manufacturing

K. Subpart V – Nitric Acid Production

L. Subpart Z – Phosphoric Acid Production

M. Subpart CC – Soda Ash Manufacturing

N. Subpart EE – Titanium Dioxide Production

O. Subpart GG – Zinc Production

P. Subpart HH – Municipal Solid Waste Landfills

R. Subpart MM - Suppliers of Petroleum Products

S. Subpart NN – Suppliers of Natural Gas and Natural Gas 

Liquids

III. 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
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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. How is this preamble organized?

The first section of this preamble contains the basic 

background information about the origin of these rule 

amendments. This section also discusses EPA’s use of our 

legal authority under the CAA to collect data under the 

mandatory GHG reporting rule. 

The second section of this preamble describes in 

detail the rule changes that are being promulgated to 

correct technical errors, to provide clarification, and to 

address implementation issues identified by EPA and others. 

This section also presents a summary and EPA’s response to 

the major public comments submitted on the proposed rule 

amendments, and significant changes, if any, made since 

proposal in response to those comments. 

Finally, the last (third) section of the preamble 

discusses the various statutory and executive order 

requirements applicable to this final rulemaking. 

B. Background on this action
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The final Mandatory Reporting of Greenhouse Gases Rule 

(40 CFR part 98 or Part 98) was signed by EPA Administrator 

Lisa Jackson on September 22, 2009 and published in the 

Federal Register on October 30, 2009 (74 FR 56260, October 

30, 2009). Part 98, which became effective on December 29, 

2009, included reporting of greenhouse gas (GHG) 

information from facilities and suppliers, consistent with 

the 2008 Consolidated Appropriations Act1. These source 

categories capture approximately 85 percent of U.S. GHG 

emissions through reporting by direct emitters as well as 

suppliers of fossil fuels and industrial gases and 

manufacturers of mobile sources. 

EPA published a notice proposing amendments to Part 98 

to, among other things, correct certain technical and 

editorial errors that have been identified since 

promulgation and clarify or propose amendments to certain 

provisions that have been the subject of questions from 

reporting entities. The proposal was published on June 15, 

2010 (75 FR 33950). The public comment period for the 

proposed rule amendments ended on July 30, 2010. EPA did 

not receive any requests to hold a public hearing. 

In addition to the notice published on June 15, 2010 

(75 FR 33950), EPA published a second proposal on August 

 

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

1844, 2128. 
Page 11 of 246 

11, 2010 (75 FR 48744). The second notice proposed to 

correct certain technical and editorial errors in Part 98 

that were identified since promulgation and clarify or 

propose amendments to certain provisions that were the 

subject of questions from reporting entities, primarily to 

subparts not addressed in the June 15, 2010 proposal. The 

August 11, 2010 proposal complements the proposal published 

on June 15, 2010. 

C. Legal authority

EPA is promulgating these rule amendments under its 

existing CAA authority, specifically authorities provided 

in CAA sections 114 and 208. 

As stated in the preamble to the final Part 98 (74 FR 

56260), CAA sections 114 and 208 provide EPA broad 

authority to require the information mandated by this rule 

because such data will inform and are relevant to EPA’s 

carrying out a wide variety of CAA provisions. As 

discussed in the preamble to the initial proposed Part 98 

(74 FR 16448, April 10, 2009) CAA section 114(a)(1) 

authorizes the Administrator to require emissions sources, 

persons subject to the CAA, manufacturers of process or 

control equipment, and persons whom the Administrator 

believes may have necessary information to monitor and 

report emissions and provide such other information the 
Page 12 of 246 

Administrator requests for the purposes of carrying out any 

provision of the CAA (except for a provision of title II 

with respect to manufacturers of new motor vehicles or new 

motor vehicle engines2). Section 208 of the CAA provides 

EPA with similar broad authority regarding the 

manufacturers of new motor vehicles or new motor vehicle 

engines, and other persons subject to the requirements of 

parts A and C of title II. For further information about 

EPA’s legal authority, see the preambles to the proposed 

and final Part 98.3 

D. How will these amendments apply to 2011 reports?

With two exceptions, we have determined that it is 

feasible for reporters to implement these changes for the 

2010 reporting year because the revisions primarily provide 

additional clarifications regarding the existing regulatory 

requirements, generally do not affect the type of 

information that must be collected and do not substantially 

affect how emissions are calculated. Our rationale for 

this determination is explained in the preamble to the 

proposed rule amendments.4

 

2 Although there are exclusions in CAA section 114(a)(1) regarding 

certain title II requirements applicable to manufacturers of new motor 

vehicle and motor vehicle engines, CAA section 208 authorizes the 

gathering of information related to those areas. 

3 74 FR 16448 (April 10, 2009) and 74 FR 56260 (October 30, 2009). 

4 75 FR 33952–33953 (June 15, 2010). 
Page 13 of 246 

In summary, these amendments, with the two exceptions 

described below, do not require any additional monitoring 

or information collection above what was already included 

in Part 98. Therefore, we have determined that reporters 

can use the same information that they have been collecting 

for each subpart to calculate and report GHG emissions for 

2010 and submit reports in 2011 under the amended subparts. 

The first exception is for reporting CO2 emissions from 

certain types of decarburization vessels at iron and steel 

sources under subpart Q. EPA has determined, based on 

public comments, that it is necessary to allow a delay in 

reporting from certain decarburization vessels until the 

2011 data collection year (and the subsequent annual GHG 

emissions reports submitted to EPA by March 31, 2012). The 

delay in implementation was determined to be necessary 

because although the 2009 final rule was clear that 

emissions from argon oxygen-decarburization vessels were 

required to be reported, the inclusion of other types of 

decarburization vessels was not clear. A more detailed 

description of the affected decarburization vessels and our 

rationale is available in Section II.I of this preamble. 

The second exception is related to crude oil reporting 

requirements in subpart MM. We are providing reporters 

some flexibility in defining a batch of crude oil for 
Page 14 of 246 

purposes of reporting crude oil data for reporting year 

2010. A more detailed description of the type of 

flexibility we are providing and our rationale is available 

in Section II.R of this preamble. EPA notes that crude oil 

data does not impact the CO2 calculations for 2010 or for 

any other reporting year. 

II. Final Amendments and Responses to Public Comments 

We are amending 40 CFR part 86 to appropriately 

incorporate the regulatory text into the regulations at 40 

CFR 86.1844-01. 

In 40 CFR Part 98, we are amending various subparts to 

correct errors in the regulatory language that were 

identified as a result of working with affected industries 

to implement the various subparts of Part 98. We are also 

amending certain rule provisions to provide greater 

clarity. The amendments to 40 CFR Part 98 include the 

following types of changes: 

• Changes to correct cross references within and between 

subparts. 

• Additional information to better or more fully 

understand compliance obligations in a specific 

provision, such as the reference to a standardized 

method that must be followed. 

• Amendments to certain equations to better reflect 

actual operating conditions. 

• Corrections to terms and definitions in certain 

equations. 
Page 15 of 246 

• Corrections to data reporting requirements so that 

they more closely conform to the information used to 

perform emission calculations. 

• Other amendments related to certain issues identified 

as a result of working with the reporters during rule 

implementation and outreach. 

The final amendments promulgated by this action 

reflect EPA’s consideration of the comments received on the 

proposal. The major public comments and EPA’s responses 

for each subpart are provided in this preamble. Our 

responses to additional significant public comments on the 

proposal are presented in a comment summary and response 

document available in Docket ID No. EPA–HQ–OAR–2010-0109. 

A. Mobile Sources

1. Summary of Final Amendments and Major Changes Since 

Proposal.

Manufacturers of highway heavy-duty vehicles, as well 

as manufacturers of highway heavy-duty engines, are subject 

to GHG reporting requirements. EPA inadvertently omitted 

the regulatory text covering manufacturers of highway 

heavy-duty vehicles. We are amending 40 CFR part 86 to 

correct that error by incorporating the appropriate 

language into the regulations at 40 CFR 86.1844-01. 

2. Summary of Comments and Responses
Page 16 of 246 

EPA did not receive any comments on the proposed 

amendments to 40 CFR part 86 and is finalizing the 

amendments as proposed. 

B. Subpart A – General Provisions

1. Summary of Final Amendments and Major Changes Since 

Proposal.

We are adding and changing several definitions to 

subpart A to clarify terms used in other subparts of Part 

98. Similarly, we are amending 40 CFR 98.7 (incorporation 

by reference) to accommodate changes in the standard 

methods that are allowed by other subparts of Part 98. 

We are amending the following definitions in 40 CFR 

98.6: 

• Carbonate-based mineral. 

• Carbonate-based mineral mass fraction. 

• Carbonate-based raw material. 

• Crude oil. 

• Decarburization vessel. 

• Gas collection system or landfill gas collection 

system. 

• Mscf. 

• Non-crude feedstocks. 

We are amending the definitions of “carbonate-based 

mineral,” “carbonate-based mineral mass fraction,” and 

“carbonate-based raw material” in order to include barium 

carbonate, potassium carbonate, lithium carbonate, and 
Page 17 of 246 

strontium carbonate, because these carbonates are consumed 

in the glass industry subject to subpart N. 

We are amending the definition of “crude oil” in 40 

CFR 98.6 so that it is consistent with the definition in 

the Energy Information Administration’s (EIA) Definitions 

of Petroleum Products and Other Terms (Revised January 

2010)5, with one additional provision to accommodate the 

needs of this program to ensure complete reporting of 

petroleum products, including the unique circumstances that 

have been raised in comments. We are adding a crude oil 

reporting requirement in subpart MM (40 CFR 98.396 (a)(22)) 

to accommodate this provision. 

We are amending the definition of “decarburization 

vessel” in 40 CFR 98.6 to include vessels that are used to 

further refine molten steel with the primary intent of 

reducing the carbon content of the steel. 

We are amending the definition of "gas collection 

system or landfill gas collection system," in 40 CFR 98.6 

to clarify that the passive vents/flares are not considered 

part of a landfill gas collection system for purposes of 

subpart HH, to state that such a system collects gas 

actively by means of a fan or similar mechanical draft 

 

5 

http://www.eia.doe.gov/pub/oil_gas/petroleum/survey_forms/psmdefs_2010.

pdf
Page 18 of 246 

equipment, versus collecting gas passively. Based on a 

comment received, we are also clarifying that a single 

landfill may have more than one gas collection system. 

We are also amending the definition of “Mscf” in 40 

CFR 98.6 to indicate that “Mscf” means thousand standard 

cubic feet. 

We are also amending the definition of “non-crude 

feedstocks” in 40 CFR 98.6 to remove the phrase “as a 

feedstock” in order to avoid confusion with the definition 

of “feedstock.” Under subpart MM, refiners must calculate 

annual CO2 emissions that would result from the complete 

combustion or oxidation of each non-crude feedstock. Our 

intention in subpart MM is to capture all petroleum 

products and natural gas liquids that enter a refinery to 

be further refined or otherwise used on site. By removing 

the term “as a feedstock” from the definition of “non-crude 

feedstocks” we are aligning the definition to the original 

intent of subpart MM. 

We are also incorporating by reference ASTM D6349-09, 

“Standard Test Method for Determination of Major and Minor 

Elements in Coal, Coke, and Solid Residues from Combustion 

of Coal and Coke by Inductively Coupled Plasma—Atomic 

Emission Spectrometry” for subpart N. 
Page 19 of 246 

Major changes since proposal are identified in the 

following list. The rationale for these and any other 

significant changes can be found in this preamble or the 

Response to Comments: Technical Corrections, Clarifying and 

Other Amendments (see EPA-HQ-OAR-2010-0109). 

• In the definitions of “carbonate-based mineral,” 

“carbonate-based mineral mass fraction,” and 

“carbonate-based raw material,” adding lithium 

carbonate and strontium carbonate, as well as the 

proposed additions of barium carbonate and potassium 

carbonate. 

• Expanding the proposed definition of crude oil to 

include petroleum products injected into a crude 

supply or reservoir. 

• Narrowing the definition of decarburization vessel to 

include only vessels for which the primary intent is 

reducing the carbon content of the steel. 

• Incorporating by reference ASTM D6349-09, “Standard 

Test Method for Determination of Major and Minor 

Elements in Coal, Coke, and Solid Residues from 

Combustion of Coal and Coke by Inductively Coupled 

Plasma—Atomic Emission Spectrometry” for subpart N. 

2. Summary of Comments and Responses

This section contains a brief summary of major 

comments and responses. Several comments were received on 

this subpart. Responses to additional significant comments 

received can be found in Response to Comments: Technical 

Corrections, Clarifying and Other Amendments (see EPA-HQOAR-2010-0109). 

Comment: One commenter responded to EPA’s question 

regarding whether other carbonates not listed in the 
Page 20 of 246 

proposed definitions are consumed in glass production, and 

the commenter noted that they consume lithium carbonate and 

strontium carbonate.

Response: EPA appreciates the clarification and has 

added these carbonates to the definitions of carbonatebased materials in 40 CFR 98.6 and to Table N-1 to subpart 

N. 

Comment: EPA received several comments on our 

proposal to amend the definition of crude oil. Two 

commenters supported the proposed definition of crude oil 

because it is identical to the definition used for 

reporting to the Energy Information Administration (EIA) 

and it will be easier for reporters to calculate and report 

the same data for both agencies’ crude oil reporting 

requirements. One commenter suggested that EPA expand it 

even further by adding the word “nitrogen” to describe nonhydrocarbons, referencing atmospheric conditions rather 

than just atmospheric pressure, removing the requirement 

that hydrocarbon liquids must be comingled with a crude 

stream, and including natural gas processing plant liquids 

captured by gravity separation. Therefore, the commenter 

did not support using a definition of crude oil that is 

identical to the definition used by EIA. Two commenters 

submitted information about situations where a petroleum 
Page 21 of 246 

product is re-injected into a crude supply line or back 

into a reservoir. One of these two commenters reported 

that they inject a mixture of products, some of which meet 

the proposed definition of crude and some of which do not, 

and specifically requested clarification on how to treat 

such a mixture with respect to crude oil and petroleum 

product reporting. 

Response: In today’s final rule, EPA is retaining the 

amendatory text proposed for the definition of crude oil 

and making amendments beyond what was proposed to address 

the comments received and improve technical accuracy. 

EPA agrees with commenters that a definition of crude 

oil for Part 98 that is identical to the EIA definition 

makes it easier for refineries to comply with both 

agencies’ reporting requirements. However, EPA considered 

comments requesting amendments to the crude oil definition 

in an effort to ensure the definition is technically 

accurate and to allow for complete reporting. 

EPA considered including natural gas processing plant 

liquids captured by gravity separation in the crude oil 

definition, but concluded that doing so would create 

ambiguity in the regulatory text. EPA has always required 

natural gas liquids (NGLs) received by the refinery to be 

reported as non-crude feedstock because the vast majority 
Page 22 of 246 

is being reported by fractionators as product supplied 

under subpart NN, and EPA does not want these volumes to be 

double counted across the industry. Because refiners would 

be unable to physically distinguish NGLs from gravity 

separation from NGLs reported as product by fractionators 

under subpart NN, EPA does not concur that such an edit is 

an improvement to the proposed definition and has not made 

the suggested change in the definition. 

EPA agrees with the comment that specifying 

atmospheric conditions (temperature and pressure), rather 

than just atmospheric pressure, is technically more 

accurate and has made this change in the final definition. 

This change allows for conditions under which liquids may 

drop out because of lower temperatures that may not have 

dropped out in warmer temperatures and atmospheric 

pressure. EPA has concluded that adding “nitrogen” as an 

example of non-hydrocarbons does not improve technical 

accuracy and is not necessary since it is clear that 

nitrogen is a non-hydrocarbon. Therefore, EPA has not made 

this change to the final definition. 

EPA considered removing the qualification that 

hydrocarbon liquids must be comingled with a crude stream 

to meet the crude oil definition and concluded that 

removing that qualification would create ambiguity. EPA 
Page 23 of 246 

determined that it may be difficult for refineries to 

distinguish between such hydrocarbon liquids (which 

commenters suggested should be treated as crude oil) and 

natural gas liquids or petroleum products (which EPA 

required be treated as non-crude feedstock) when received 

and to, therefore, determine how to comply with the rule. 

EPA has concluded that we cannot delete such text from the 

crude oil definition unless we specifically seek comment on 

the impact of such a revision to reporters. Therefore, 

such an amendment is outside of the scope of this 

rulemaking. 

Finally, EPA is expanding the proposed definition of 

crude oil to include petroleum products that are received 

or produced at a refinery and subsequently injected into a 

crude supply or reservoir by the same refinery owner or 

operator. EPA is making this addition because, in these 

situations, petroleum products will be comingled with crude 

oil to the point of being indistinguishable from crude oil. 

Whenever a refinery receives the comingled crude oil 

downstream they will report it as crude oil to EPA. 

Therefore, this addition is needed to prevent doublecounting among reporters under subpart MM. EPA has 

concluded that the additions to the definition beyond what 

is used by EIA will only apply to a small minority of 
Page 24 of 246 

refineries that face the unique circumstances presented by 

commenters and that all other refineries will be able to 

report to EPA according to the same definition that they 

use to report to EIA. 

With this amendment in place, EPA will need data on 

the volume injected into a crude supply or reservoir from 

this small minority of refineries in order to conduct 

effective verification on the full set of data submitted 

under subpart MM. Therefore, we are making a harmonizing 

amendment to subpart MM to require reporting on the volume 

of any crude oil injected into a crude supply or reservoir 

under a new paragraph 40 CFR 98.396(a)(22). 

Comment: One commenter noted that the Phosphate 

Mining States Methods Used and Adopted by the Association 

of Fertilizer and Phosphate Chemists (AFPC) Manual 10th 

Edition — Version 1.9 had been updated to the version 1.92, 

which includes a protocol for collecting grab samples of 

phosphate rock to be tested for chemical composition. 

Response: EPA agrees that it is important to allow 

phosphoric acid facilities to follow the latest standard 

protocol for grab samples of phosphate rock. In light of 

this, EPA has finalized requirements to use an industry 

consensus standard or industry standard practice for 

collecting grab samples. As an example, the Association of 
Page 25 of 246 

Fertilizer and Phosphate Chemists (AFPC) Manual 10th

Edition- Version 1.92 and future versions of that manual 

would be an acceptable standard. 

C. Subpart E – Adipic Acid Production

1. Summary of Final Amendments and Major Changes Since 

Proposal.

We are amending Equation E-1, Equation E-2 and 

Equation E-3 in 40 CFR 98.53. First, we are amending these 

equations so that the calculation equations are internally 

consistent. Currently, the equations do not correctly 

address situations in which a facility has more than one 

production unit or process line with separate N2O control or 

abatement technology on the separate production units or 

process lines, and the technologies are not operated 100 

percent of the time. In these circumstances, the current 

equations will not provide an accurate calculation of N2O 

emissions. We are amending the equations so that emissions 

are calculated separately for each production unit or 

process line (or groups of units or lines) that has a 

separate control or abatement technology, and then the 

emissions for all such units or lines are summed to 

determine the overall N2O emissions for the facility. For 

consistency with these amendments, we are also amending 40 
Page 26 of 246 

CFR 98.54(a), 98.56(j), and 98.57(c) for monitoring and 

QA/QC, reporting, and recordkeeping, respectively. 

We are amending 40 CFR 98.53(b)(1) to address 

performance testing when a group of adipic acid production 

units share a common abatement technology or emission 

point. 

We are amending Equation E-3 of subpart E to 

accommodate N2O abatement technology located after the 

emission test (sampling) point and re-designating it as 

Equation E-3a of subpart E. There are three ways in which 

abatement technology can be employed. Equation E-3a of 

subpart E is for one N2O abatement technology. We are 

amending Equation E-3a of subpart E further so that the 

annual adipic acid produced by adipic acid unit “z” (Pz) is 

used rather than annual adipic acid produced by unit(s) for 

which N2O abatement technology “N” is operating (Pa,N). 

Also, the summation was removed. 

We are adding Equation E-3b of subpart E to 

accommodate multiple N2O abatement technologies in series 

and we are adding Equation E-3c of subpart E to accommodate 

multiple N2O abatement technologies in parallel. We are 

also adding a new Equation E-3d of subpart E for facilities 

that do not have any N2O abatement technology located after 

the test (sampling) point. 
Page 27 of 246 

We are adding Equation E-4 of subpart E to sum the 

emissions from Equations E-3a through E-3d of subpart E for 

each adipic acid production unit “z”. 

We are amending the language in 40 CFR 98.54(a)(3) and 

98.56(k) regarding the Administrator approved alternative 

method to clarify that this alternative method is for 

determining N2O emissions rather than N2O concentration. 

Also, we are amending the language in 40 CFR 98.54(a)(1), 

(e) and (f) to clarify the location of the test (sampling) 

point used for the performance test and to clarify that the 

performance test should be conducted when the process is 

operating normally. As promulgated, the language can be 

misconstrued that EPA is requiring the facility to shut 

down any N2O abatement technology during the performance 

testing. This was not intended because many, if not all, 

of the N2O abatement technologies in use must be operated at 

all times that the adipic acid facility is operated to 

control emissions of NOx in order to comply with state and 

federal regulations limiting NOx emissions. The amendments 

clarify that testing can occur before or after N2O abatement 

technology as long as the destruction efficiency of the N2O 

abatement technology is properly accounted for and adipic 

acid production is quantified while abatement equipment is 

operating. Finally, we are clarifying under 40 CFR 
Page 28 of 246 

98.57(f) that facilities should retain records of all data 

collected during performance tests, not just the calculated 

emission factor. This clarification is consistent with the 

general recordkeeping requirements in 40 CFR 

98.3(g)(2)(ii). 

Major changes since proposal are identified in the 

following list. The rationale for these and any other 

significant changes can be found in this preamble or the 

Response to Comments: Technical Corrections, Clarifying and 

Other Amendments (see EPA-HQ-OAR-2010-0109). 

• Language was added to 40 CFR 98.53(b)(1) to address 

performance testing when multiple adipic acid 

production units exhaust to a common emission point. 

• Changed the emission factor in Equation E-1 of subpart 

E from EFN2O,N to EFN2O,z to eliminate confusion. 

• Changed the description of the emission factor, EFN2O,z

from “Average facility-specific N2O emission factor for 

each adipic acid production unit (lb N2O generated/ton 

adipic acid produced)” to “Average facility-specific 

N2O emission factor for each adipic acid production 

unit “z” (lb N2O/ton adipic acid produced).” 

• Changed the terms “waste gas stream” and “air stream” 

to “vent stream” at 40 CFR 98.53(b)(1) and 

98.53(g)(1). 

• Edited Equation E-1 and Equation E-3a of subpart E to 

include changes above. 

• Added Equation E-3b, Equation E-3c, Equation E-3d and 

Equation E-4 of subpart E. 

2. Summary of Comments and Responses

This section contains a brief summary of major 

comments and responses. Several comments were received on 
Page 29 of 246 

this subpart. Responses to additional significant comments 

received can be found in Response to Comments: Technical 

Corrections, Clarifying and Other Amendments (see EPA-HQOAR-2010-0109). 

Comment: One commenter raised the issue that there 

are situations where multiple adipic acid production units 

exhaust to a common abatement technology or emission point 

and should be addressed during the performance test. 

Response: EPA has added language at 40 CFR 

98.53(b)(1) to address performance testing for a group of 

adipic acid production units exhausting to a common 

abatement technology or emission point and for other 

possible situations that were not accurately addressed by 

the proposed Equation V-3a of subpart V (abatement 

technologies used in series and backup abatement 

technologies operated periodically. We are aware of at 

least one facility where multiple units exhaust through a 

common abatement technology. 

Comment: One commenter suggested that the subscript 

letter “N” in the term EFN2O,N used in Equation E-1 of 

subpart E be explained and changed to avoid confusion with 

the term “N” in Equations E-2 and E-3a. The commenter also 

suggested that the word “generated” be struck from the 

definition of EFN2O,N in Equation E-1 of subpart E to reflect 
Page 30 of 246 

that the emission factor may now be determined either 

before or after abatement. If measured after abatement, 

EFN2O,N represents the controlled emission rate instead of 

the amount of N2O generated. The commenter suggested a 

similar change to Equations E-3a and E-3b of subpart E 

where the terms EFN2O,N and EFN2O respectively, are used. 

Response: EPA agrees that the subscript letter “N” in 

the term EFN2O,N used in Equation E-1 of subpart E could be 

confused with the term “N” used in Equations E-2 and E-3a 

of subpart E. Therefore, the subscript “N” has been 

changed to subscript “z” in Equation E-1 of subpart E. EPA 

also agrees that EFN2O,N represents the controlled emission 

rate instead of the amount of N2O generated, if the test 

point is located after the abatement technology. 

Therefore, the definition of EFN2O,z has been revised to be 

the average facility-specific N2O emission factor for each 

adipic acid production unit “z”, in units of lb N2O/ton 

adipic acid produced. 

EPA also removed the word “generated” in Equations E3a and E-3b of subpart E for the definitions of the terms 

EFN2O,N and EFN2O, respectively. 

Comment: One commenter agreed with the proposed 

amendments to correctly calculate emissions in which an 
Page 31 of 246 

abatement technology is not operated 100 percent of the 

time. The commenter requested that additional changes be 

made to Equation E-3a in 40 CFR 98.53(g)(1). The commenter 

suggested the use of Pa (annual adipic acid produced for 

unit a) instead of PaN (annual adipic acid produced by 

unit(s) for which N2O abatement technology “N” is 

operating), and noted that the summation over the range of 

1 to N should include only the term (1-(DFN*AFN)), to 

accurately represent the effect of multiple abatement 

devices on each unit. 

Response: EPA agrees that annual adipic acid produced 

from unit “z” (Pz) should be used rather than annual adipic 

acid produced by unit(s) for which N2O abatement technology 

“N” is operating (Pa,N). These changes have been made in 

the final rule. 

D. Subpart H – Cement Production

1. Summary of Final Amendments and Major Changes Since 

Proposal.

We are amending 40 CFR 98.84(b) to correct the most 

recent ASTM standard, to ASTM C114-09 rather than C114-07, 

for determining the weight fraction of magnesium oxide 

(MgO) and calcium oxide (CaO) in clinker. In addition we 

have learned through questions from reporters, that for 

some facilities it is more efficient to sample clinker for 
Page 32 of 246 

the weight fraction of total MgO and CaO as it exits the 

kiln rather than from bulk storage. Some facilities do 

perform this analysis on clinker on a daily basis. We are 

amending the rule to allow facilities the option to 

determine a monthly value based on the arithmetic average 

of the daily samples. 

Through reporters we have also learned that facilities 

use direct measurement in conjunction with other factors 

(e.g. kiln feed) to determine clinker production. These 

procedures are verified periodically for accuracy. We are 

amending 40 CFR 98.84(d) to allow facilities to use these 

existing procedures for measuring clinker produced and 

verify those on a monthly basis. Facilities are already 

required to measure clinker on a monthly basis. Concurrent 

with this change, we are amending 40 CFR 98.86(b) so that 

facilities that do not estimate combined process and 

combustion emissions using continuous emission monitoring 

systems (CEMS) will be required to report the kiln specific 

feed-to-kiln ratios used to calculate clinker produced for 

EPA verification of emissions associated with clinker 

production. For consistency, we are clarifying 40 CFR 

98.84(e) to allow similar flexibility in determination of 

cement kiln dust produced. 
Page 33 of 246 

Further, we understand from facilities’ questions that 

an analysis of the organic carbon contents of raw materials 

could be determined from a composite sample of the kiln 

feed or from sampling each raw material in the kiln feed 

depending on the existing sampling methods and raw material 

storage procedures at the facility. We are amending the 

calculation and monitoring procedures in 40 CFR 98.83(d)(3) 

and 98.84(c) to allow facilities the option to use either 

sampling procedure for estimating carbon dioxide (CO2) 

emissions from raw materials. 

We are also correcting and clarifying the 

recordkeeping requirements under 40 CFR 98.87(a) and (b) 

for facilities with CEMS and for facilities without CEMS. 

In Part 98, the recordkeeping requirements listed under 40 

CFR 98.87(a)(1) and (a)(2) should have been listed under 40 

CFR 98.87(b). Facilities using CEMS to estimate combined 

process and combustion CO2 emissions from kilns do not need 

to calculate process emissions using the clinker based 

emissions methodology provided in Subpart H and, therefore, 

would not have the relevant records requested in 40 CFR 

98.87(a)(1) and (a)(2). 

Major changes since proposal are identified in the 

following list. The rationale for these and any other 

significant changes can be found in this preamble or the 
Page 34 of 246 

Response to Comments: Technical Corrections, Clarifying and 

Other Amendments document (see EPA-HQ-OAR-2010-0109). 

• Clarifying the cement kiln dust (CKD) monitoring 

requirements in 40 CFR 98.84(e); 

• Changing cement production reporting requirements 

under 40 CFR 98.86 to require annual, facility-wide 

cement production instead of monthly, kiln-specific 

cement production; and 

2. Summary of Comments and Responses

This section contains a brief summary of major 

comments and responses. Several comments were received on 

this subpart. Responses to additional significant comments 

received can be found in Response to Comments: Technical 

Corrections, Clarifying and Other Amendments document (see 

EPA-HQ-OAR-2010-0109). 

Comment: One commenter expressed concern that the 

monthly verification of the feed-to-clinker ratio, required 

under 40 CFR 98.94(d), is unduly burdensome. The commenter 

suggested that EPA change subpart H to require quarterly 

verification instead of monthly.

Response: Because subpart H requires cement 

manufacturers to report clinker production on a monthly 

basis, we are requiring facilities that estimate clinker 

production using a feed-to-clinker ratio to verify the 

accuracy of that ratio also on a monthly basis. We 

provided cement manufacturers the option to use a feed-to-
Page 35 of 246 

clinker ratio instead of direct clinker measurement to 

provide flexibility and consistency with current industry 

practices. We note the commenter’s concern regarding the 

burden of monthly verification. However, other industry 

comments generally support this requirement. 

Comment: One commenter stated that the CKD 

measurement requirements under 40 CFR 98.84(e) should be 

revised to be consistent with the clinker measurement 

requirements under 40 CFR 98.84(d). Specifically, 40 CFR 

98.84(d) allows facilities to determine monthly clinker 

quantities by either reconciling weigh hopper or belt weigh 

feeder measurements against inventory measurements, or by 

direct weight measurement of raw feed and applying a feedto-clinker ratio. Meanwhile, 40 CFR 98.84(e) requires 

facilities to determine quarterly CKD quantities by direct 

weight measurement. The commenter points out that the CKD 

quantity has a lesser impact on CO2 emission calculations 

than the clinker quantity. Therefore, the rule should not 

have more stringent measurement requirements for CKD than 

for clinker. The commenter also states that direct weight 

measurement devices should not be required to be installed 

if they are currently not being utilized at the facility, 

and requests that facilities be permitted to use the same 
Page 36 of 246 

methods currently in place for accounting purposes to 

determine the quantity of CKD not recycled to the kiln. 

Response: The rule currently allows for the type of 

flexibility that the commenter is requesting. The rule 

lists direct weight measurement as an example technique 

that may be used; however, the examples provided in the 

rule are not an exhaustive list. Facilities should 

determine the quantity of CKD not recycled to the kiln for 

each kiln using the same plant techniques used for 

accounting purposes. We have revised the language in 40 

CFR 98.84(e) to clarify this flexibility. 

Comment: Two commenters noted that reporting 

requirements in 40 CFR 98.86(a)(2) and 98.86(b)(3) require 

cement manufacturers to report monthly cement production 

from each kiln at the facility. The commenters pointed out 

that cement kilns produce clinker – not cement. The 

clinker from each cement kiln is subsequently sent to a 

mill and pulverized into a fine powder, and mixed with 

other ingredients to produce cement. Plants that operate 

multiple kilns may combine the clinker from all kilns and 

store the combined clinker before feeding it to the cement 

mill. Because of the variability of the amount of clinker 

produced by different kilns, and the varying methods of 

storage, the commenters proposed that EPA require cement 
Page 37 of 246 

manufacturers to report the total quantity of cement 

produced by the facility on an annual rather than monthly, 

kiln-specific basis. 

Response: EPA agrees with the commenter that the 

requirements in 40 CFR 98.86(a)(2) and 98.86(b)(3) are 

inconsistent with cement plant manufacturing practices, and 

should not be required on a kiln-specific basis. In 

addition, we agree that due to the variations in storage 

time between clinker production and cement production, 

cement production data are not needed on a monthly basis. 

This reporting requirement was added for verification of 

reported emissions, not calculating emissions. Therefore, 

we have revised the rule to require facilities to report 

cement production on an annual, facility-wide basis. 

E. Subpart K – Ferroalloy Production 

1. Summary of Final Amendments and Major Changes Since 

Proposal.

We are amending 40 CFR 98.112(a) to be consistent with 

the requirement described in 40 CFR 98.113(d) to calculate 

methane (CH4) emissions from an electric arc furnace (EAF) 

used for the production of all ferroalloys for which an 

applicable CH4 emission factor is provided in the rule. 

These alloys and the associated CH4 emission factors are 

listed in Table K-1 to subpart K. Subpart K in Part 98 
Page 38 of 246 

contained calculation and reporting procedures for 

quantifying process CH4 emissions from all ferroalloys 

listed in Table K-1 to subpart K, but CH4 was inadvertently 

not included in the GHGs to Report section. 

We are also amending the introductory language for 40 

CFR 98.113 to clarify the applicability of the procedures 

for calculating CO2 and CH4 emissions in that section. 

Finally, we are amending the language in 40 CFR 98.116 to 

clarify that the data reporting requirements in 40 CFR 

98.116(b) are for each EAF and those in 40 CFR 98.116(d)(1) 

and (e)(1) are for any ferroalloy product identified in 40 

CFR 98.110. We are also amending 40 CFR 98.116(d) to 

correct an incorrect cross-reference to 40 CFR 98.36. 

2. Summary of Comments and Responses

EPA did not receive any comments on the proposed 

amendments to subpart K and is finalizing the amendments to 

this subpart as proposed. 

F. Subpart N – Glass Production

1. Summary of Final Amendments and Major Changes Since 

Proposal.

We are amending subpart N to add CO2 emission factors 

to Table N-1 to subpart N for barium carbonate, potassium 

carbonate, lithium carbonate, and strontium carbonate. 

These raw materials were not included in Part 98, but EPA 
Page 39 of 246 

has since learned that they are also used by the glass 

industry. EPA is also amending 40 CFR 98.144(b) to allow 

for an additional method for determining the carbonate 

mineral mass fraction of raw materials used in glass 

production. Specifically, in addition to ASTM D3682-01, 

reporters can also use ASTM D6349-09, “Standard Test Method 

for Determination of Major and Minor Elements in Coal, 

Coke, and Solid Residues from Combustion of Coal and Coke 

by Inductively Coupled Plasma—Atomic Emission 

Spectrometry.” We are also amending the introductory 

language to 40 CFR 98.146(a) to correct an incorrect crossreference to 40 CFR 98.36 and to clarify in 40 CFR 

98.146(a)(2) that reporting of glass production is by 

furnace and from all furnaces combined, consistent with the 

calculation methods. We are amending 40 CFR 98.146(b)(7) 

and (9) to correct typographical errors. 

Major changes since proposal are identified in the 

following list. The rationale for these changes can be 

found in this preamble. 

• Added an emission factor for lithium carbonate 

• Added an emission factor for strontium carbonate 

• Removed the requirement for analysis by an 

“independent certified laboratory.” When the final 

subpart N was published on October 30, 2009, EPA 

agreed with commenters that analyses do not have to be 

performed by an independent certified laboratory, but 

this language inadvertently remained in subpart N. 
Page 40 of 246 

2. Summary of Comments and Responses

This section contains a brief summary of major 

comments and responses. One comment letter was received on 

this subpart. 

Comment: One commenter asked that emission factors 

for lithium carbonate and strontium carbonate be added to 

subpart N, in addition to those being added for barium 

carbonate and potassium carbonate. 

Response: EPA has added these two compounds to the 

final subpart N. EPA was not previously aware of use of 

these carbonates in glass production in the United States 

during the initial proposal of the rule. While less 

common, these carbonates are used in glass production to 

add different properties to glass products and EPA 

therefore agrees that these emission factors should be 

included in the final rule. 

G. Subpart O - HCFC-22 Production and HFC-23 Destruction 

1. Summary of Final Amendments and Major Changes Since 

Proposal.

We are amending 40 CFR 98.154(k), the requirement to 

monitor HFC-23 emitted from process vents, to refer to 

Equation O-7 of subpart O rather than Equation O-6 of 

subpart O. In 40 CFR 98.154(k), (l), and (o) and in 40 CFR 
Page 41 of 246 

98.156(b), we are amending the language so that the term 

“destruction device” is used rather than the narrower term 

“thermal oxidizer.” 

We are amending the reporting requirements in 40 CFR 

98.156(c) and (d) to clarify that only facilities that are 

required to recalculate the destruction efficiency of their 

destruction device under 40 CFR 98.154(l) must report the 

flow rate of HFC-23 being fed into the destruction device, 

the flow rate at the outlet of the destruction device, and 

the emission rate of the device. In addition, such 

facilities will be required to report the newly calculated 

DE of the device, the HFC-23 concentration measurement used 

in the DE calculation, and whether 40 CFR 98.154(l)(1) or 

(l)(2) was used for the calculation. Under these two 

paragraphs, other HFC-23 destruction facilities will be 

required to report only the results of their annual 

measurement of the HFC-23 concentration at the outlet of 

the destruction device. 

We are amending the reporting requirements in 40 CFR 

98.156(e) to clarify that the one-time report for HFC-23 

destruction facilities is due by March 31, 2011 or within 

60 days of commencing HFC-23 destruction. The amendment 

was necessary because it was not clear when the one-time 

report must be submitted. The amendment will make the due 
Page 42 of 246 

date in 40 CFR 98.156(e) consistent with the due date for a 

similar report required in Subpart OO. 

In general, these amendments to the reporting 

requirements for HFC-23 destruction facilities make them 

consistent with the monitoring requirements for these 

facilities. The due dates for the one-time report are 

consistent with those elsewhere in Part 98 for the source 

categories that are required to begin monitoring in 2010. 

2. Summary of Comments and Responses

EPA did not receive any comments on the proposed 

amendments to subpart O and is finalizing the amendments to 

this subpart as proposed. 

H. Subpart P - Hydrogen Production 

1. Summary of Final Amendments and Major Changes Since 

Proposal.

We are amending the definition of the source category 

in 40 CFR 98.160(c) to clarify that hydrogen production 

facilities located within other facilities are also 

included in the source category if they are not owned by, 

or under the direct control of, the other facility’s owner 

and operator. This clarification was necessary to correct 

a misunderstanding that the original rule text limited the 

source universe to hydrogen production facilities located 

within petroleum refineries. 
Page 43 of 246 

Broadly, we are amending subpart P to remove several 

references to “process” CO2 emissions. EPA received 

information from industry indicating that the use of the 

term “process” in the context of calculating and reporting 

CO2 emissions resulted in confusion in differentiating 

between process and combustion emissions. We are 

clarifying the text in the rule by removing references to 

the term “process” from the rule language. 

We are removing the requirements in 40 CFR 98.162(b) 

for owners or operators to report CO2, CH4 and N2O 

combustion emissions from each hydrogen production process 

unit using the emissions calculation methods in subpart C. 

This provision results in double counting of combustionrelated emissions from hydrogen production process units, 

as these combustion emissions are already accounted for 

when following the calculation methods in 40 CFR 98.163(a) 

or (b). CO2 emissions will still be reported under 40 CFR 

98.162(a) using the procedures in 40 CFR 98.163(a) or 

98.163(b). 

We are also amending language describing the 

calculation of GHG emissions from gaseous, liquid and solid 

fuels and feedstocks in 40 CFR 98.163. The clarified 

language specifies that each gaseous, liquid or solid fuel 

and feedstock will need to be calculated based on its 
Page 44 of 246 

respective equations detailed in the rule language. This 

removes the concern that the language was unclear as to 

which fuel and feedstock stream should be used to calculate 

CO2 emissions. 

Lastly, we are amending 40 CFR 98.166(c) to strike 

“quarterly” and “kg” (kilogram). Some facilities subject 

to subpart P may also be subject to subpart PP – Suppliers 

of Carbon Dioxide. Quarterly reporting of CO2 quantities 

(in kilograms) was not consistent with subpart PP. 

2. Summary of Comments and Responses

All comments received on the proposed amendments to 

subpart P were supportive and EPA is finalizing the 

amendments to this subpart as proposed. 

I. Subpart Q – Iron and Steel Production

1. Summary of Final Amendments and Major Changes Since 

Proposal.

We are amending the subpart Q requirements regarding 

emissions from flares to clarify the requirements and 

correct certain deficiencies in the rule pertaining to 

flares burning off-gases from argon-oxygen decarburization 

(AOD) and other decarburization processes. Section 

98.172(b) of Part 98 required reporting of CO2 emissions 

from flares using procedures from subpart Y (Petroleum 

Refineries), without distinguishing flares burning off-
Page 45 of 246 

gases from AOD or other decarburization processes from 

other types of flares. 

The referenced equations in subpart Y and the further 

instructions in 40 CFR 98.172(b) are applicable to 

estimating emissions from burning coke oven gas or blast 

furnace gas, but are not applicable for estimating 

emissions from flares burning the off-gases from AOD or 

other decarburization processes. We are, therefore, 

amending the language in 40 CFR 98.172(b) to clarify that 

for subpart Q facilities, flare emissions must be estimated 

for flares burning blast furnace gas or coke oven gas. 

Similarly, we are amending the introductory text in 40 CFR 

98.175 to specify that the missing data procedures in 

subpart Y (Petroleum Refineries) at 40 CFR 98.255(b) must 

be followed for flares burning coke oven gas or blast 

furnace gas. We are also amending the introductory text 

for the data reporting requirements in 40 CFR 98.176 to 

include flares burning coke oven gas or blast furnace gas. 

Subpart Q in Part 98 also referenced incorrect 

equations from subpart Y. We are amending and correcting 

the references in 40 CFR 98.172(b) to the subpart Y flare 

equations. Equations Y-2 and Y-3 of subpart Y are the 

correct equations; the promulgated subpart Q of subpart Q 

incorrectly referenced Equation Y-1 of subpart Y. 
Page 46 of 246 

We are amending the reporting requirements in 40 CFR 

98.176(e)(3) to clarify that fuel consumption needs to be 

reported separately for each type of fuel and other process 

input and output material. We are also adding paragraphs 

(g) and (h) to 40 CFR 98.176. Paragraph (g) requires 

facilities to report the annual amount of coal charged to 

coke ovens because it is used to estimate CO2 emissions from 

coke pushing. Paragraph (h) incorporates the same 

reporting requirements specified in 40 CFR 98.256(e) of 

subpart Y (Petroleum Refineries) for flares burning coke 

oven gas or blast furnace gas. 

We are amending the recordkeeping requirements in 40 

CFR 98.177(d) to clarify the units and processes for which 

annual operating hours need to be recorded. 

We are also amending the requirements in the 

promulgated rule to estimate GHG emissions from AOD vessels 

to clarify that they also apply to any other type of vessel 

used with the primary intent of removing carbon from molten 

steel (decarburization), such as vacuum oxygen 

decarburization. Because of the clarification noted above 

to include all types of decarburization vessels used 

primarily to remove carbon, we are replacing the term 

“argon-oxygen decarburization vessels” with the term 

“decarburization vessels” throughout subpart Q and 
Page 47 of 246 

replacing the definition of “argon-oxygen decarburization 

vessels” with a definition for “decarburization vessels” in 

order to maintain reporting of the CO2 emissions from these 

vessels. 

In response to comments, we are clarifying the 

definition of “decarburization vessels” to include only 

those decarburization vessels, such as AOD and vacuum 

oxygen decarburization vessels, used with the primary 

intent of removing carbon from the steel. We are also 

delaying the reporting of GHG emissions from 

decarburization vessels that are not AOD vessels until 

reports submitted in 2012, instead of requiring reporting 

with the first reports submitted to EPA in March 2011. 

Major changes since proposal are identified in the 

following list. The rationale for these and any other 

significant changes can be found in this preamble or the 

Response to Comments: Technical Corrections, Clarifying and 

Other Amendments document (see EPA-HQ-OAR-2010-0109). 

• Clarifying the definition of “decarburization vessels” 

to include only those decarburization vessels used 

with the primary intent of removing carbon from the 

steel. 

• Delaying the reporting of GHG emissions from 

decarburization vessels that are not AOD vessels until 

reports submitted in 2012. 

2. Summary of Comments and Responses
Page 48 of 246 

This section contains a brief summary of major 

comments and responses. Several comments were received on 

this subpart. Responses to additional significant comments 

received can be found in Response to Comments: Technical 

Corrections, Clarifying and Other Amendments document (see 

EPA-HQ-OAR-2010-0109). 

Comment: We received three comments on our proposal 

to clarify the definition of decarburization vessels to 

include all decarburization vessels rather than just argonoxygen decarburization (AOD). Two commenters noted that 

the proposal was not merely a technical correction or 

clarification, but was instead a substantive change to 

subpart Q as promulgated. According to the commenters, the 

new definition of decarburization vessel, which includes a 

list of the covered processes and the phrase "or other 

decarburization vessels," was too broad and inclusive. The 

commenters noted that most steel plants, whether integrated 

or electric arc furnace producers, employ several different 

kinds of refining processes to improve the quality of the 

steel produced, and some of these refining processes, such 

as AODs, are primarily intended to reduce carbon. However, 

the commenters stated that other processes, such as vacuum 

degassing, electro-slag remelting, and vacuum-arc 

remelting, are primarily intended to reduce dissolved gases 
Page 49 of 246 

such as hydrogen, nitrogen, and oxygen in the molten steel, 

and carbon reduction is only incidental. According to the 

commenters, making these processes subject to subpart Q 

would require facilities to make numerous adjustments to 

their monitoring plans and conduct additional sampling. 

For these reasons, the commenters believe that the proposed 

amendment would add significant new requirements and 

represent a substantive change rather than being merely a 

clarification. One commenter argued that the time and 

effort to verify GHG emissions from vacuum degassing would 

be burdensome, estimating that it would increase the 

resources needed to comply with subpart Q by 50 percent. 

The commenter stated that the added burden of data 

collection, measurements, recordkeeping, and reporting of 

these emissions is not justified by the addition of vacuum 

degassing and other refining operations to the reporting 

requirements. 

Two of the commenters estimated that the additional 

processes included in the proposed amendment contribute 

“substantially less than 1 percent” of the emissions from 

the sector. Another commenter estimated they contributed 

only 0.02 percent of the emissions. The same commenter 

argued that because these emissions are relatively 

insignificant and would be extremely difficult to quantify 
Page 50 of 246 

for reporting purposes, they should continue to be excluded 

from reporting obligations. The commenter also rejected 

the rationale that emissions from all decarburization 

vessels should be reported because EPA is also proposing to 

limit reporting of emissions from flares to those burning 

coke oven gas or blast furnace gas only (an amendment that 

the commenter supports), which would obviate reporting of 

vacuum degasser flare emissions. The commenter estimated 

that the emissions are so low they would be difficult to 

detect, and measuring such emissions through either the 

carbon-mass balance approach or a site-specific emission 

factor would be burdensome and potentially infeasible. The 

commenter concluded that EPA has not provided a rational 

basis for inclusion of decarburization vessels within the 

GHG Reporting Program. 

Two commenters recommended that if EPA proceeds by 

adding a definition for “decarburization vessel,” the 

definition should be revised. One commenter suggested that 

the definition be clarified such that it includes only 

vessels for which the primary purpose is decarburization. 

The other commenter asked that it be revised to read “any 

vessel used to further refine molten steel with the primary 

intent of reducing carbon content of the steel that also 

requires flaring the off-gas to oxidize CO to CO2.” 
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All three commenters stated that if EPA chooses to 

include all decarburization vessels as proposed, they 

should not be included in the reports submitted to EPA in 

2011. Two commenters explained that making this change 

retroactive to data collection in 2010 is untenable because 

companies were obligated to develop comprehensive GHG 

Monitoring Plans in early 2010 and to begin recordkeeping 

in January 2010 in order to be able to report for the 

entire 2010 reporting year by March 2011. 

One commenter stated that by expanding the 

decarburization vessel definition in Subpart Q to include 

vacuum degassing and other refining operations beyond AODs, 

facilities with these operations will need to make 

adjustments to their monitoring plans, conduct additional 

sampling of inputs and outputs for these operations, make 

programmatic modifications to tracking software, and retrain employees. The commenter claimed that it will be 

impossible to collect the necessary samples of steel and 

dust or sludge and perform analyses representative of the 

months that have elapsed since the beginning of 2010 in 

order to perform a mass balance, and it is also unrealistic 

to expect companies to consider the option of establishing 

a site-specific emission factor for these units because of 

all of activities that would be required to perform 
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testing. The commenter recommended that EPA follow the 

course set in its July 12, 2010 final rule notice adding 

four new source categories to Part 98 (75 FR 39735). The 

commenter said that EPA recognized in that notice that it 

would be unrealistic to require those operations to report 

emissions for 2010 and made these new rules effective with 

the data collection in 2011. 

Two commenters recommended that if EPA proceeds with 

the proposed changes, those requirements should be 

effective no sooner than 2011 and should be reportable in 

March 2012. One commenter argued that by amending a rule 

to include data acquisition and management after a 

reporting period has already begun is arbitrary and 

capricious and will significantly add to the burden the 

regulated community faces when attempting to collect 

meaningful data. The commenter stated that any such 

amendment should be prospective in nature and not impact 

calculations and sampling already underway. 

Response: After consideration of these comments, we 

agree that the proposed new definition of “decarburization 

vessels” was too broad and would include certain steel 

refining processes that were not intended (i.e., those 

whose primary purpose is not removal of carbon). Some of 

the additional processes cited by the commenters have a 
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primary purpose to remove dissolved gases, and although 

some carbon may be incidentally removed, the CO2 emissions 

from these processes are a small percent of total GHG 

emissions from iron and steel making. Because the change 

in carbon content of the steel is so small, it is difficult 

to accurately quantify the emissions by a carbon balance, 

and it is problematic to measure them because of the 

sampling and other difficulties mentioned by the 

commenters. Consequently, we are revising the definition 

of “decarburization vessels” to include those for which the 

primary purpose is removal of carbon, including but not 

limited to AOD and vacuum oxygen decarburization (VOD). We 

are not adding the suggested revision that the definition 

should include only those decarburization vessels equipped 

with flares because not all AOD and VOD vessels are 

equipped with flares. The revised definition makes the 

amendment a technical clarification that is more consistent 

with the final rule as originally promulgated. 

We also agree that additional time would be required 

to gather the data to report emissions from decarburization 

vessels other than AOD vessels, and we are amending the 

reporting requirements so that these emissions are reported 

beginning in March 2012 for the year 2011. However, the 

final amendments will not require a delay in the reporting 
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period for AOD vessels because facilities with AOD vessels 

have known since the original promulgation of subpart Q 

that these decarburization vessels would be included in the 

reporting for 2010. 

J. Subpart S – Lime Manufacturing

1. Summary of Final Amendments and Major Changes Since 

Proposal.

We are amending the cross reference to 40 CFR 

98.193(b)(1) in the introductory language to 40 CFR 98.195; 

it incorrectly referenced 40 CFR 98.193(b)(2). 

We are also amending the terminology used throughout 

subpart S to clarify whether the calculation and reporting 

requirements are referring to calcined byproducts and waste 

materials by adding the word “calcined” to the lime 

byproduct and waste terminology, as needed. We are also 

amending the terminology in the subpart to clarify when the 

calculation and reporting requirements apply to lime 

products that are produced at the facility. 

2. Summary of Comments and Responses

EPA did not receive any comments on the proposed 

amendments to subpart S and is finalizing the amendments to 

this subpart as proposed. 

K. Subpart V – Nitric Acid Production
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1. Summary of Final Amendments and Major Changes Since 

Proposal.

We are amending 40 CFR 98.223 and 98.224 to clarify 

how N2O emissions are to be measured if a facility has an 

N2O abatement device. The first amendment clarifies the 

location of the test (sampling) point used for the 

performance test in several paragraphs in 40 CFR 98.223. 

As promulgated, the language could be misconstrued to 

require the nitric acid facility to shut down any N2O 

abatement technology during the performance testing. This 

was not the intention as many, if not all, of the N2O 

abatement technologies in use must be operated at all times 

that the nitric acid facility is operated to control 

emissions of NOx in order to comply with state and federal 

regulations limiting NOx emissions. The amendments will 

clarify that testing can occur before or after N2O abatement 

technology as long as the testing properly accounts for 

destruction efficiency. 

We are amending Equation V-3 of subpart V to 

accommodate N2O abatement technology located after the 

emission test (sampling) point, and re-designating it as 

Equation V-3a of subpart V. Equation V-3a is also 

corrected so that the term on the left-hand side of the 

equation is changed from EFN2Ot to EN2Ot. 
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There are three ways in which abatement technology can 

be employed. Equation V-3a of subpart V is for one N2O 

abatement technology. We are adding Equation V-3b of 

subpart V to accommodate multiple N2O abatement technologies 

in series and we are adding Equation V-3c of subpart V to 

accommodate multiple N2O abatement technologies in parallel. 

We are also including a new Equation V-3d of subpart V 

for facilities that do not have N2O abatement technology 

located after the test (sampling) point. 

In addition, we are clarifying in 40 CFR 98.223 that 

the annual performance test must be conducted for each 

nitric acid train, consistent with the equations in 40 CFR 

98.223. Additional changes were made to the monitoring 

requirements in 40 CFR 98.224 to conform to the changes in 

the calculation methods in 40 CFR 98.223. We are amending 

40 CFR 98.224(a)(1) to clarify when during a nitric acid 

production campaign facilities must conduct the performance 

test. 

We are also amending the language concerning the 

Administrator-approved alternative method for determining 

N2O emissions in 40 CFR 98.223(a)(2)(ii), 98.224(a)(3), and 

98.226(n). The alternative method is for determining N2O 

emissions rather than N2O concentration or an N2O emission 
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factor. The language has been changed to correct this 

point. 

We are amending the data reporting requirements in 40 

CFR 98.226(g) and (m) to be consistent with the calculation 

methods which are for each nitric acid train, not the 

facility. 

Major changes since proposal are identified in the 

following list. The rationale for these and any other 

significant changes can be found in this preamble or the 

Response to Comments: Technical Corrections, Clarifying and 

Other Amendments document (see EPA-HQ-OAR-2010-0109). 

• Changed the description of the emission factor, EFN2Ot

from “lb N2O generated/ton nitric acid produced, 100 

percent acid basis” to “lb N2O/ton nitric acid 

produced, 100 percent acid basis.” 

• Changed the term “air stream” to “vent stream” at 40 

CFR 98.223(g)(1). 

• Added Equations E-3b and E-3c of subpart E. 

2. Summary of Comments and Responses

This section contains a brief summary of major 

comments and responses. Two sets of comments were received 

on this subpart. Responses to additional significant 

comments received can be found in Response to Comments: 

Technical Corrections, Clarifying and Other Amendments 

document (see EPA-HQ-OAR-2010-0109). 
Page 58 of 246 

Comment: One commenter noted that the regulation for 

Adipic Acid is similar to the regulation for Nitric Acid 

and asked that EPA compare the clarifications made to each 

of these subparts for consistency. 

Response: EPA agrees that there are similarities 

between the two subparts. Although the commenter did not 

provide specific examples for subpart V, EPA reviewed the 

commenter’s suggested clarifications for subpart E and made 

the following comparable changes to subpart V: 

EPA agrees with the change to the term “air stream.” 

The term has been changed to “vent stream” in 40 CFR 

98.223(g)(1) as this is more consistent with terminology 

used to identify testing locations at current facilities. 

EPA agrees that there could be situations at nitric 

acid facilities where multiple trains exhaust to a common 

abatement technology. Language has been added to 

98.223(b)(1) to add flexibility for facilities that have a 

group of trains that exhaust to the same abatement 

equipment. Further, the equations do not correctly address 

situations in which a facility has separate N2O control or 

abatement technology on the separate train or process 

lines, back-up controls in parallel on a single train, and 

these technologies are not operated 100 percent of the time 

(i.e. operated during maintenance operations on primary 
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controls). We have learned that some facilities could have 

existing controls (e.g. NSCR) and may apply additional 

controls during the production process (e.g secondary 

catalysts in oxidation reactor) in the future. 

In these circumstances, the current equations will not 

provide an accurate calculation of N2O emissions. To 

address the three ways in which abatement technology can be 

employed EPA has revised 40 CRR 98.223 to include 

calculation methods to accurately account for these 

possible abatement applications. The current Equation V-3a 

of subpart V is for one N2O abatement technology. EPA has 

added Equation V-3b and V-3c to accommodate situations 

where multiple N2O abatement technologies operate in series 

and or multiple abatement technologies in parallel, 

respectively. Equation V-3d of subpart V addresses the 

situation when facilities that do not have N2O abatement 

technology. 

Comment: According to one commenter, facilities do 

not have information to determine a point during the 

campaign which is representative of the average emissions 

over the entire campaign. The commenter requested that 40 

CFR 98.224(a)(1) be modified to ensure that performance 

tests are conducted during representative operations while 
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enabling operating facilities to document and demonstrate 

compliance with this objective. 

Response: The purpose of this language was to capture 

emissions data when the process was operating normally. 

This requirement is to ensure that the emission factor 

developed through this performance test is an accurate 

depiction of the quantity of N2O emitted per quantity of 

nitric acid produced over the course of an entire year. A 

campaign was used as a reference due to concerns that N2O 

rates from nitric acid plants are somewhat below average at 

the beginning of a campaign and above average at the end of 

a campaign. Testing during either of those times could 

result in an emission factor developed during nonrepresentative conditions. For example, at the end of a 

campaign, the age of the catalyst may influence emissions. 

As long as the choice of the timing of the testing is 

documented and the methods used to determine the timing are 

documented, this requirement is met. EPA has clarified 

“average emissions over the entire campaign” to “average 

emissions rate from nitric acid campaigns” as it is the 

emissions rate that is obtained during the performance test 

and a facility may run more than one production campaign 

over a reporting year. EPA does not agree that the 

additional changes recommended are needed. 
Page 61 of 246 

The rule offers flexibility in determining the timing 

of the performance testing. Facilities may refer to 

literature and continuous monitoring data from similar 

facilities in other countries. This literature and data 

could be used to determine an appropriate test point from a 

representative or typical nitric acid campaign. The rule 

provides facilities flexibility on methods to determine 

this testing point. Further, facilities can also apply to 

EPA to use alternative methods for determining N2O 

emissions. 

L. Subpart Z – Phosphoric Acid Production

1. Summary of Final Amendments and Major Changes Since 

Proposal.

We are renumbering Equation Z-1 as Z-1a of subpart Z 

and adding a new Equation Z-1b of subpart Z. Equation Z-1b 

will be used to calculate CO2 emissions when the method used 

to analyze phosphate rock provides a direct estimate of CO2

emissions instead of just inorganic carbon content. 

We have learned from facilities that the “Phosphate 

Mining States Methods Used and Adopted by the Association 

of Fertilizer and Phosphate Chemists AFPC Manual 10th 

Edition - Version 1.9” (AFPC manual) does not currently 

contain a procedure for obtaining a representative grab 

sample of rock for testing. A recently updated version of 
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the AFPC manual, Version 1.92, does contain the appropriate 

sampling procedures. To add flexibility to the rule, we 

are amending 40 CFR 98.264(a) to allow facilities to use 

the appropriate industry consensus standards or industry 

standard practices currently available. We are also 

amending 40 CFR 98.264(a) to clarify that the grab sample 

must be collected prior to entering the mill for accurate 

analysis of inorganic carbon contents. 

We are amending 40 CFR 98.266 to correct a cross 

reference in the introductory text of that section, and to 

revise paragraph (c) to clarify that the annual arithmetic 

average percent inorganic carbon in phosphate rock is to be 

reported as the percent by weight, expressed as a decimal 

fraction. We are also adding a new paragraph (f)(9) to 40 

CFR 98.266 to specify that facilities need to report the 

total annual process CO2 emissions from the phosphoric acid 

production facility, in metric tons. Facilities must 

calculate these emissions already in 40 CFR 98.263(b)(2) 

using Equation Z-2 of subpart Z. 

Major changes since proposal are identified in the 

following list. The rationale for these and any other 

significant changes can be found in this preamble or the 

Response to Comments: Technical Corrections, Clarifying and 

Other Amendments document (see EPA-HQ-OAR-2010-0109). 
Page 63 of 246 

• Renumbered Equation Z-1 as Equation Z-1a of subpart Z. 

• Added a new Equation Z-1b of subpart Z. 

• Revised 98.364(a) and (b) to allow facilities to use 

the appropriate industry consensus standard or 

industry standard practice. 

2. Summary of Comments and Responses

This section contains a brief summary of major 

comments and responses. Several comments were received on 

this subpart. Responses to additional significant comments 

received can be found in Response to Comments: Technical 

Corrections, Clarifying and Other Amendments document (see 

EPA-HQ-OAR-2010-0109). 

Comment: One commenter requested that Equation Z-1 be 

revised to accurately reflect the output of the AFPC 

Manual’s method for the analysis of phosphate rock. 

Regarding the inorganic carbon determinations, the equation 

assumes that the AFPC Manual’s test is for inorganic carbon 

and the equation provides for calculation of CO2 emissions 

using inorganic carbon content as an input. However, the 

AFPC Manual’s test is for CO2 directly, making Equation Z-1 

of subpart Z inapplicable as written to the AFPC Manual’s 

test output. The commenter suggested a technical amendment 

to correct this minor misalignment by removing the factor 

to convert inorganic carbon to CO2 from Equation Z-1. 

Response: EPA agrees that this change is warranted. 

However, EPA has decided not to replace Equation Z-1 but to 
Page 64 of 246 

renumber Equation Z-1 as Equation Z-1a and to add the 

revised equation as Equation Z-1b. This subpart would 

still allow facilities to use other methods (e.g., sampling 

inorganic carbon content) to determine carbon content in 

addition to using analytic methods to directly measure CO2

emissions. Therefore, EPA is maintaining this flexibility 

by retaining the previous equation and adding a new one 

that can be used with the AFPC Manual. 

M. Subpart CC – Soda Ash Manufacturing

1. Summary of Final Amendments and Major Changes Since 

Proposal.

We are amending the data reporting requirements in 40 

CFR 98.296(b)(3) to clarify that the annual soda ash 

production is reported for each line, and to make the 

reporting requirements consistent with the calculation 

requirements in 40 CFR 98.293(b)(1) through (b)(3). The 

units in 40 CFR 98.296(a)(1) and 40 CFR 98.296(b)(6) are 

corrected from metric tons to short tons for consistency 

with other similar data reporting requirements. This 

change is also consistent with how facilities collect these 

data. 

We are also amending 40 CFR 98.296(b)(10) to clarify 

that the information in that paragraph is reported for each 

manufacturing line or stack, when using a site specific 
Page 65 of 246 

emission factor, and to clarify that the elements required 

by 40 CFR 98.296(b)(10)(i), (ii), and (iv) are for the 

periods during the performance test. We are also deleting 

40 CFR 98.296(b)(11)(iv), (v), and (vi) because those 

paragraphs describe missing data procedures for elements 

during the site-specific emission factor performance test 

which are not allowed to be missing per 40 CFR 98.296(c). 

2. Summary of Comments and Responses

EPA did not receive any comments on the proposed 

amendments to subpart CC and is finalizing the amendments 

to this subpart as proposed. 

N. Subpart EE – Titanium Dioxide Production

1. Summary of Final Amendments and Major Changes Since 

Proposal.

We are amending the monitoring and QA/QC reporting 

requirements in 40 CFR 98.314(e) to clarify that the 

quantity of carbon-containing waste generated from each 

titanium dioxide production line is determined on a monthly 

basis, consistent with the calculation procedures in 40 CFR 

98.313(b)(3). In addition, we are amending the data 

reporting requirements under 40 CFR 98.316(b)(9) to be 

consistent with the calculation and monitoring alternative 

requirements of 40 CFR 98.313(b)(2) and 40 CFR 98.314(c) by 

removing the restriction that the carbon content factor for 
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petroleum coke can only be from the supplier. We are also 

amending the data reporting requirements under 40 CFR 

98.316(b)(11) to clarify that they apply to each process 

line, consistent with the calculation and monitoring 

alternative requirements of 40 CFR 98.313(b)(3) and 40 CFR 

98.314(f). 

2. Summary of Comments and Responses

EPA did not receive any comments on the proposed 

amendments to subpart EE and is finalizing the amendments 

to this subpart as proposed. 

O. Subpart GG – Zinc Production

1. Summary of Final Amendments and Major Changes Since 

Proposal.

We are amending the definitions of the terms for 

(Electrode)k and (CElectrode)k in Equation GG-1 of subpart 

GG to remove the references to kilns because electrodes are 

only used in electrothermic furnaces and are not used in 

Waelz kilns. We are also amending 40 CFR 98.336(a) to 

correct a cross reference to subpart C, and to amend 40 CFR 

98.336(b)(1) to clarify that identification numbers need to 

be reported for both Waelz kilns and electrothermic 

furnaces. 

We are amending the data reporting requirements in 40 

CFR 98.336(b)(7) and (10) to clarify that the carbon 
Page 67 of 246 

content of each input to a kiln or furnace should be 

reported as a calculation parameter regardless of whether 

the data are collected from the supplier or by self 

measurement. In 40 CFR 98.336, paragraphs (b)(8) and (11) 

already require facilities to report whether carbon 

contents were determined through self measurement or based 

on reports from the supplier. 

2. Summary of Comments and Responses

EPA did not receive any comments on the proposed 

amendments to subpart GG and is finalizing the amendments 

to this subpart as proposed. 

P. Subpart HH – Municipal Solid Waste Landfills

1. Summary of Final Amendments and Major Changes Since 

Proposal.

We are making numerous clarifying amendments and 

technical corrections to subpart HH to address questions 

EPA has received about the rule’s requirements and to 

correct known errors. Amendments to the rule are also 

being made to address some of the more significant 

questions that were the result of the level of detail 

provided in the 2009 final rule. 

Source Category Definition. We are amending 40 CFR 

98.340(b) to read, “This source category does not include 

Resource Conservation and Recovery Act (RCRA) Subtitle C or 
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Toxic Substances Control Act (TSCA) hazardous waste 

landfills, construction and demolition waste landfills, or 

industrial waste landfills.” We are adding definitions 

within 40 CFR 98.348 for the terms “construction and 

demolition waste landfills” and “industrial waste 

landfills.” 

Equation HH-1. We are making the following technical 

amendments to Equation HH-1 in 40 CFR 98.343: 

• Replace the term L0 (CH4 generating potential) with the 

terms, “MCF×DOC×DOCF×F×16/12,” (where MCF is the CH4

correction factor; DOC is the degradable organic 

content; DOCF is the fraction of DOC dissimilated; and 

F is the fraction by volume of CH4 in landfill gas) and 

remove the definition of the term L0 from the 

definitions for Equation HH-1 of subpart HH. 

• Revise the definition of “S” to read, “Start year of 

calculation. Use the year 1960 or the opening year of 

the landfill, whichever is more recent.” 

• Revise the definition of Wx to include “measurement 

data” as follows: “Quantity of waste disposed of in 

the landfill in year x from measurement data, tipping 

fee receipts, or other company records (metric tons, 

as received (wet weight).” 

• Revise the definition of “MCF” to read “Methane 

correction factor (fraction). Use the default value 

of 1 unless there is active aeration of waste within 

the landfill during the reporting year. If there is 

active aeration of waste within the landfill during 

the reporting year, either use the default value of 1 

or select an alternative value no less than 0.5 based 

on site-specific aeration parameters.” 

• Revise the definition of “DOCf” to read, “Fraction of 

DOC dissimilated (fraction). Use the default value of 

0.5.” 
Page 69 of 246 

• Revise the definition of “F” as follows: “Fraction by 

volume of CH4 in landfill gas from measurement data on 

a dry basis, if available (fraction); default is 0.5.” 

• Revise the definition of “k” to read, “Rate constant 

from Table HH-1 to subpart HH (yr-1). Select the most 

applicable k value for the majority of the past 10 

years (or operating life, whichever is shorter).” 

We are also amending 40 CFR 98.343(a)(2) to replace 

“use the bulk waste parameter values for k and L0 in Table 

HH-1 to subpart HH” with “use the bulk waste parameter 

values for k and DOC in Table HH-1 to subpart HH.”. 

Measuring Waste Quantity. We are amending 40 CFR 

98.343(a) by adding a new paragraph (a)(3) to provide the 

necessary detail and clarification on the requirements for 

measuring the quantity of waste disposed in the landfill 

beginning with the first reporting year, and re-designating 

the existing 40 CFR 98.343(a)(3) as (a)(4). The amended 

waste measurement requirements for the reporting years 

require the use of scales when scales are in-place for all 

vehicles or containers delivering waste, except passenger 

vehicles and light duty pick-up trucks or waste loads that 

cannot be measured using the scales due to physical 

limitations (load cannot physically access or fit on the 

scale) and/or operational limitations of the scale (load 

exceeds the limits or sensitivity range of the scale). 
Page 70 of 246 

When scales are present at the MSW landfill, they must 

be used, (except for passenger vehicles and light duty 

pick-up trucks or waste loads that cannot be measured using 

scales due to physical and/or operational limitations). 

Two options for the use of scales are included in the 

amendments. One option is to directly weigh each 

vehicle/container load as it enters the landfill and weigh 

each vehicle/container after the waste has been off-loaded, 

and calculate the mass of waste disposed as the difference 

in the two measurements. The second option requires the 

landfill owner or operator to determine tare weights (empty 

vehicle weights) for representative vehicle types. In this 

option, the landfill owner or operator must weigh the 

incoming vehicles and containers and calculate the mass of 

waste disposed based on the difference of the incoming 

vehicle weight and the tare weight of that vehicle type. 

When scales are not in place, the working capacity or 

the mass of waste per type of vehicle or container must be 

determined. These measurements may include determining the 

volumetric capacity of representative containers and the 

average density of the waste as received. Wheel-load 

scales or portable axle-load scales may be used for these 

density determinations or measures of the mass of waste 

received by type of load. The landfill owner or operator 
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must record the number and type of vehicles that haul waste 

to the landfill and use the working capacity of the 

containers to calculate the quantity of waste landfilled. 

In addition to redesignating paragraph (a)(3) of 40 

CFR 98.343 to (a)(4), we are amending that paragraph and 

the sub-paragraphs to clarify that measurement data can be 

used for historical years when the data are available. We 

are clarifying that the “Historical waste disposal 

quantities should only be determined once, as part of the 

first annual report, and the same values should be used for 

all subsequent annual reports, supplemented by the next 

year’s data on new waste disposal.” We are also amending 

40 CFR 98.343(a)(4)(i) to read, “Assume all prior year’s 

waste disposal quantities are the same as the waste 

quantity in the first year for which waste quantities are 

available.” We are amending 40 CFR 98.343(a)(4)(iii) by 

revising the phrase, “i.e., from first accepting waste...” 

with “i.e., from the first year accepting waste...” 

In related amendments, we are also amending 40 CFR 

98.344(a) to state that “Mass measurement equipment used to 

determine the quantity of waste landfilled on or after 

January 1, 2010 must meet the requirements for weighing 

equipment as described in “Specifications, Tolerances, and 

Other Technical Requirements For Weighing and Measuring 
Page 72 of 246 

Devices,” NIST Handbook 44 (2009) (incorporated by 

reference, see 40 CFR 98.7).” We are also amending 40 CFR 

98.346(a) to require reporting of “...an indication of 

whether scales are present at the landfill,” and to amend 

40 CFR 98.346(b) to require reporting of the waste 

quantities that were determined using scales according to 

the requirements in 40 CFR 98.343(a)(3)(i) and the waste 

quantities determined using vehicle counts and load 

capacities. We are also amending 40 CFR 98.347 to 

specifically require that records be maintained of all 

measurements used to determine vehicle tare weights or 

working capacities. 

Equations HH-2, HH-3, and HH-4. We are making the 

following technical amendments to Equation HH-2 in 40 CFR 

98.343: 

• Replace the term “WGRx” with “WDRx” and remove the 

term “%SWDS.” 

• Replace the definition of the term “WGRx” with “WDRx = 

Average per capita waste disposal rate for year x from 

Table HH-2 to this subpart (metric tons per capita per 

year, wet basis; tons/cap/yr).” 

• Delete the definition of the term “%SWDS.” 

• Delete the word “of” from the definition of “POPx.” 

We are making the following technical amendments to 

Equation HH-3 in 40 CFR 98.343: 

• Replace the term “WDRx” with “Wx.” 
Page 73 of 246 

• Replace the definition of the term “WDRx” with “Wx” = 

quantity of waste place in the landfill in year x 

(metric tons/wet basis).” 

• Replace the definition of LFC with “Landfill capacity 

or, for operating landfills, capacity of the landfill 

used (or the total quantity of waste-in-place) at the 

end of the year prior to the year when waste disposal 

data are available from design drawings or engineering 

estimates (metric tons).” 

We are making the following technical amendments to 

Equation HH-4 and the related 40 CFR 98.343(b): 

• Amend Equation HH-4 of subpart HH and the terms in 

that equation to allow for daily averages (365 or 366 

per year) from a continuous CH4 monitoring system, or 

from weekly sampling (with 52 measurement periods). 

• Amend the definitions of the terms (T)n and (P)n in 

Equation HH-4 to allow for averaging of measurements. 

• In 40 CFR 98.343(b)(2), delete “...at least weekly...” 

• In 40 CFR 98.343(b)(2)(ii), (iii)(A), and (iii)(B), 

replace “no less than weekly” with “at least once each 

calendar week; if only one measurement is made each 

calendar week, there must be at least three days 

between measurements.” 

• In 40 CFR 98.343(c), replace “Calculate...” with “For 

all landfills, calculate...” 

Moisture Content Measurement. In addition to the 

other amendments to Equation HH-4 of subpart HH discussed 

above, we revised the definition of (V)n to be the 

cumulative volume for the measurement period (rather than 

the volumetric flow rate), eliminated the 1,440 conversion 

factor for minutes per day, and revised the reference to 

“day” in the definition of equation terms with “measurement 

period.” We are also amending Equation HH-4 to replace the 
Page 74 of 246 

moisture correction term, [1-(fH2O)n], with a moisture 

correction factor, KMC. KMC is defined as “Moisture 

correction term for the measurement period, volumetric 

basis,” for three different measurement scenarios: 

KMC = 1 if (V)n and (C)n are both measured on a dry 

basis or if both are measured on a wet basis. 

KMC = 1-(fH2O)n if (V)n is measured on a wet basis and 

(C)n is measured on a dry basis. 

KMC = 1/[1-(fH2O)n] if (V)n is measured on a dry basis 

and (C)n is measured on a wet basis. 

We are similarly amending 40 CFR 98.343(b)(2)(iii)(B) 

to indicate that moisture content is needed “[i]f the CH4

concentration is determined on a dry basis and flow is 

determined on a wet basis or CH4 concentration is determined 

on a wet basis and flow is determined on a dry basis,...”. 

We are amending 40 CFR 98.344(d) and (e) to include 

reference to moisture content monitors. Specifically, we 

are amending 40 CFR 98.344(d) to read: “All temperature, 

pressure, and if necessary, moisture content monitors must 

be calibrated using the procedures and frequencies 

specified by the manufacturer.” We are also amending the 

first sentence in 40 CFR 98.343(d) to read, “The owner or 

operator shall document the procedures used to ensure the 

accuracy of the estimates of disposal quantities and, if 

applicable, gas flow rate, gas composition, temperature, 

pressure, and moisture content measurements.” We are 
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amending 40 CFR 98.346(i)(3) to require reporting of both 

temperature and pressure (not just temperature) and to 

amend 40 CFR 98.346(i)(4) to require reporting of the 

moisture content measurements. 

“Active” and “Passive” Gas Collection Systems. We are 

amending the definition of “gas collection system” in 40 

CFR 98.6 as described in Section II.B of this preamble and 

we are adding a reporting requirement in 40 CFR 98.346(h) 

and (i)(7) for reporters to provide “an indication of 

whether passive vents and/or passive flares (vents or 

flares that are not considered part of the gas collection 

system as defined in 40 CFR 98.6) are present at this 

landfill.” 

Other Technical Corrections. We are making other 

technical corrections for subpart HH to correct 

typographical errors, to correct equations, and to provide 

minor clarifications. 

We are making the following technical corrections to 

40 CFR 98.344(b): 

• Delete the word “install.” 

• In 40 CFR 98.344(b)(6)(ii), add “at the routine 

sampling location.” 

• Revise 40 CFR 98.344(b)(6)(ii)(A) to read “Take a 

minimum of three grab samples of the landfill gas with 

a minimum of 20 minutes between samples and determine 

the methane composition of the landfill gas using one 
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of the methods specified in paragraphs (b)(1) through 

(b)(5) of this section.” 

• In 40 CFR 98.344(b)(6)(iii), delete “that is collected 

and routed to a destruction device (before and 

treatment equipment).” 

• In 40 CFR 98.344(b)(6)(ii)(B), add “for use in 

Equation HH-4 of this subpart” to the definition of 

the term CH4 as follows “Methane concentration in the 

landfill gas (volume %) for use in Equation HH-4 of 

this subpart.” 

In 40 CFR 98.344(c), we are revising the language to 

read, “Each gas flow meter shall be recalibrated either 

biennially (every 2 years) or at the minimum frequency 

specified by the manufacturer. Except as provided in 40 

CFR 98.343(b)(2)(i), each gas flow meter must be capable of 

correcting for the temperature and pressure and, if 

necessary, moisture content.” We are making the following 

technical corrections to 40 CFR 98.346: 

• Revise the language in 40 CFR 98.346(a) regarding 

leachate recirculation to read “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).” 

• Revise 40 CFR 98.346(c) to read “Waste composition for 

each year required for Equation HH-1 of this subpart, 

in percentage by weight, for each waste category 

listed in Table HH-1 to this subpart that is used in 

Equation HH-1 of this subpart to calculate the annual 

modeled CH4 generation.” 

• In 40 CFR 98.346(d)(1), replace the term, “Degradable 

organic carbon (DOC) value used in the calculations,” 

with “Degradable organic carbon (DOC), methane 
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correction factor (MCF), and fraction of DOC 

dissimilated (DOCF) values used in the calculations.” 

• In 40 CFR 98.346(d)(1) add “If an MCF value other than 

the default of 1 is used, provide an indication of 

whether active aeration of the waste in the landfill 

was conducted during the reporting year, a description 

of the aeration system, including aeration blower 

capacity, the fraction of the landfill containing 

waste affected by the aeration, the total number of 

hours during the year the aeration blower was 

operated, and other factors used as a basis for the 

selected MCF value.” 

• Revise 40 CFR 98.346(f) to read, “The surface area of 

the landfill containing waste (in square meters), 

identification of the type of cover material used (as 

either organic cover, clay cover, sand cover, or other 

soil mixtures). If multiple cover types are used, the 

surface area associated with each cover type.” 

• Add “for the reporting year” to 40 CFR 98.346(i)(1) as 

follows: “Total volumetric flow of landfill gas 

collected for destruction for the reporting year 

(cubic feet at 520°R or 60°F and 1 atm).” 

• Add “Annual average” to 40 CFR 98.346(i)(2)as follows: 

“Annual average CH4 concentration of landfill gas 

collected for destruction (percent by volume).” 

• In 40 CFR 98.346(i)(7), replace the parenthetical 

“(manufacture, capacity, number of wells, etc.)” with 

“(manufacturer, capacity, and number of wells).” 

We are also adding the following definitions within 40 

CFR 98.348 of subpart HH: “destruction device”; “solid 

waste”; and “working capacity.” 

We are amending Table HH-1 to subpart HH to delete the 

default value for Lo, to provide additional DOC and k-values 

including those for inerts, e.g. glass, plastics, metal, 

concrete, and to provide additional DOC and k-values to 

provide additional options for categorizing waste when 
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applying Equation HH-1 in 40 CFR 98.343(a). We are also 

amending Table HH-1 to subpart HH to provide a more 

reasoned approach for determining the decay rate constant, 

k, when only a small quantity of leachate is recirculated 

and/or when leachate recirculation is used rarely (not 

every year). The leachate recirculation rate will be 

calculated as the total volume of leachate recirculated 

during the year divided by the area of the portion of the 

landfill containing waste. No direct measurement of volume 

of leachate recirculated is required; engineering estimates 

may be used. This leachate recirculation rate (in 

inches/year) is added to the precipitation rate and the sum 

used to determine what decay rate constant is appropriate. 

Alternatively, landfills that use leachate recirculation 

can elect to use the higher k value rather than calculating 

the recirculated leachate rate. The footnotes for Table 

HH-1 to subpart HH have been revised accordingly. 

We are amending Table HH-2 to subpart HH to provide 

directly the waste disposal factors rather than the waste 

generation rates and percent disposed of in solid waste 

disposal sites (% to SWDS) and correcting an error in the 

waste generation rates included in Table HH-2 to subpart HH 

from 1989 to 2006. We are also adding waste disposal rates 

for 2007, 2008, and 2009. 
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We are amending Table HH-3 to subpart HH to delete the 

references to the average depth of waste within an area 

(H2, H3, H4, and H5). We are also amending Table HH-3 to 

subpart HH to clarify what is considered a “final soil 

cover.” The description for A5 is revised to read, “Area 

with a final soil cover of 3 feet or thicker of clay and/or 

geomembrane cover system and active gas collection.” The 

description for A4 is revised to read, “Area with an 

intermediate soil cover, or a final soil cover not meeting 

the criteria for A5 below, and active gas collection.” 

Major changes since proposal are identified in the 

following list. The rationale for these and any other 

significant changes can be found in this preamble or the 

Response to Comments: Technical Corrections, Clarifying and 

Other Amendments (see EPA-HQ-OAR-2010-0109). 

• Deleted the word “dedicated” from the phrase 

“dedicated construction and demolition waste landfill” 

in 40 CFR 98.340(b) and replaced the proposed 

definition of “dedicated construction and demolition 

waste landfill” with a definition of “construction and 

demolition waste landfill” taken from 40 CFR part 

257.2. 

• Revised the definition of MCF term in Equation HH-1 to 

allow landfills with active aeration to select an MCF 

value less than 1, but no lower than 0.5 and added 

reporting requirements to 40 CFR 98.346(d)(1) for 

facilities using an MCF value other than 1. 

• Revised Table HH-1 to subpart HH to include DOC and k 

values for additional waste categories to provide an 

additional option for characterizing waste materials 

when applying Equation HH-1 of subpart HH. 
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• Revised the footnotes to Table HH-1 to subpart HH to 

allow the use of the greater k value in a given range 

when recirculation is used without the need to 

calculate the recirculated leachate quantity in inches 

per year. 

• Revised 40 CFR 98.343(a)(3) to account for those loads 

that cannot be measured using scales due to their 

physical and/or operational limitations. 

2. Summary of Comments and Responses

This section contains a brief summary of major 

comments and responses. Several comments were received on 

this subpart. Responses to additional significant comments 

received can be found in Response to Comments: Technical 

Corrections, Clarifying and Other Amendments (see EPA-HQOAR-2010-0109). 

Comment: Several commenters stated that the new 

definition of “dedicated construction and demolition (C&D) 

waste landfills” is problematic and inappropriate because 

it is inconsistent with the C&D landfill definition already 

long-established in 40 CFR 257.2, “Criteria for the 

Classification of Solid Waste Disposal Facilities and 

Practices,” it represents a significant material change to 

the subpart HH applicability requirements, and it changes 

the data collection requirements for landfills 

retroactively. The RCRA Subtitle D definition 40 CFR 257.2 

is: 
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“Construction and demolition (C&D) landfill means a 

solid waste disposal facility subject to the 

requirements of subparts A or B of this part that 

receives construction and demolition waste and does 

not receive hazardous waste (defined in §261.3 of this 

chapter) or industrial solid waste (defined in §258.2 

of this chapter). Only a C&D landfill that meets the 

requirements of subpart B of this part may receive 

conditionally exempt small quantity generator waste 

(defined in §261.5 of this chapter). A C&D landfill 

typically receives any one or more of the following 

types of solid wastes: roadwork material, excavated 

material, demolition waste, construction/renovation 

waste, and site clearance waste.” 

According to the commenters, a dedicated C&D landfill, 

as defined in the proposal, rarely exists and most states 

allow C&D landfills to accept yard waste and other forms of 

household trash, pointing to the use of the word 

“typically” with regard to the types of wastes received, 

and suggesting that site clearance waste includes yard 

waste among other materials. The commenters urged EPA to 

delete the new C&D landfill definition in 40 CFR 98.348 and 

replace it with the definition found in 40 CFR 257.2. On 

the other hand, one commenter expressed concern with 

excluding “dedicated C&D waste landfills” even with the 

proposed definition and requested EPA to quantify the 

methane emissions from these C&D landfills. 

Response: We generally agree with commenters that the 

RCRA Subtitle D definition in 40 CFR 257.2 is appropriate 

and should be used in preference to the proposed definition 
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of “dedicated C&D waste landfills.” However, we are 

concerned with some of the assertions made by the 

commenters that a “C&D waste landfill” could accept some 

yard wastes and possibly other household wastes. Yard 

waste and household solid wastes are clearly included in 

the definition of “municipal solid waste or MSW” in 40 CFR 

98.6. The definition of “MSW landfill” in 40 CFR 98.6 

“means an entire disposal facility...where household waste 

is placed in or on land.” It is our interpretation and 

intent that any landfill in which household wastes, 

including household yard wastes or other MSW materials, are 

placed is a MSW landfill and is subject to the reporting 

requirements of subpart HH. As we did not change or alter 

the definition of MSW or MSW landfill, we do not agree with 

commenters that interpret the RCRA Subtitle D definition of 

C&D landfills in 40 CFR 257.2 to somehow supersede the 

definitions and intent of subpart HH. Furthermore, the 

definition of MSW landfill (MSWLF) unit in 40 CFR 257.2 

specifies that “a C&D waste landfill that receives 

residential lead-based paint waste and does not receive any 

other household waste is not a MSWLF unit.” The converse 

of the statement clearly suggests that a C&D waste landfill 

that receives any household waste other than residential 

lead-based paint waste is a MSWLF unit. Thus, while we are 
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revising the definition of C&D landfill to more closely 

follow the definition at 40 CFR 257.2, we do not agree that 

we materially altered the rule by providing a definition of 

dedicated C&D waste landfill and strongly object to the 

supposition that landfills that receive even small 

quantities of household wastes (other than residential 

lead-based paint wastes) are anything other than MSW 

landfills. Therefore, to clarify our intent, we have 

revised slightly the language adapted from the RCRA 

definition to specifically state that a C&D waste landfill 

does not receive MSW. We also deleted the sentence 

regarding conditionally exempt waste as superfluous to the 

requirements of this definition in subpart HH. The final 

definition reads “Construction and demolition (C&D) waste 

landfill means a solid waste disposal facility subject to 

the requirements of subparts A or B of part 257 of this 

chapter that receives construction and demolition waste and 

does not receive hazardous waste (defined in 40 CFR 261.3 

of this chapter) or industrial solid waste (defined in 40 

CFR 258.2 of this chapter) or municipal solid waste 

(defined in 40 CFR 98.6) other than residential lead-based 

paint waste. A C&D waste landfill typically receives any 

one or more of the following types of solid wastes: 
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roadwork material, excavated material, demolition waste, 

construction/renovation waste, and site clearance waste.” 

While we have adopted, for the most part, the RCRA 

subtitle D definition for C&D waste landfills, we maintain 

that the inclusion of a definition of C&D waste landfills 

is not a material change in the rule because it does not 

alter the definition of MSW landfill or the applicability 

of the rule to MSW landfills. As the final definition of 

C&D waste landfills expressly includes site clearance 

wastes, which could include trees and other materials that 

have significant organic content, we agree that additional 

evaluation is needed to assess the methane generation 

potential of C&D waste landfills. Consequently, we are 

taking this comment under advisement; we will determine 

whether or not reporting requirements should be proposed 

for C&D waste landfills at a future time based on the 

results of the additional evaluations of C&D waste 

materials and their methane generation potential. 

Comment: Several commenters expressed support for the 

amended definition of “gas collection systems or landfill 

gas collection systems,” intended to clarify that passive 

vents/flares are not considered part of a landfill gas 

collection system for purposes of subpart HH. However, 

these commenters opposed the proposed reporting requirement 
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to provide an indication of whether passive vents and/or 

passive flares that are not considered part of the gas 

collection system as defined in 40 CFR 98.6 are present at 

the landfill. The commenters argued that this represents a 

new data element that would require significant additional 

burden to contact landfill engineers to collect this new 

information. The commenters recommended that EPA finalize 

this data element, but delay its collection to January 1, 

2011, and delay its reporting to March 31, 2012 and 

thereafter. On the other hand, one commenter expressed 

concerned that EPA’s decision to exempt “passive” gas 

collection systems from flow meter reporting may 

inadvertently exempt substantial emissions sources. The 

commenter noted that the number of landfills with passive 

vent controls is uncertain and argued that the cumulative 

emissions from these passive collection systems could be 

significant. The commenter requested EPA include any data 

on this point in the record for the final rulemaking and 

include passive gas collection systems fully in the rule if 

warranted. 

Response: The monitoring requirements for gas 

collection systems within the final rule were developed 

considering forced ventilation systems and those monitoring 

requirements are inappropriate for passive gas collection 
Page 86 of 246 

systems. However, we agree with the commenter who 

suggested that EPA must obtain more data on the prevalence 

of these systems in order to properly understand and 

account for the impact these systems may have on the GHG 

emissions from MSW landfills. We find that “an indication” 

(essentially answering a yes/no question to indicate 

whether or not a passive gas collection system is present) 

is not a significant additional reporting burden. As this 

reporting requirement requires no monitoring or other 

activities that might be considered a retroactive 

requirement, we conclude that this reporting requirement is 

appropriate and necessary for the 2010 reporting year. 

Comment: A few commenters indicated that the 

requirement to use a methane correction factor (MCF) of 1 

will overestimate methane generation from landfills that 

are actively aerated and recommended that facilities be 

allowed to use alternative MCF values based on sitespecific conditions (e.g., the use of in-situ aeration). 

Response: To the extent some MSW landfills actively 

aerate the waste within the landfill, we agree that 

alternative MCF values should be allowed for actively 

aerated landfills. Supplying air to the waste within the 

landfill will reduce the fraction of carbon that is 

degraded anaerobically, which is represented by the MCF 
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value. However, additional reporting requirements are 

needed to verify the MCF value selected. These include the 

basis of the alternative value, such as an indication of 

whether active aeration is used, a description of the 

aeration system, including aeration blower capacity, the 

fraction of the landfill containing waste affected by the 

aeration, the total number of hours during the year the 

aeration blower was operated, and other factors used as a 

basis for the selected MCF value. Based on other comments 

received (e.g., comments described above on reporting of 

the presence of passive gas collection systems), the 

inclusion of these additional reporting requirements would 

likely be objectionable. However, we have conditioned 

these additional reporting requirements to be applicable 

only for facilities electing not to use an MCF value of 1. 

As the reporting requirements for facilities that use an 

MCF value of 1 have not changed, and because all facilities 

can choose to use the default value of 1 (including the 

relatively few landfills that use active aeration), we find 

that we have not significantly altered the reporting 

requirements of the final rule. Facilities electing to use 

an MCF other than 1 must have active aeration and must 

provide information regarding the aeration system to 

justify the lower MCF value. 
Page 88 of 246 

Comment: One commenter noted that the new defaults 

for inert wastes in Table HH-1 to subpart HH are designated 

for use only by those landfills capable of segregating and 

measuring the waste they accept by composition using EPA’s 

prescribed waste categories, which include: food waste, 

garden, paper, wood and straw, textiles, diapers, sewage 

sludge and, now, inerts. According to commenters, U.S. MSW 

landfills do not use these categories to categorize waste 

receipts, and few if any MSW landfills will be able to 

adjust for large quantities of inerts that may be disposed 

of at a specific landfill. The commenter noted that the 

MSW landfill sector in the U.S. typically records waste 

type receipts using the broad categories of MSW bulk waste, 

construction and demolition (C&D) bulk waste, inert waste, 

sewage sludge, and yard and garden waste. The commenter 

recommended that the inert defaults be included in Table 

HH-1 to subpart HH for the “Bulk Waste Option” to allow 

landfills to take large shipments of bulk inert wastes into 

account in their landfill gas generation models. 

Response: The bulk DOC and k values were determined 

based on monitored landfill gas generation rates and the 

total quantity of waste disposed (annual average waste 

acceptance rates). We reviewed the C&D waste acceptance 

policies of these landfills, as C&D waste can largely be 
Page 89 of 246 

comprised of inert materials, and determined that each 

landfill accepted C&D wastes. While we do not have a 

breakdown of the relative quantities of different 

categories of wastes in these landfills, we maintain that 

the default “bulk waste” DOC and k values are 

representative of typical or average MSW landfill 

operations in the U.S. However, we also acknowledge that 

there is significant variability in the methane generation 

rates (per ton of waste disposed) at individual landfills. 

We provided the waste composition option to account for 

this variability, but this option needs a default value for 

inert materials in order to be more comprehensive and 

therefore reflective of waste composition at U.S. 

landfills. With regard to the bulk waste option, which is 

applicable when a landfill cannot breakdown their waste 

quantities at all, it is not appropriate to allow the use 

of inert default parameters, because values provided for 

this option already consider that there will be some amount 

of inerts in the overall waste quantity. Therefore, this 

option remains as it appeared in the October 2009 Final 

rule. However, we consider it reasonable to provide an 

alternative bulk MSW option that allows landfills to 

characterize their waste quantities into categories that 

the MSW landfill industry more typically monitors and 
Page 90 of 246 

records. We reviewed available MSW waste characterization 

data to develop default bulk MSW model parameters excluding 

inerts and C&D wastes, and determined that an appropriate 

DOC value for this waste category is 0.31 with a k value 

similar to that for bulk waste. Therefore, we have 

included in the final rule an additional option for 

characterizing waste materials. In this “bulk MSW” option, 

there are three waste categories: bulk MSW excluding 

inerts and C&D wastes; inert wastes; and C&D wastes. This 

new option provides a means for individual landfills to 

better estimate the methane generation rates to account for 

significant quantities of inert materials or C&D wastes 

without needing to classify the wastes into the detailed 

categories of the waste composition option. For more 

information on the bulk MSW option, please see “Modified 

Bulk MSW Option” in docket EPA-HQ-OAR-2010-0109. 

Given these amendments to Table HH-1 to subpart HH, we 

are also revising the reporting requirements in 40 CFR 

98.346(c) to clarify that the waste compositions should be 

reported only for the waste categories in Table HH-1 to 

subpart HH that are used in the calculation of methane 

generation using Equation HH-1 of subpart H. This 

amendment is needed to avoid confusion with the “municipal” 
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category currently listed in 40 CFR 98.346(c) and the bulk 

waste and bulk MSW categories. 

Comment: A few commenters indicated that the 

amendment to the Table HH-1 to subpart HH regarding 

leachate recirculation imposes substantial new data 

collection requirements that would require significant 

operational changes to implement. According to the 

commenters, most landfills that recirculate leachate do not 

measure and track the volume that is recirculated during 

each event and would not be able to provide these data for 

the 2010 calendar year. Furthermore, the commenter 

suggested that landfills would incur significant expense to 

install appropriate leachate measurement devices and 

ancillary equipment for a nominal impact on landfill GHG 

emissions calculation accuracy. 

Response: We proposed the modifications to Table HH-1 

to subpart HH to address questions that arose concerning 

the use of the highest k value in the range when leachate 

recirculation was used sporadically or only in limited 

amounts. We did not specify any monitoring requirements 

for the quantity of leachate recirculated; we anticipated 

that most landfills would use company records or 

engineering estimates to determine the quantity of leachate 

recirculated. We have revised the first footnote to Table 
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HH-1 to subpart HH to clarify this point. Additionally, we 

have revised the footnotes to allow facilities to use the 

highest k value in the range when leachate recirculation is 

used. As such, the final amendments are effectively 

equivalent to those proposed, but give reporters some 

flexibility to use high-range default k values if leachate 

recirculation is used, but leachate recirculation rates are 

unknown or otherwise not estimated. The use of the higher 

k values may overestimate methane generation, but it will 

not result in any additional monitoring or reporting burden 

for reporters. Further, not all landfills use leachate 

recirculation and we expect that some of the landfills that 

do use leachate recirculation will have records that 

document the amount of leachate that is recirculated. 

Therefore, we expect that only a small subset of landfills 

would default to the higher k-value when a lower k-value 

might be more appropriate and that there will not be a 

significant bias in overall emissions from landfills. 

Comment: Several commenters discussed the amendments 

in 40 CFR 98.343(a)(3) requiring landfills to use scales 

when scales are in-place for all vehicles or containers 

delivering waste, except passenger vehicles and light-duty 

pick-up truck. The commenters stated that this requirement 

is problematic because it is not possible to physically 
Page 93 of 246 

weigh all loads entering the landfill because their weight 

may exceed the scales’ capability or the dimensions of the 

waste may not allow the waste load to pass through the 

physical constraints of the scale and scale-house. Some 

commenters noted that state and local requirements may 

require accounting of certain waste types on a volumetric 

basis despite the landfill having scales. The commenters 

suggested that having to maintain two sets of records in 

order to comply with all established regulatory 

requirements is an unnecessary burden and contrary to 

acceptable accounting practices. One commenter suggested 

that the clarification to require all waste loads to be 

weighed via a scale to be a substantial material change 

because the final MMR could be interpreted to allow tipping 

fee receipts or company years for 2010 and beyond and not 

just direct measurement. The commenters generally 

recommended that 40 CFR 98.343(a)(3) be revised so that 

waste loads can be measured by using either methodologies 

as appropriate for the waste type disposed even though 

scales are present at the landfill. Some of the commenters 

suggested EPA allow facilities to estimate the 

weight/volume of the delivered waste material using methods 

and factors allowed or required by state or local agencies 
Page 94 of 246 

or other methods documented in the relevant facility’s GHG 

Monitoring Plan. 

Response: We originally intended that scales be 

installed and direct mass measurements be used for the year 

2010 and beyond; the allowance of tipping fee receipts or 

other company records was intended for years prior to the 

first emissions reporting year. While states and local 

jurisdictions may require measurement by volume, Equation 

HH-1 of subpart HH, which is the foundation for determining 

methane generation from the landfill, requires the waste 

quantity in units of mass. Section 98.343(a)(2) of subpart 

HH specifically requires these waste quantities [in units 

of mass] to be determined daily, and 40 CFR 98.344(a) 

states that “[t]he quantity of waste landfilled must be 

determined using mass measurement equipment...” EPA 

answered numerous questions regarding this requirement and 

communicated the above interpretation to the industry in 

webinars and other outreach materials. Consequently, we do 

not consider the proposed amendments in 40 CFR 98.343(a)(3) 

to be a substantial material change in the requirements of 

the rule published on October 30, 2009. However, we 

recognize that some reporters did not believe that the rule 

language was explicit with respect to these requirements. 

Additionally, we reconsidered our original position that 
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scales must be installed. The proposed amendments 

addressed both of these issues. 

We had not considered that there would be physical 

limitations to accessing the scale. We also anticipated 

that the scales would cover the range of sizes and weights 

received at the site. As we no longer require the 

installation of permanent scales at a facility, we 

certainly do not intend to require facilities to have to 

replace existing scales to accommodate unusually sized or 

heavy loads. As such, we conclude that it is reasonable to 

allow facilities to use the methods in 40 CFR 

98.343(a)(3)(ii) for certain waste loads even though scales 

are present at the facility. However, because the mass of 

waste is a critical input to Equation HH-1 and we desire 

accurate measurements of this waste, the methods outlined 

in 40 CFR 98.343(a)(3)(ii) are limited to waste loads that 

cannot be measured using the scales due to physical and 

operational limitations of the scale. Physical limitations 

refers to the shape or size of the load so that it cannot 

access the scale or does not fit on the scale. Operational 

limitations refers to the weight of the load exceeding the 

limits or sensitivity range of the scale. Operational 

limitations are not intended to consider waiting times to 

access the scale. For all other types of waste loads 
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(other than passenger vehicles or light duty trucks), the 

direct mass measurement methods in 40 CFR 98.343(a)(3)(i) 

must be used. 

Q. Subpart LL – Suppliers of Coal-based Liquid Fuels

1. Summary of Final Amendments and Major Changes Since 

Proposal.

First, we are amending 40 CFR 98.386(a)(5) and (6) to 

clarify that fossil-fuel products that enter the facility 

will not be reported when exiting the facility if they are 

not further refined or otherwise used on site (e.g. 

products stored in a tank). It was not EPA’s intent that 

such products be reported. 

Second, we are amending 40 CFR 98.386(a)(3), (a)(7), 

(b)(3), and (c)(3) to harmonize the reporting requirements 

with the amendments in 40 CFR 98.393 of today’s rule to 

account for denaturant in ethanol. Third, we are replacing 

a comma with the words “that were” in 40 CFR 98.386(a)(16) 

and (a)(17) and adding a paragraph at 40 CFR 98.386(d) to 

harmonize the reporting requirements with the amendment in 

40 CFR 98.393(i) of today’s rule to provide an optional 

method for calculating GHG emissions from blended feedstock 

and products. Since subpart LL reporters follow subpart MM 

methodologies for calculating GHG emissions, these 
Page 97 of 246 

amendments are necessary to ensure complete reporting of 

subpart LL data. 

2. Summary of Comments and Responses

EPA did not receive any comments on the proposed 

amendments to subpart LL and is finalizing the amendments 

to this subpart as proposed. 

R. Subpart MM - Suppliers of Petroleum Products 

1. Summary of Final Amendments and Major Changes Since 

Proposal.

We are adding a definition of “batch” in 40 CFR 98.398 

to clarify the crude oil reporting requirements in 40 CFR 

98.396(a)(20) and to minimize administrative burden. Under 

this final rule, a batch of crude oil means either a volume 

that enters a refinery or a component of such volume (e.g., 

the volumes of different crude streams that are blended 

together and then delivered to a refinery). The batch 

volume is dependant upon what a refiner knows about the 

crude oil it receives and is the first appropriate tier in 

the following list: 

(1) Up to an annual volume of a type of crude oil 

identified by an EIA crude stream code6, if the EIA crude 

stream code is known. 

 

6 The EIA crude stream code is the numeric code used to identify the 

type of domestic crude oil in Form EIA-182 (Domestic Crude Oil First 

Purchase Report) and the alpha numeric code used to identify the type 
Page 98 of 246 

(2) Up to an annual volume of a type of crude oil 

identified by a generic name for the crude stream and an 

appropriate EIA two-letter country or state and production 

area code7 if the generic name and EIA two-letter code are 

known but no appropriate EIA crude stream code exists. 

(3) Up to a calendar month volume from a single known 

foreign country of origin if the crude stream name is 

unknown. 

(4) Up to a calendar month volume from the United 

States if the crude stream name and production area are 

unknown. 

(5) Up to a calendar month volume if the country of 

origin is unknown. 

For example, if refiners know the EIA crude stream 

code of a volume of crude oil that they receive, they must 

report the API gravity and sulfur content of up to an 

annual volume of this type of crude oil. If refiners only 

know the country of origin of a volume of foreign crude oil 

(but not the crude stream name), they must report the API 

 

of foreign crude oil in Form EIA-856 (Monthly Foreign Crude Oil 

Acquisition Report). 

7 EIA country code means the two-letter code identifying the country 

associated with the alpha numeric crude stream codes used to identify 

the type of foreign crude oil in Form EIA-856 and is traditionally 

found in Appendix A of the form. The EIA state and production area 

code is the two-letter code used to identify the source of domestic 

crude oil in Form EIA-182 is traditionally found in Appendix A of the 

instructions. 
Page 99 of 246 

gravity and sulfur content of up to a calendar month volume 

from that country. 

For data collection in 2010 only, a refiner that knows 

the information that we require them to report under a 

specific tier of the batch definition, but does not have 

the necessary data collection and management in place to 

readily report this information, can use the next most 

appropriate tier of the batch definition for reporting 

batch information in 40 CFR 98.396(a)(20). 

With this definition of “batch”, we are requiring 

refiners to report on crude oil volumes in 40 CFR 

98.396(a)(20) using the best data they are collecting as 

part of normal business practices. For example, refiners 

must use data on the American Petroleum Institute (API) 

gravity and sulfur content of crude oil that they, or a 

third party, currently collect as part of normal business 

practices, including data refiners use to report monthly 

weighted average API gravity and sulfur content to EIA. As 

another example, refiners must use data that they currently 

collect on the EIA crude stream code or country of origin 

for the components of a blended crude oil. 

We are making harmonizing amendments to 40 CFR 

98.396(a)(20) to allow refiners to report the country of 

origin, EIA crude stream code and name, or the generic name 
Page 100 of 246 

of the crude stream and associated production area code for 

a given batch as appropriate, if known. 

To better align the API gravity and sulfur content 

reporting requirements with normal business practices, we 

are also amending the recordkeeping requirements in 40 CFR 

98.397 so that refiners will no longer be required to 

maintain laboratory reports, calculations and worksheets 

used in the measurement of API gravity and sulfur content 

of crude oil. Instead, refiners must maintain sufficient 

records to support the information they report to EPA (as 

required by 40 CFR 98.397(a) and (b)). 

We are also amending 40 CFR 98.394(d) and 40 CFR 

98.396(a)(20) to clarify that we are seeking the weighted 

average API gravity and sulfur content from representative 

samples of each batch. 

To ensure that refiners can report readily available 

data in 40 CFR 98.386(a)(20) on the volume and associated 

characteristics of components of a blended crude oil, we 

are amending the requirements for determining quantity of 

crude oil in 40 CFR 98.394(a)(1) so that they only apply to 

volumes of crude oil that refiners measure on site (e.g., 

the total volume rather than the components of such 

volume). Refiners may now use an industry standard 

practice to determine volumes of crude oil that are not 
Page 101 of 246 

measured on site, even if an appropriate standard method 

published by a consensus-based standards organization 

exists, as specified in a new paragraph, 40 CFR 

98.394(a)(3). We are also amending the recordkeeping 

requirements associated with quantity determination in 40 

CFR 98.397(b) so that refiners will not be required to 

maintain metering and gauging records for quantities of 

crude oil that they do not measure on site, including the 

date of initial calibration and frequency of recalibration 

for associated measurement equipment. We are also amending 

98.394(d) to give refiners the option of following an 

industry standard practice to measure API gravity and 

sulfur content of crude oil. 

We are amending the definition of Producti (annual 

volume of product “i” produced, imported, or exported) in 

Equation MM-1 in 40 CFR 98.393(a)(1) and (2) to make it 

clear that GHG emissions should not be calculated for 

products leaving the refinery if those products had entered 

the refinery but were not further refined or otherwise used 

on site (e.g., products stored in a tank). As a 

harmonizing change, we are amending 40 CFR 98.396(a)(5) and 

(6) to clarify that these products are not reported. 

We are amending the procedure in 40 CFR 98.393(f)(1) 

for calculating emission factors for solid products when 
Page 102 of 246 

using Calculation Method 1. The amendments will clarify 

that reporters should multiply the default carbon share 

factor in column B of Table MM-1 to subpart MM by 44/12 

(the ratio of the molecular weight of CO2 to the atomic 

weight of carbon) to convert the amount of carbon in the 

product to CO2. Due to an oversight, 44/12 was not included 

in the original formula. This amendment is necessary 

because otherwise reporters would calculate the emissions 

of carbon instead of carbon dioxide. 

We are amending Equation MM-9 in 40 CFR 98.393(h)(2) 

to correct a typographical error. The correct emission 

factor (EF) term in the equation is EFj not EFi. 

We are adding an optional method for reporters in 40 

CFR 98.393(i) to calculate CO2 emissions that would result 

from the complete oxidation or combustion of a blended 

product or blended non-crude feedstock. The procedures in 

the existing rule require reporters to calculate CO2

emissions for blended products either by selecting the 

default emission factor for the product listed in Table MM1 to subpart MM that resembles most closely the blended 

product (Calculation Method 1) or by sampling and testing 

the blended product (Calculation Method 2). If a reporter 

applies the former method, the CO2 emissions calculation for 

the blended product will likely reflect the CO2 content of 
Page 103 of 246 

only one blend component. In such a case, the CO2 from the 

blended product will not be as accurately accounted for in 

Equation MM-4 of subpart MM. The optional method we are 

adding allows reporters to account for the CO2 emissions of 

a blended product or blended non-crude feedstock in the 

summary calculation of total facility CO2 by calculating the 

emissions of the blend’s individual components using 

appropriate default factors listed in Table MM-1 to subpart 

MM. This increases flexibility for facilities that receive 

and supply blends. This also improves accuracy of the 

summary calculation of total refinery CO2 because it ensures 

that the same quantities and emission factors are used for 

blend components coming in to the refinery as for blended 

products going out. 

The optional method is not available for a product 

that is biomass-based because such biomass-based products 

are subject to paragraph (h) of 40 CFR 98.393. 

To align the existing regulatory text with the 

optional method for blends, we are amending paragraphs 

(a)(1) and (b)(1) of 40 CFR 98.393 and paragraphs (a)(16) 

and (a)(17) of 40 CFR 98.396. We are also adding paragraph 

(d) of 40 CFR 98.396 to create new data reporting 

requirements for blends. 
Page 104 of 246 

We are amending the calculation procedures in 40 CFR 

98.393(h) for blended biomass-based fuels. Part 98 (as 

finalized in 70 CFR 56260, October 30, 2009) directed 

refineries that supply a petroleum product that was 

produced by blending a petroleum-based product with 

denatured ethanol to report emissions from the denaturant 

leaving the refinery but not the denaturant in the ethanol 

that enters the refinery as a feedstock. This resulted in 

over-reporting of GHG emissions across subpart MM reporters 

because the blending refinery accounted for the CO2 from 

denaturant in its GHG emissions calculation even though the 

original refinery that produced the denaturant ex-refinery 

gate already accounted for the CO2 in its GHG emission 

calculation. To address the over-reporting for refineries 

using Calculation Method 1 for petroleum products or noncrude petroleum feedstocks that contain denatured ethanol, 

we are amending Equations MM-8 and MM-9 of subpart MM to 

exclude denaturant from the term “%vol”, respectively. 

To address this over-reporting for refineries using 

Calculation Method 2 for petroleum products that were 

produced by blending a petroleum-based product with 

denatured ethanol on site, we are adding a new Equation MM10a of subpart MM. Equation MM-10a requires refineries to 

sample the petroleum-based products prior to blending them 
Page 105 of 246 

with denatured ethanol and use the resulting emissions 

factor and the volume of the petroleum-based product to 

calculate emissions for the ultimate petroleum products 

that leave the refinery. This new equation is necessary 

and Equation MM-10 is incorrect for such situations because 

the term for the biomass default emission factor in 

Equation MM-10 is applied to the whole volume of biomass 

received for blending (which for ethanol includes 

denaturant), even though the default factor for ethanol 

does not account for denaturant. We are splitting 40 CFR 

98.393(h)(3) into paragraphs (i) and (ii) so that Equation 

MM-10 remains in (i) for petroleum products blended with 

biomass other than denatured ethanol while Equation MM-10a 

appears in (ii) for petroleum products blended with 

denatured ethanol. We are amending Equation MM-10 to 

exclude denaturant from the term “%vol.” 

Together, these amendments ensure that the denaturant 

present in ethanol is not accounted for in the calculation 

of CO2 that would result from the complete combustion or 

oxidation of the biomass-blended product or feedstock. We 

have concluded that these amendments simplify reporting for 

reporters while maintaining the level of data quality and 

accuracy required by EPA for subpart MM because we would 

expect any denaturant in ethanol that enters the refinery 
Page 106 of 246 

in a feedstock to leave the refinery in a product and 

therefore the CO2 emissions from the denaturant would be a 

net of zero. 

We cannot identify a situation, nor did any 

commenters, in which a refinery would want to use 

Calculation Method 2 for a non-crude feedstock that 

contains denatured ethanol or an importer or exporter would 

want to use Calculation Method 2 for products containing 

denatured ethanol. Therefore, we are splitting 40 CFR 

98.393(h)(4) into paragraphs (i) and (ii) so that Equation 

MM-11 of subpart MM remains in (i) for non-crude feedstocks 

blended with biomass other than denatured ethanol while 

directions to use Calculation Method 1 appear in (ii) for 

non-crude feedstocks blended with denatured ethanol by 

refineries. We are also adding directions in 40 CFR 

98.393(h)(3)(ii) for importers and exporters of petroleum 

products blended with denatured ethanol to use Calculation 

Method 1. We are amending Equation MM-11 to exclude 

denaturant from the term “%vol.” 

We are amending 40 CFR 98.396(a)(3), (a)(7), (b)(3), 

and (c)(3) to align the reporting requirements with the 

amendments to account for denaturant in ethanol. 

Major changes since the proposal are identified in the 

following list. The rationale for these and any other 
Page 107 of 246 

significant changes can be found in Response to Comments: 

Technical Corrections, Clarifying and Other Amendments (see 

EPA-HQ-OAR-2010-0109). 

• We expanded on the proposed definition of “batch” to 

require refiners to report up to an annual volume of a 

type of crude oil identified by an EIA crude stream 

code (or the generic crude stream name and production 

area code if no appropriate EIA crude stream code 

exists) if refiners know this information. If 

refiners do not know this information, refiners must 

report according to the proposed definition of batch 

(e.g., up to a calendar month volume from a single 

country of origin or, if refiners do not know the 

country of origin, up to a total calendar month 

volume). 

• We clarified that “batch” can mean either the volume 

that enters a refinery or the components of such 

volume. We amended 40 CFR 98.394(a) to allow refiners 

to use industry standard practices to determine crude 

oil volumes that they do not measure on site, rather 

than standard methods published by a consensus-based 

standard, if desired. We also amended the 

recordkeeping requirements associated with quantity 

determination in 40 CFR 98.397(b) so that refiners are 

not required to maintain metering and gauging records 

for quantities of crude oil that they do not measure 

on site. 

• We amended 40 CFR 98.394(d) to allow refiners to use 

industry standard practices to measure API gravity and 

sulfur content of crude oil, rather than standard 

methods published by a consensus-based standards 

organization, if desired. 

• For reporting year 2010 only, we are providing 

reporters some flexibility in defining a batch of 

crude oil. A refiner that knows the information under 

a specific tier of the batch definition, but does not 

have the necessary data collection and management in 

place to readily report this information, can use the 

next most appropriate tier of the batch definition for 

reporting batch information in 40 CFR 98.396(a)(20). 

• As a harmonizing amendment with the final definition 

of crude oil (as discussed in Section II.B, Subpart A 
Page 108 of 246 

– General Provisions, of this preamble), we added a 

reporting requirements for refineries in 40 CFR 

98.396(a). Refiners are now required to report on the 

volume of crude oil that they inject into a crude 

supply or reservoir under a new paragraph (22). 

2. Summary of Comments and Responses

This section contains a brief summary of major 

comments and responses. Several comments were received on 

this subpart. Responses to additional significant comments 

received can be found in Response to Comments: Technical 

Corrections, Clarifying and Other Amendments (see EPA-HQOAR-2010-0109). 

Comment: We received three comments related to our 

proposed amendments regarding the treatment of denatured 

ethanol. Two comments supported the proposed change. The 

third commented that reporting of gasoline-ethanol blends 

(i.e., a petroleum product that contains denatured ethanol 

and is a blended biomass-based fuel) was burdensome and 

suggested that only the petroleum portion of these blends 

should be reported. That commenter stated that the 

blending of ethanol with gasoline should not be considered 

“to be further refined or otherwise used on site” (40 CFR 

98.396(a)(1)) and that therefore, ethanol should not have 

to be reported. 

Response: We are finalizing our proposed amendments 

related to denaturant in ethanol in today’s rule. 
Page 109 of 246 

When finalizing subpart MM, (74 FR 56260, October 30, 

2009), EPA concluded that reporting the total volume of 

gasoline-ethanol blends ex refinery gate as well as the 

percentage of that volume that is petroleum-based is not 

unnecessarily burdensome to reporters. The changes to 40 

CFR Part 98.396(a) that would be necessary to remove 

biomass reporting as suggested by the commenter are outside 

the scope of the specific amendments proposed for public 

comment in the Federal Register notice of June 15, 2010. 

The proposed changes to 40 CFR 98.396(a) only addressed how 

the denaturant in ethanol should be treated, and EPA did 

not seek comment on removing reporting on biomass entirely. 

As a result of the comments we received, we have 

concluded that there has been confusion regarding how 

ethanol should be reported when it leaves the facility. 

When ethanol leaves a facility covered by subpart MM, it is 

generally being blended with finished gasoline as it is 

being loaded into a truck. We are clarifying here that EPA 

considers the ethanol and the gasoline to be leaving the 

facility separately if they are leaving through different 

“spigots” and being blended in the truck. Under these 

circumstances, there is no gasoline-ethanol blend on site 

at the facility. The gasoline is the petroleum product 

that must be reported as leaving the facility. The 
Page 110 of 246 

denatured ethanol is not part of a petroleum product 

leaving the facility and, as a result of the technical 

correction being made in this rule for how to treat the 

denaturant in ethanol, need not be reported as entering or 

leaving the facility under these circumstances. 

The phrase “to be further refined or otherwise used on 

site” only applies to petroleum products, including blended 

biomass-based fuels, and natural gas liquids. EPA has 

clarified through guidance that a petroleum product or 

natural gas liquid that stays in the same container or 

vessel while on site and that is not blended with any other 

product is not “otherwise used on site” and that blending 

is considered “otherwise used on site”. If refiners blend 

ethanol with a petroleum product on site – for example, a 

refiner blends gasoline and ethanol on site and stores the 

blend in a tank before it leaves the facility – then the 

total volume of the ethanol-gasoline blend as well as the 

percentage of that volume that is petroleum-based must be 

reported when the blend leaves the facility. The volume of 

ethanol entering the facility need not be reported. 

Comment: In the proposal, we sought comment on 

defining a “batch” to help clarify crude oil reporting 

requirements in 40 CFR 98.396(a)(20) and reduce 
Page 111 of 246 

administrative burden, while continuing to collect adequate 

crude oil data to support the purposes of subpart MM. 

We received several comments on our proposed 

definition of batch and potential alternatives. One 

commenter supported defining a batch as the annual volume 

of a type of crude oil characterized by an EIA crude stream 

code (rather than monthly volumes) if EPA maintains the 

requirement to report API gravity, sulfur content, and 

country of origin of crude oil. One commenter expressed 

support for the proposed definition of batch but cautioned 

that it would limit refiners to report the country of 

origin as “unknown” when the crude oil batch is a blend of 

crude oil from several known countries. The commenter 

therefore advised EPA to allow refiners to report on the 

components in a crude oil blend and to amend the quantity 

determination requirements so that refiners can use 

information obtained from normal business practices on 

blend component volumes. The commenter further opined 

that, similar to the problem of reporting a single country 

of origin, refiners receiving a crude oil blend would be 

unable to report a single EIA crude stream code. Therefore 

the commenter recommended that EPA include annual crude 

volumes by EIA crude stream codes in the definition of 

batch only if it is presented as one of multiple options. 
Page 112 of 246 

Two commenters advocated that EPA limit the definition of 

batch to the annual volume of each EIA crude stream code 

category and remove the requirement to report API gravity, 

sulfur content, and country of origin for every batch. One 

commenter expressed concern about limiting the definition 

of batch to the annual volume of each EIA crude stream code 

category if it means losing data on API gravity. That 

commenter urged EPA to require refiners to report the 

sample data they already collect for EIA reporting. The 

commenter also asked that EPA define “batch” in a way that 

captures the differences in crude oil originating from the 

same country since different crude streams from the same 

country can have different API gravity and sulfur contents. 

Response: In today’s rule we are finalizing a 

definition of “batch” that builds on our proposed 

definition by adding two additional features. First, we 

are requiring refiners to define a batch as up to an annual 

volume of a type of crude oil identified by an EIA crude 

stream code (or a generic crude stream name and production 

area code) if refiners know this information. Second, we 

are defining batch as either the total volume of crude oil 

that enters a refinery or the components of such volume so 

that refiners will be able to report representative data 

they currently collect on all three crude parameters – (1) 
Page 113 of 246 

API gravity, (2) sulfur content, and (3) country of origin 

or crude stream name and production area – for the 

components in a blended crude volume instead of having to 

report the third parameter as unknown. These amendments 

were generally supported by commenters and we concluded 

that they would result in better data and be less 

burdensome than the proposed definition. 

With regard to comments on defining a batch as a 

monthly versus annual volume of crude, we determined that 

API gravity and sulfur content of specific crude streams do 

not vary enough to warrant requiring batch to be defined as 

only up to a monthly volume. On the other hand, API 

gravity and sulfur content can vary significantly between 

different crude streams coming from the same country of 

origin (or multiple countries of origin). Therefore, we 

determined that monthly reporting outlined in the proposed 

definition of “batch” would be necessary in those cases 

where refiners only know the country of origin of their 

crude volume (rather than the crude stream name and 

production area) or when they do not know the country of 

origin. We did not conclude that reporting batches more 

frequently than a monthly basis would be necessary in any 

situation. 
Page 114 of 246 

We considered eliminating the requirement that 

refiners report API gravity and sulfur content if they 

report the EIA crude stream code associated with the batch, 

but we determined that there were too many EIA crude stream 

codes without corresponding API gravity and sulfur content 

values and that even when present these values, while 

illustrative, were based on limited information and would 

not always be representative of the characteristics of the 

crude oil used at a refinery. Furthermore, refiners 

already collect data on the API gravity and sulfur content 

of their crude oil in order to report this information to 

EIA on a monthly basis, and it is our understanding, based 

on an industry comment, that refiners also track this 

information to determine how well the physical 

characteristics of the crude oil align with the processing 

capability of their refineries. 

Comment: In the proposal, we sought comment on other 

technical amendments (besides defining “batch”) that would 

help clarify crude oil reporting requirements in 40 CFR 

98.396(a)(20) and reduce administrative burden. In 

particular, we sought comment on ways to better align the 

provisions related to crude oil reporting with normal 

business practices. 
Page 115 of 246 

We received two comments with input on ways to better 

align the monitoring and QA/QC provisions related to crude 

oil reporting with normal business practices. According to 

the two commenters, it is normal business practice for 

refiners to maintain data on crude batch volumes and other 

parameters required in 40 CFR 98.396(a)(20). They 

described a number of different sources they use to 

identify the sulfur content and API gravity of crude oil 

batches (including components of blended crude oil volumes) 

such as grab samples, contract laboratory records, crude 

assay reports, invoices, and pipeline receipt tickets. 

They explained that the data contained in these sources are 

often collected outside of the refinery under normal 

business practices, which may be inconsistent with the 

current requirements in the rule to use standard methods to 

measure these data (resulting in the need to collect the 

data again inside the refinery). In addition, one of the 

two commenters explained that they maintain data on the 

components of blended crude volumes but they may not be 

able to determine the volume of the components of blended 

crude according to the quantity determination requirements 

in 40 CFR 98.394(a)(1) since the components arrive at the 

refinery already blended. Therefore, they will be forced 

to report the total volume of the blended crude oil and the 
Page 116 of 246 

country of origin (or EIA crude stream code) as “unknown” 

even though they know information about the volume 

components. 

We also received two comments in support of the 

proposed elimination of recordkeeping requirements in 40 

CFR 98.397 related to the measurement of API gravity and 

sulfur content of crude oil because it would support the 

use of data collected in normal business records. We 

received one comment that objected to EPA’s deletion of 

specific recordkeeping requirements for API gravity and 

sulfur content measurements on the basis that these records 

were important verification tools. 

Response: In response to comments, we are retaining 

our proposed amendment to eliminate the recordkeeping 

requirements in 40 CFR 98.397 related to the measurement of 

API gravity and sulfur content of crude oil. We are also 

making several additional amendments to improve the 

flexibility of the QA/QC and recordkeeping requirements in 

the rule to facilitate the reporting of similar and, in 

many cases, better quality data on API gravity, sulfur 

content, and geographic origin of crude oil batches while 

reducing administrative burden. We are amending 40 CFR 

98.394(d) to allow refiners to use industry standard 

practices to determine the API gravity and sulfur content 
Page 117 of 246 

of crude oil. We are amending the quantity determination 

monitoring and QA/QC requirements in 40 CFR 98.394(a) so 

that refiners can use industry standard practices to 

determine the volume of components of a blended crude batch 

(which are never directly measured on site at a refinery). 

Therefore, refiners will be able to report representative 

data they currently collect on all three crude parameters – 

(1) API gravity, (2) sulfur content, and (3) country of 

origin or crude stream name and production area – of the 

components in a blended crude volume instead of having to 

report the third parameter as unknown. We are also making 

a harmonizing amendment to 40 CFR 98.397(b) to eliminate 

the requirement that refiners maintain metering and gauging 

records for crude oil batch volumes that they do not 

measure on site. Together, these amendments will allow 

refiners to report crude characteristics contained in crude 

assay reports, third party laboratory reports, or pipeline 

receipt tickets if the characteristics are representative 

of the crude oil used at the refinery and it is an industry 

standard practice to use these sources. We have determined 

that these amendments will still ensure that the data 

refiners report is adequately representative of the crude 

oil they receive at the refinery and that the records they 

keep will be sufficient to support EPA verification of the 
Page 118 of 246 

data. We made this determination in light of the fact that 

crude oil data is not used to calculate the CO2 emissions 

reported under subpart MM.

Comment: We sought comment on our proposed timeline 

of implementing the technical amendments to subpart MM for 

the 2010 reporting year and whether this timeline was 

appropriate considering the nature of the proposed changes 

and/or the way in which data have been collected thus far 

in 2010. We received one comment indicating that defining 

“batch” in a manner that would require monthly reporting of 

crude oil volumes may necessitate modifications to current 

refinery sampling and monitoring practices and that 

refiners may not be able to provide this information by the 

March 31, 2011 reporting deadline for 2010 data. 

Response: While data collection methods may vary by 

refinery, we have determined that refiners currently 

collect data as part of normal business practices on the 

API gravity and sulfur content for at least one of the five 

tiers described in the definition of “batch” in today’s 

rule and should therefore be able to meet the crude oil 

reporting requirements in 40 CFR 98.396(a)(20) in a timely 

manner. However, since we did not include a definition of 

“batch” in the final rule (74 FR 56260), refiners may not 

have established data collection and management systems in 
Page 119 of 246 

2010 to link the information they collect on API gravity, 

sulfur content, and volumes of crude batches to an EIA 

crude stream code or generic crude stream name and 

production area code (i.e., tiers 1 and 2 of the “batch” 

definition). Likewise, refiners may not have had adequate 

time to link data they collect on API gravity and sulfur 

content from crude coming from a single country of origin 

to “up to a calendar month volume” (i.e., tiers 3 and 4 of 

the “batch” definition). We are therefore providing 

refiners the flexibility to report at a lower tier for 

reporting year 2010 if they do not have appropriate data 

collection and management systems in place to readily 

report the information in the higher tier. 

S. Subpart NN – Suppliers of Natural Gas and Natural Gas

Liquids

1. Summary of Final Amendments and Major Changes Since 

Proposal.

We are amending the definition of the term “Fuelh” in 

Equation NN-1 of subpart NN to clarify that the 

abbreviation “Mscf” refers to “thousand standard cubic 

feet” in order to avoid confusion on if this abbreviation 

means “million standard cubic feet”. We are also adding 

the subscript “h” to the terms for Fuel and HHV in Equation 

NN-1. 
Page 120 of 246 

We are amending the definition of the term “EF” in 

Equation NN-7 of subpart NN to clarify that the emission 

factor is for each natural gas liquid (NGL) product “g” and 

to add the subscript “g” to the term “EF.” 

We are amending Equation NN-8 of subpart NN to correct 

the term for “Annual CO2 mass emissions that would result 

from the combustion or oxidation of fractionated NGLs 

received from other fractionators” from “CO2j” to “CO2m”. We 

are also amending Equation NN-8 to remove the summation 

signs that were unnecessary from this equation for 

clarification purposes. We are also amending the 

definition of the term CO2i to clarify that this term 

includes NGLs delivered to customers or, on behalf of, 

customers, recognizing that some customers may not receive 

the NGLs directly. 

We are amending 40 CFR 98.406(a)(6) to correct two 

cross references. The incorrect references referred the 

reader to 40 CFR 98.406(b)(1) and (b)(2), when they were 

supposed to refer to 40 CFR 98.406(a)(1) and (a)(2). 

Similarly, we are amending an incorrect reference in 40 CFR 

98.407(d) to refer the reader to 40 CFR 98.406(b)(7) 

instead of 40 CFR 98.406(b)(6). 
Page 121 of 246 

We are amending 40 CFR 98.406(a)(9) to correct the 

abbreviation of NGL (from LNG) and to specify that 

reporting under that paragraph is for each product type. 

We are amending 40 CFR 98.407(a) to remove the word 

“daily” because daily meter readings are not specifically 

required under this subpart. 

Finally, we are updating the high heat values (HHVs) 

and default CO2 emission factors in Tables NN-1 and NN-2 to 

subpart NN to be consistent with the emission factors in 

Tables C-1 to subpart C and MM-1 to subpart MM. 

2. Summary of Comments and Responses

There were no major comments received on the proposed 

amendments to this section. A few comments seeking minor 

technical clarification or correction were received on this 

subpart. Responses to these comments can be found in 

Response to Comments: Technical Corrections, Clarifying and 

Other Amendments document (see EPA-HQ-OAR-2010-0109).

III. 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 12866 (58 FR 51735, 

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

under the executive order. 

B. Paperwork Reduction Act
Page 122 of 246 

This action does not impose any new information 

collection burden. These amendments do not make any 

substantive changes to the reporting requirements in any of 

the subparts for which amendments are being made. In many 

cases, the amendments to the reporting requirements reduce 

the reporting burden by making the reporting requirements 

conform more closely to current industry practices. 

However, the Office of Management and Budget (OMB) has 

previously approved the information collection requirements 

contained in the regulations promulgated on October 30, 

2009, under 40 CFR Part 98 under the provisions of the 

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

assigned OMB control number 2060-0629. Burden is defined 

at 5 CFR 1320.3(b). 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. 

Further information on EPA’s assessment on the impact 

on burden can be found in the Technical Corrections and 

Amendments Cost Memo (EPA-HQ-OAR-2010-0109). 

C. Regulatory Flexibility Act (RFA)

The RFA generally requires an agency to prepare a 

regulatory flexibility analysis of any rule subject to 
Page 123 of 246 

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 these 

amendments on small entities, small entity is defined as: 

(1) A small business as defined by the Small Business 

Administration’s regulations at 13 CFR 121.201; (2) a small 

governmental jurisdiction that is a government of a city, 

county, town, school district or special district with a 

population of less than 50,000; and (3) a small 

organization that is any not-for-profit enterprise which is 

independently owned and operated and is not dominant in its 

field. 

After considering the economic impacts of these rule 

amendments on small entities, I certify that this action 

will not have a significant economic impact on a 

substantial number of small entities. The rule amendments 

will not impose any new requirement on small entities that 

are not currently required by Part 98 promulgated on 

October 30, 2009 (i.e., calculating and reporting annual 

GHG emissions). 
Page 124 of 246 

EPA took several steps to reduce the impact on small 

entities. For example, EPA determined appropriate 

thresholds that reduced the number of small businesses 

reporting. In addition, EPA did not require facilities to 

install CEMS if they did not already have them. Facilities 

without CEMS can calculate emissions using readily 

available data or data that are less expensive to collect 

such as process data or material consumption data. For 

some source categories, EPA developed tiered methods that 

are simpler and less burdensome. Also, EPA required annual 

instead of more frequent reporting. Finally, EPA continues 

to conduct significant outreach on the mandatory GHG 

reporting rule and maintains an “open door” policy for 

stakeholders to help inform EPA’s understanding of key 

issues for the industries. 

D. Unfunded Mandates Reform Act (UMRA)

This action contains no Federal mandates under the 

provisions of Title II of the Unfunded Mandates Reform Act 

of 1995 (UMRA), 2 U.S.C. 1531-1538 for State, local, or 

tribal governments or the private sector. The action 

imposes no enforceable duty on any State, local or tribal 

governments or the private sector. In addition, EPA 

determined that the rule amendments contain no regulatory 

requirements that might significantly or uniquely affect 
Page 125 of 246 

small governments because the amendments will not impose 

any new requirements that are not currently required by 

Part 98 promulgated on October 30, 2009 (i.e., calculating 

and reporting annual GHG emissions), and the rule 

amendments will not unfairly apply to small governments. 

Therefore, this action is not subject to the requirements 

of CAA section 203 of the UMRA. 

E. Executive Order 13132: Federalism

This action does not have federalism implications. It 

will not have substantial direct effects on the States, on 

the relationship between the national government and the 

States, or on the distribution of power and 

responsibilities among the various levels of government, as 

specified in Executive Order 13132. However, for a more 

detailed discussion about how these rule amendments will 

relate to existing State programs, please see Section II of 

the proposal preamble for the Mandatory GHG Reporting Rule 

(74 FR 16457-16461, April 10, 2009). 

These amendments apply directly to facilities that 

supply fuel that when used emit greenhouse gases or 

facilities that directly emit greenhouses gases. They do 

not apply to governmental entities unless the government 

entity owns a facility that directly emits greenhouse gases 

above threshold levels (such as a landfill), so relatively 
Page 126 of 246 

few government facilities will be affected. This 

regulation also does not limit the power of States or 

localities to collect GHG data and/or regulate GHG 

emissions. Thus, Executive Order 13132 does not apply to 

this action. 

Although section 6 of Executive Order 13132 does not 

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

officials or representatives of State and local governments 

in developing Part 98. A summary of EPA’s consultations 

with State and local governments is provided in Section 

VIII.E of the preamble to Part 98 (74 FR 56260, October 30, 

2009). 

F. Executive Order 13175: Consultation and Coordination 

with Indian Tribal Governments

This action does not have tribal implications, as 

specified in Executive Order 13175 (65 FR 67249, November 

9, 2000). The rule amendments will not result in any 

changes to the requirements of Part 98. Thus, Executive 

Order 13175 does not apply to this action. 

Although Executive Order 13175 does not apply to this 

action, EPA sought opportunities to provide information to 

Tribal governments and representatives during the 

development of the rules promulgated on October 30, 2009. 

A summary of the EPA’s consultations with Tribal officials 
Page 127 of 246 

is provided Sections VIII.E and VIII.F of the preamble to 

the 2009 Final Mandatory GHG Reporting Rule (74 FR 56260, 

October 30, 2009). 

G. Executive Order 13045: Protection of Children from 

Environmental Health Risks and Safety Risks

EPA interprets Executive Order 13045 (62 FR 19885, 

April 23, 1997) as applying only to those regulatory 

actions that concern health or safety risks, such that the 

analysis required under section 5-501 of the executive 

order has the potential to influence the regulation. This 

action is not subject to Executive Order 13045 because it 

does not establish an environmental standard intended to 

mitigate health or safety risks. 

H. Executive Order 13211: Actions that Significantly 

Affect Energy Supply, Distribution, or Use

This action is not subject to Executive Order 13211 

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

significant regulatory action under Executive Order 12866. 

I. National Technology Transfer and Advancement Act

Section 12(d) of the National Technology Transfer and 

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

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

standards in its regulatory activities unless to do so 

would be inconsistent with applicable law or otherwise 
Page 128 of 246 

impractical. Voluntary consensus standards are technical 

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

sampling procedures, and business practices) that are 

developed or adopted by voluntary consensus standards 

bodies. NTTAA directs EPA to provide Congress, through 

OMB, explanations when the Agency decides not to use 

available and applicable voluntary consensus standards. 

This rulemaking involves the use of one new voluntary 

consensus standard from ASTM. Specifically, EPA will allow 

facilities in the glass industry to use ASTM D6349-09 

Standard Test Method for Determination of Major and Minor 

Elements in Coal, Coke, and Solid Residues from Combustion 

of Coal and Coke by Inductively Coupled Plasma—Atomic 

Emission Spectrometry in addition to the methods 

incorporated by reference in Part 98. This additional 

voluntary consensus standard will provide an alternative 

method that owners or operators in the glass industry can 

use to monitor GHG emissions. No new test methods were 

developed for this action. 

J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and LowIncome Populations

Executive Order 12898 (59 FR 7629, February 16, 1994) 

establishes federal executive policy on environmental 
Page 129 of 246 

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 Part 98 does not have 

disproportionately high and adverse human health or 

environmental effects on minority or low-income populations 

because it does not affect the level of protection provided 

to human health or the environment because it is a rule 

addressing information collection and reporting procedures. 

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 
Page 130 of 246 

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 
Technical Corrections to Mandatory 

Reporting of GHGs – Final Rule 

131 of 246 

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

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

THE DATE 30 DAYS AFTER THE DATE OF PUBLICATION IN THE 

FEDERAL REGISTER].

List of Subjects

40 CFR Part 86 

Environmental protection, Administrative practice and 

procedure, Air pollution control, Reporting and 

recordkeeping requirements, Motor vehicle pollution. 

40 CFR Part 98 

Environmental protection, Administrative practice and 

procedure, Greenhouse gases, Incorporation by reference, 

Suppliers, Reporting and recordkeeping requirements. 

Dated: 

Lisa P. Jackson, 

Administrator. 
Page 132 of 246 

For the reasons set out in the preamble, title 40, 

Chapter I, of the Code of Federal Regulations is amended as 

follows: 

PART 86–[AMENDED] 

1. The authority citation for part 86 continues to 

read as follows: 

Authority: 42 U.S.C. 7401-7671q. 

2. Section 86.1844-01 is amended by adding paragraph 

(j) to read as follows: 

§86.1844-01 Information requirements: Application for 

certification and submittal of information upon request.

* * * * * 

(j) For complete heavy-duty vehicles only, measure 

CO2, N2O, and CH4 as described in this paragraph (j) with 

each certification test on an emission data vehicle. Do 

not apply deterioration factors to the results. Use the 

analytical equipment and procedures specified in 40 CFR 

part 1065 as needed to measure N2O and CH4. Report these 

values in your application for certification. The 

requirements of this paragraph (j) apply starting with 

model year 2011 for CO2 and 2012 for CH4. The requirements 

of this paragraph (j) related to N2O emissions apply for 

test groups that depend on NOx after-treatment to meet 

emission standards starting with model year 2013. 
Page 133 of 246 

Businesses that are defined as a small business by the 

Small Business Administration size standards in 13 CFR 

121.201 may omit measurement of N2O and CH4; other 

manufacturers may provide appropriate data and/or 

information and omit measurement of N2O and CH4 as described 

in 40 CFR 1065.5. Use the same measurement methods as for 

your other results to report a single value for CO2, N2O, 

and CH4. Round the final values as follows: 

(1) Round CO2 to the nearest 1 g/mi. 

(2) Round N2O to the nearest 0.001 g/mi. 

(3) Round CH4 to the nearest 0.001 g/mi. 

Part 98—[AMENDED] 

3. The authority citation for part 98 continues to 

read as follows: 

Authority: 42 U.S.C. 7401, et seq.

Subpart A—[Amended] 

4. Section 98.6 is amended by: 

a. Removing the definition of “Argon-oxygen 

decarburization (AOD) vessel.” 

b. Adding a definition for “Decarburization vessel.” 

c. Revising the definitions of “Carbonate-based 

mineral,” “Carbonate-based mineral mass fraction,” 

“Carbonate-based raw material,” “Crude oil,” “Gas 
Page 134 of 246 

collection system or landfill gas collection system,” 

“Mscf,” and “Non-crude feedstocks.” 

§98.6 Definitions.

* * * * * 

Carbonate-based mineral means any of the following 

minerals used in the manufacture of glass: calcium 

carbonate (CaCO3), calcium magnesium carbonate 

(CaMg(CO3)2), sodium carbonate (Na2CO3), barium carbonate 

(BaCO3), potassium carbonate (K2CO3), lithium carbonate 

(Li2CO3), and strontium carbonate (SrCO3). 

Carbonate-based mineral mass fraction means the 

following: for limestone, the mass fraction of calcium 

carbonate (CaCO3) in the limestone; for dolomite, the mass 

fraction of calcium magnesium carbonate (CaMg(CO3)2) in the 

dolomite; for soda ash, the mass fraction of sodium 

carbonate (Na2CO3) in the soda ash; for barium carbonate, 

the mass fraction of barium carbonate (BaCO3) in the barium 

carbonate; for potassium carbonate, the mass fraction of 

potassium carbonate (K2CO3) in the potassium carbonate; for 

lithium carbonate, the mass fraction of lithium carbonate 

(Li2CO3); and for strontium carbonate, the mass fraction of 

strontium carbonate (SrCO3). 
Page 135 of 246 

Carbonate-based raw material means any of the 

following materials used in the manufacture of glass: 

limestone, dolomite, soda ash, barium carbonate, potassium 

carbonate, lithium carbonate, and strontium carbonate. 

* * * * * 

Crude oil means a mixture of hydrocarbons that exists 

in liquid phase in natural underground reservoirs and 

remains liquid at atmospheric pressure after passing 

through surface separating facilities. Depending upon the 

characteristics of the crude stream, it may also include 

any of the following: 

(1) Small amounts of hydrocarbons that exist in 

gaseous phase in natural underground reservoirs but are 

liquid at atmospheric conditions (temperature and pressure) 

after being recovered from oil well (casing-head) gas in 

lease separators and are subsequently commingled with the 

crude stream without being separately measured. Lease 

condensate recovered as a liquid from natural gas wells in 

lease or field separation facilities and later mixed into 

the crude stream is also included. 

(2) Small amounts of non-hydrocarbons, such as sulfur 

and various metals. 

(3) Drip gases, and liquid hydrocarbons produced from 

tar sands, oil sands, gilsonite, and oil shale. 
Page 136 of 246 

(4) Petroleum products that are received or produced 

at a refinery and subsequently injected into a crude supply 

or reservoir by the same refinery owner or operator. 

Liquids produced at natural gas processing plants are 

excluded. Crude oil is refined to produce a wide array of 

petroleum products, including heating oils; gasoline, 

diesel and jet fuels; lubricants; asphalt; ethane, propane, 

and butane; and many other products used for their energy 

or chemical content. 

* * * * * 

Decarburization vessel means any vessel used to 

further refine molten steel with the primary intent of 

reducing the carbon content of the steel, including but not 

limited to vessels used for argon-oxygen decarburization 

and vacuum oxygen decarburization. 

* * * * * 

Gas collection system or landfill gas collection 

system means a system of pipes used to collect landfill gas 

from different locations in the landfill by means of a fan 

or similar mechanical draft equipment to a single location 

for treatment (thermal destruction) or use. Landfill gas 

collection systems may also include knock-out or separator 

drums and/or a compressor. A single landfill may have 

multiple gas collection systems. Landfill gas collection 
Page 137 of 246 

systems do not include “passive” systems, whereby landfill 

gas flows naturally to the surface of the landfill where an 

opening or pipe (vent) is installed to allow for natural 

gas flow. 

* * * * * 

Mscf means thousand standard cubic feet. 

* * * * * 

Non-crude feedstocks means any petroleum product or 

natural gas liquid that enters the refinery to be further 

refined or otherwise used on site. 

* * * * * 

5. Section 98.7 is amended by removing and reserving 

paragraph (a), and adding paragraph (e)(46). 

§98.7 What standardized methods are incorporated by 

reference into this part? 

* * * * * 

(e) * * * 

(46) ASTM D6349-09 Standard Test Method for 

Determination of Major and Minor Elements in Coal, Coke, 

and Solid Residues from Combustion of Coal and Coke by 

Inductively Coupled Plasma—Atomic Emission Spectrometry, 

IBR approved for §98.144(b). 

* * * * * 

Subpart E—[Amended] 
Page 138 of 246 

6. Section 98.53 is revised to read as follows: 

§98.53 Calculating GHG emissions. 

(a) You must determine annual N2O emissions from 

adipic acid production according to paragraphs (a)(1) or 

(a)(2) of this section. 

(1) Use a site-specific emission factor and 

production data according to paragraphs (b) through (i) of 

this section. 

(2) Request Administrator approval for an alternative 

method of determining N2O emissions according to paragraphs 

(a)(2)(i) and (a)(2)(ii) of this section. 

(i) You must submit the request within 45 days 

following promulgation of this subpart or within the first 

30 days of each subsequent reporting year. 

(ii) If the Administrator does not approve your 

requested alternative method within 150 days of the end of 

the reporting year, you must determine the N2O emissions for 

the current reporting period using the procedures specified 

in paragraphs (b) through (h) of this section. 

(b) You must conduct an annual performance test 

according to paragraphs (b)(1) through (b)(3) of this 

section. 

(1) You must conduct the test on the vent stream from 

the nitric acid oxidation step of the process, referred to 
Page 139 of 246 

as the test point, according to the methods specified in 

§98.54(b) through (f). If multiple adipic acid production 

units exhaust to a common abatement technology and/or 

emission point, you must sample each process in the ducts 

before the emissions are combined, sample each process when 

only one process is operating, or sample the combined 

emissions when multiple processes are operating and base 

the site-specific emission factor on the combined 

production rate of the multiple adipic acid production 

units. 

(2) You must conduct the performance test under 

normal process operating conditions. 

(3) You must measure the adipic acid production rate 

during the test and calculate the production rate for the 

test period in metric tons per hour. 

(c) Using the results of the performance test in 

paragraph (b) of this section, you must calculate an 

emission factor for each adipic acid unit according to 

Equation E-1 of this section: 

n

P

C Q

EF

n

N O

N O z

∑

∗ × ∗

=

−

1

7

2

2

1.14 10

, (Eq. E-1) 

Where: 
Page 140 of 246 

EFN2O,z = Average facility-specific N2O emission factor 

for each adipic acid production unit “z” (lb 

N2O/ton adipic acid produced). 

CN2O = N2O concentration per test run during the 

performance test (ppm N2O). 

1.14x10-7 = Conversion factor (lb/dscf-ppm N2O). 

Q = Volumetric flow rate of effluent gas per test 

run during the performance test (dscf/hr). 

P = Production rate per test run during the 

performance test (tons adipic acid 

produced/hr). 

n = Number of test runs. 

(d) If any N2O abatement technology “N” is located 

after your test point, you must determine the destruction 

efficiency according to paragraphs (d)(1), (d)(2), or 

(d)(3) of this section. 

(1) Use the manufacturer’s specified destruction 

efficiency. 

(2) Estimate the destruction efficiency through 

process knowledge. Examples of information that could 

constitute process knowledge include calculations based on 

material balances, process stoichiometry, or previous test 

results provided the results are still relevant to the 

current vent stream conditions. You must document how 

process knowledge was used to determine the destruction 

efficiency. 
Page 141 of 246 

(3) Calculate the destruction efficiency by 

conducting an additional performance test on the vent 

stream following the N2O abatement technology. 

(e) If any N2O abatement technology “N” is located 

after your test point, you must determine the annual amount 

of adipic acid produced while N2O abatement technology “N” 

is operating according to §98.54(f). Then you must 

calculate the abatement factor for N2O abatement technology 

“N” according to Equation E-2 of this section. 

z

a N

N

P

P

AF ,= (Eq. E-2) 

Where: 

AFN = Abatement utilization factor of N2O abatement 

technology “N” (fraction of annual production 

that abatement technology is operating). 

Pz,N = Annual adipic acid production during which N2O 

abatement technology “N” was used on unit “z” 

(ton adipic acid produced). 

Pz = Total annual adipic acid production from unit 

“z” (ton acid produced). 

(f) You must determine the annual amount of adipic 

acid produced according to §98.54(f). 

(g) You must calculate N2O emissions according to 

paragraph (g)(1), (g)(2), (g)(3), or (g)(4) of this section 

for each adipic acid production unit. 

(1) If one N2O abatement technology “N” is located 

after your test point, you must use the emissions factor 
Page 142 of 246 

(determined in Equation E-1 of this section), the 

destruction efficiency (determined in paragraph (d) of this 

section), the annual adipic acid production (determined in 

paragraph (f) of this section), and the abatement 

utilization factor (determined in paragraph (e) of this 

section), according to Equation E-3a of this section: 

( ( )) ,

, DF AF

EF P

E

N z z

a z

∗ − ∗

∗

= 1

2205

20 (Eq. E-3a) 

Where: 

Ea,z = Annual N2O mass emissions from adipic acid 

production unit “z” according to this Equation 

E-3a (metric tons). 

EFN2Oz = N2O emissions factor for unit “z” (lb N2O/ton 

adipic acid produced). 

Pz = Annual adipic acid produced from unit “z” 

(tons). 

DF = Destruction efficiency of N2O abatement 

technology “N” (percent of N2O removed from 

vent stream). 

AF = Abatement utilization factor of N2O abatement 

technology “N” (percent of time that the 

abatement technology is operating). 

2205 = Conversion factor (lb/metric ton). 

(2) If multiple N2O abatement technologies are located 

in series after your test point, you must use the emissions 

factor (determined in Equation E-1 of this section), the 

destruction efficiency (determined in paragraph (d) of this 

section), the annual adipic acid production (determined in 

paragraph (f) of this section), and the abatement 
Page 143 of 246 

utilization factor (determined in paragraph (e) of this 

section), according to Equation E-3b of this section: 

( ( )) *( ( )) * ... *( ( )) ,

, N N

N z z

b z DF AF DF AF DF AF

EF P

E ∗ − ∗ − ∗ − ∗

∗

= 1 1 1

2205 1 1 2 2

20 (Eq. E-3b) 

Where: 

Eb,z = Annual N2O mass emissions from adipic acid 

production unit “z” according to this Equation 

E-3b (metric tons). 

EFN2O,z = N2O emissions factor for unit “z” (lb N2O/ton 

adipic acid produced). 

Pz = Annual adipic acid produced from unit “z” 

(tons). 

DF1 = Destruction efficiency of N2O abatement 

technology 1 (percent of N2O removed from vent 

stream). 

AF1 = Abatement utilization factor of N2O abatement 

technology 1 (percent of time that abatement 

technology 1 is operating). 

DF2 = Destruction efficiency of N2O abatement 

technology 2 (percent of N2O removed from vent 

stream). 

AF2 = Abatement utilization factor of N2O abatement 

technology 2 (percent of time that abatement 

technology 2 is operating). 

DFN = Destruction efficiency of N2O abatement 

technology N (percent of N2O removed from vent 

stream). 

AFN = Abatement utilization factor of N2O abatement 

technology N (percent of time that abatement 

technology N is operating). 

2205 = Conversion factor (lb/metric ton). 

N = Number of different N2O abatement technologies. 

(3) If multiple N2O abatement technologies are located 

in parallel after your test point, you must use the 
Page 144 of 246 

emissions factor (determined in Equation E-1 of this 

section), the destruction efficiency (determined in 

paragraph (d) of this section), the annual adipic acid 

production (determined in paragraph (f) of this section), 

and the abatement utilization factor (determined in 

paragraph (e) of this section), according to Equation E-3c 

of this section: 

∗ ∑ − ∗

∗

=

N

N N N

N z z

c z DF AF FC

EF P

E

1

20 1

2205

(( ( ))* )

,

, (Eq. E-3c) 

Where: 

Ec,z = Annual N2O mass emissions from adipic acid 

production unit “z” according to this Equation 

E-3c (metric tons). 

EFN2O,z = N2O emissions factor for unit “z” (lb N2O/ton 

adipic acid produced). 

Pz = Annual adipic acid produced from unit “z” 

(tons). 

DFN = Destruction efficiency of N2O abatement 

technology “N” (percent of N2O removed from 

vent stream). 

AFN = Abatement utilization factor of N2O abatement 

technology “N”(percent of time that the 

abatement technology is operating). 

FCN = Fraction control factor of N2O abatement 

technology “N” (percent of total emissions from 

unit “z” that are sent to abatement technology 

“N”). 

2205 = Conversion factor (lb/metric ton). 

N = Number of different N2O abatement technologies 

with a fraction control factor. 

(4) If no N2O abatement technologies are located after 

your test point, you must use the emissions factor 
Page 145 of 246 

(determined using Equation E-1 of this section) and the 

annual adipic acid production (determined in paragraph (f) 

of this section) according to Equation E-3d of this section 

for each adipic acid production unit. 

2205

N 20 z

d z

EF P

E

∗

, = (Eq. E-3d) 

Where: 

Ed,z = Annual N2O mass emissions from adipic acid 

production for unit “z” according to this 

Equation E-3d (metric tons). 

EFN2O = N2O emissions factor for unit “z” (lb N2O/ton 

adipic acid produced). 

PZ = Annual adipic acid produced from unit “z” (tons). 

2205 = Conversion factor (lb/metric ton). 

(h) You must determine the emissions for the facility 

by summing the unit level emissions according to Equation 

E-4 of this section. 

∑=

= + + +

M

z

N O Ea z Eb z Ec z Ed z

1

2 , , , , (Eq. E-4) 

Where: 

Ea,z = Annual N2O mass emissions from adipic acid 

production unit “z” according to Equation E-3a of 

this section (metric tons). 

Eb,z = Annual N2O mass emissions from adipic acid 

production unit “z” according to Equation E-3b of 

this section (metric tons). 

Ec,z = Annual N2O mass emissions from adipic acid 

production unit “z” according to Equation E-3c of 

this section (metric tons). 

Ed,z = Annual N2O mass emissions from adipic acid 

production unit “z” according to Equation E-3d of 

this section (metric tons). 
Page 146 of 246 

M = Total number of adipic acid production units. 

(i) You must determine the amount of process N2O 

emissions that is sold or transferred off site (if 

applicable). You can determine the amount using existing 

process flow meters and N2O analyzers. 

7. Section 98.54 is amended by: 

a. Revising paragraph (a) introductory text. 

b. Adding second and third sentences to the end of 

paragraph (a)(1). 

c. Revising paragraph (a)(3). 

d. Revising paragraph (c) introductory text. 

e. Revising the first sentence of paragraph (d) 

introductory text. 

f. Revising paragraphs (e) and (f). 

§98.54 Monitoring and QA/QC requirements.

(a) You must conduct a new performance test and 

calculate a new emissions factor for each adipic acid 

production unit according to the frequency specified in 

paragraphs (a)(1) through (a)(3) of this section. 

(1) * * * The test must be conducted at a 

point during production that is representative of the 

average emissions rate from your process. You must 

document the methods used to determine the representative 

point. 
Page 147 of 246 

* * * * * 

(3) If you requested Administrator approval for an 

alternative method of determining N2O emissions under 

§98.53(a)(2), you must conduct the performance test if your 

request has not been approved by the Administrator within 

150 days of the end of the reporting year in which it was 

submitted. 

* * * * * 

(c) You must determine the adipic acid production 

rate during the performance test according to paragraph 

(c)(1) or (c)(2) of this section. 

* * * * * 

(d) You must determine the volumetric flow rate 

during the performance test in conjunction with the 

applicable EPA methods in 40 CFR part 60, appendices A-1 

through A-4. * * * 

* * * * * 

(e) You must determine the monthly amount of adipic 

acid produced. You must also determine the monthly amount 

of adipic acid produced during which N2O abatement 

technology, located after the test point, is operating. 

These monthly amounts are determined according to the 

methods in paragraphs (c)(1) or (c)(2) of this section. 
Page 148 of 246 

(f) You must determine the annual amount of adipic 

acid produced. You must also determine the annual amount 

of adipic acid produced during which N2O abatement 

technology located after the test point is operating. 

These are determined by summing the respective monthly 

adipic acid production quantities determined in paragraph 

(e) of this section. 

8. Section 98.56 is amended by: 

a. Revising the introductory text 

b. Revising paragraph (c). 

c. Revising paragraph (j) introductory text. 

d. Revising paragraph (j)(1). 

e. Revising paragraph (k) introductory text. 

f. Adding paragraph (l) 

§98.56 Data reporting requirements. 

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

each annual report must contain the information specified 

in paragraphs (a) through (l) of this section at the 

facility level. 

* * * * * 

(c) Annual adipic acid production during which N2O 

abatement technology (located after the test point) is 

operating (tons). 

* * * * * 
Page 149 of 246 

(j) If you conducted a performance test and 

calculated a site-specific emissions factor according to 

§98.53(a)(1), each annual report must also contain the 

information specified in paragraphs (j)(1) through (j)(7) 

of this section for each adipic acid production unit. 

(1) Emission factor (lb N2O/ton adipic acid). 

* * * * * 

(k) If you requested Administrator approval for an 

alternative method of determining N2O emissions under 

§98.53(a)(2), each annual report must also contain the 

information specified in paragraphs (k)(1) through (k)(4) 

of this section for each adipic acid production facility. 

(l) Fraction control factor for each abatement 

technology (percent of total emissions from the production 

unit that are sent to the abatement technology) if equation 

E-3c is used. 

* * * * * 

9. Section 98.57 is amended by revising paragraphs 

(c) and (f) to read as follows: 

§98.57 Records that must be retained. 

* * * * * 

(c) Number of facility and unit operating hours in 

calendar year. 

* * * * * 
Page 150 of 246 

(f) Performance test reports. 

* * * * * 

Subpart H—[Amended] 

10. Section 98.83 is amended by revising the 

introductory text of paragraph (d)(3); and by revising the 

definitions of “rm”, “TOCrm”, and “M” in Equation H-5 of 

paragraph (d)(3) to read as follows: 

§98.83 Calculating GHG emissions. 

* * * * * 

(d) * * * 

(3) CO2 emissions from raw materials. Calculate CO2

emissions from raw materials using Equation H-5 of this 

section: 

* * * * * 

rm = The amount of raw material i consumed 

annually, tons/yr (dry basis) or the amount of 

raw kiln feed consumed annually, tons/yr (dry 

basis). 

* * * * * 

TOCrm = Organic carbon content of raw material i or 

organic carbon content of combined raw kiln 

feed(dry basis), as determined in §98.84(c) or 

using a default factor of 0.2 percent of total 

raw material weight. 

M = Number of raw materials or 1 if calculating 

emissions based on combined raw kiln feed. 

* * * * * 

11. Section 98.84 is amended as follows: 
Page 151 of 246 

a. By revising paragraph (b). 

b. By revising paragraph (c). 

c. By revising paragraph (d). 

d. By revising paragraph (e). 

e. By revising paragraph (f). 

§98.84 Monitoring and QA/QC requirements. 

* * * * * 

(b) You must determine the weight fraction of total 

CaO and total MgO in clinker from each kiln using ASTM 

C114-09 Standard Test Methods for Chemical Analysis of 

Hydraulic Cement (incorporated by reference, see §98.7). 

The monitoring must be conducted monthly for each kiln from 

a monthly clinker sample drawn from bulk clinker storage if 

storage is dedicated to the specific kiln, or from a 

monthly arithmetic average of daily clinker samples drawn 

from the clinker conveying systems exiting each kiln. 

(c) The total organic carbon content (dry basis) of 

raw materials must be determined annually using ASTM C114-

09 Standard Test Methods for Chemical Analysis of Hydraulic 

Cement (incorporated by reference, see §98.7) or a similar 

industry standard practice or method approved for total 

organic carbon determination in raw mineral materials. The 

analysis must be conducted either on sample material drawn 

from bulk raw kiln feed storage or on sample material drawn 
Page 152 of 246 

from bulk raw material storage for each category of raw 

material (i.e., limestone, sand, shale, iron oxide, and 

alumina). Facilities that opt to use the default total 

organic carbon factor provided in §98.83(d)(3), are not 

required to monitor for TOC. 

(d) The quantity of clinker produced monthly by each 

kiln must be determined by direct weight measurement of 

clinker using the same plant techniques used for accounting 

purposes, such as reconciling weigh hopper or belt weigh 

feeder measurements against inventory measurements. As an 

alternative, facilities may also determine clinker 

production by direct measurement of raw kiln feed and 

application of a kiln-specific feed-to-clinker factor. 

Facilities that opt to use a feed-to-clinker factor must 

verify the accuracy of this factor on a monthly basis. 

(e) The quantity of CKD not recycled to the kiln 

generated by each kiln must be determined quarterly using 

the same plant techniques used for accounting purposes, 

such as direct weight measurement using weigh hoppers, 

truck weigh scales, or belt weigh feeders. 

(f) The annual quantity of raw kiln feed or annual 

quantity of each category of raw materials consumed by the 

facility (e.g., limestone, sand, shale, iron oxide, and 

alumina) must be determined monthly by direct weight 
Page 153 of 246 

measurement using the same plant instruments used for 

accounting purposes, such as weigh hoppers, truck weigh 

scales, or belt weigh feeders. 

* * * * * 

12. Section 98.86 is amended by: 

a. Revising paragraph (b)(3). 

b. Revising paragraph (b)(4). 

c. Revising paragraph (b)(12). 

d. Revising paragraph (b)(13). 

e. Adding paragraph (b)(15). 

§98.86 Data reporting requirements. 

* * * * * 

(b) * * * 

(3) Annual cement production at the facility. 

(4) Number of kilns and number of operating kilns. 

* * * * * 

(12) Annual organic carbon content of raw kiln feed 

or annual organic carbon content of each raw material (wtfraction, dry basis). 

(13) Annual consumption of raw kiln feed or annual 

consumption of each raw material (dry basis). 

* * * * * 

(15) Method used to determine the monthly clinker 

production from each kiln reported under (b)(2) of this 
Page 154 of 246 

section, including monthly kiln-specific clinker factors, 

if used. 

13. Section 98.87 is revised to read as follows: 

§98.87 Records that must be retained.

(a) If a CEMS is used to measure CO2 emissions, then 

in addition to the records required by §98.3(g), you must 

retain under this subpart the records required for the Tier 

4 Calculation Methodology in §98.37. 

(b) If a CEMS is not used to measure CO2 emissions, 

then in addition to the records required by §98.3(g), you 

must retain the records specified in paragraph (b) of this 

section for each portland cement manufacturing facility. 

(1) Documentation of monthly calculated kiln-specific 

clinker CO2 emission factor. 

(2) Documentation of quarterly calculated kilnspecific CKD CO2 emission factor. 

(3) Measurements, records and calculations used to 

determine reported parameters. 

Subpart K—[Amended] 

14. Section 98.112 is amended by revising paragraph 

(a) to read as follows:

§98.112 GHGs to report.

* * * * * 

(a) Process CO2 emissions from each electric arc 

furnace (EAF) used for the production of any ferroalloy 
Page 155 of 246 

listed in §98.110, and process CH4 emissions from each EAF 

that is used for the production of any ferroalloy listed in 

Table K-1 to subpart K. 

* * * * * 

15. Section 98.113 is amended by revising the 

introductory text to read as follows: 

§98.113 Calculating GHG emissions.

You must calculate and report the annual process CO2

emissions from each EAF not subject to paragraph (c) of 

this section using the procedures in either paragraph (a) 

or (b) of this section. For each EAF also subject to 

annual process CH4 emissions reporting, you must also 

calculate and report the annual process CH4 emissions from 

the EAF using the procedures in paragraph (d) of this 

section. 

* * * * * 

16. Section 98.116 is amended by: 

a. Revising paragraph (b). 

b. Revising paragraph (c). 

c. Revising paragraph (d) introductory text. 

d. Revising paragraph (d)(1). 

e. Revising paragraph (e)(1). 

§98.116 Data reporting requirements.

* * * * * 
Page 156 of 246 

(b) Annual production for each ferroalloy product 

identified in §98.110, from each EAF (tons). 

(c) Total number of EAFs at facility used for 

production of ferroalloy products. 

(d) If a CEMS is used to measure CO2 emissions, then 

you must report under this subpart the relevant information 

required by §98.36 for the Tier 4 Calculation Methodology 

and the following information specified in paragraphs 

(d)(1) through (d)(3) of this section. 

(1) Annual process CO2 emissions (in metric tons) from 

each EAF used for the production of any ferroalloy product 

identified in §98.110. 

* * * * * 

(e) * * * 

(1) Annual process CO2 emissions (in metric tons) from 

each EAF used for the production of any ferroalloy 

identified in §98.110 (metric tons). 

* * * * * 

Subpart N—[Amended] 

17. Section 98.144 is amended by revising paragraph 

(b) to read as follows: 

§98.144 Monitoring and QA/QC requirements.

* * * * * 
Page 157 of 246 

(b) You must measure carbonate-based mineral mass 

fractions at least annually to verify the mass fraction 

data provided by the supplier of the raw material; such 

measurements shall be based on sampling and chemical 

analysis using ASTM D3682-01 (Reapproved 2006) Standard 

Test Method for Major and Minor Elements in Combustion 

Residues from Coal Utilization Processes (incorporated by 

reference, see §98.7) or ASTM D6349-09 Standard Test Method 

for Determination of Major and Minor Elements in Coal, 

Coke, and Solid Residues from Combustion of Coal and Coke 

by Inductively Coupled Plasma—Atomic Emission Spectrometry 

(incorporated by reference, see §98.7). 

* * * * * 

18. Section 98.146 is amended by: 

a. Revising paragraph (a) introductory text. 

b. Revising paragraph (a)(2). 

c. Revising paragraph (b)(7). 

d. Revising paragraph (b)(9). 

§98.146 Data reporting requirements.

* * * * * 

(a) If a CEMS is used to measure CO2 emissions, then 

you must report under this subpart the relevant information 

required under §98.36 for the Tier 4 Calculation 
Page 158 of 246 

Methodology and the following information specified in 

paragraphs (a)(1) and (a)(2) of this section: 

* * * * * 

(2) Annual quantity of glass produced by each glass 

melting furnace and by all furnaces combined (tons). 

(b) * * * 

(7) Method used to determine fraction of calcination. 

* * * * * 

(9) The number of times in the reporting year that 

missing data procedures were followed to measure monthly 

quantities of carbonate-based raw materials or mass 

fraction of the carbonate-based minerals for any continuous 

glass melting furnace (months). 

19. Table N-1 to subpart N is amended by adding 

entries for “Barium carbonate,” “Potassium carbonate,” 

“Lithium carbonate,” and “Strontium carbonate” to the end 

of the table to read as follows: 

Table N-1 to Subpart N—CO2 Emission Factors for CarbonateBased Raw Materials 

Carbonate-Based Raw Material – 

Mineral 

CO2 Emission 

Factora

* * * * * * * 

Barium carbonate – BaCO3 0.223 

Potassium carbonate – K2CO3 0.318 

Lithium carbonate (Li2CO3) 0.596 

Strontium carbonate (SrCO3) 0.298 

a Emission factors in units of metric tons of CO2 emitted per 

metric ton of carbonate-based raw material charged to the 

furnace. 
Page 159 of 246 

Subpart O—[Amended] 

20. Section 98.154 is amended by: 

a. Revising the first and second sentence of 

paragraph (k). 

b. Revising the second sentence of paragraph (l) 

introductory text. 

c. Revising paragraph (o). 

§98.154 Monitoring and QA/QC requirements. 

* * * * * 

(k) The mass of HFC-23 emitted from process vents 

shall be estimated at least monthly by incorporating the 

results of the most recent emissions test into Equation O-7 

of this subpart. HCFC-22 production facilities that use a 

destruction device connected to the HCFC-22 production 

equipment shall conduct emissions tests at process vents at 

least once every five years or after significant changes to 

the process. * * * 

(l) * * * HFC-23 destruction facilities shall 

conduct annual measurements of HFC-23 concentrations at the 

outlet of the destruction device in accordance with EPA 

Method 18 at 40 CFR part 60, appendix A-6. * * * 

* * * * * 

(o) In their estimates of the mass of HFC-23 

destroyed, HFC-23 destruction facilities shall account for 
Page 160 of 246 

any temporary reductions in the destruction efficiency that 

result from any startups, shutdowns, or malfunctions of the 

destruction device, including departures from the operating 

conditions defined in State or local permitting 

requirements and/or destruction device manufacturer 

specifications. 

* * * * * 

21. Section 98.156 is amended by: 

a. Revising paragraph (b)(1). 

b. Revising paragraph (b)(3). 

c. Revising paragraph (c). 

d. Revising paragraph (d). 

e. Adding paragraph (e) introductory text. 

§98.156 Data reporting requirements.

* * * * * 

(b) * * * 

(1) Annual mass of HFC-23 fed into the destruction 

device. 

* * * * * 

(3) Annual mass of HFC-23 emitted from the 

destruction device. 

(c) Each HFC-23 destruction facility shall report the 

concentration (mass fraction) of HFC-23 measured at the 

outlet of the destruction device during the facility’s 
Page 161 of 246 

annual HFC-23 concentration measurements at the outlet of 

the device. 

(d) If the HFC-23 concentration measured pursuant to 

§98.154(l) is greater than that measured during the 

performance test that is the basis for the destruction 

efficiency (DE), the facility shall report the revised 

destruction efficiency calculated under §98.154(l) and the 

values used to calculate it, specifying whether 

§98.154(l)(1) or §98.154(l)(2) has been used for the 

calculation. Specifically, the facility shall report the 

following: 

(1) Flow rate of HFC-23 being fed into the 

destruction device in kg/hr. 

(2) Concentration (mass fraction) of HFC-23 at the 

outlet of the destruction device. 

(3) Flow rate at the outlet of the destruction device 

in kg/hr. 

(4) Emission rate (in kg/hr) calculated from 

paragraphs (d)(2) and (d)(3) of this section. 

(5) Destruction efficiency (DE) calculated from 

paragraphs (d)(1) and (d)(4) of this section. 

(e) By March 31, 2011 or within 60 days of commencing 

HFC-23 destruction, HFC-23 destruction facilities shall 
Page 162 of 246 

submit a one-time report including the following 

information for each destruction process: 

* * * * * 

22. Section 98.157 is amended by revising paragraph 

(b)(1) to read as follows: 

§98.157 Records that must be retained.

* * * * * 

(b) * * * 

(1) Records documenting their one-time and annual 

reports in §98.156(b) through (e). 

* * * * * 

Subpart P—[Amended] 

23. Section 98.160 is amended by revising paragraph 

(c) to read as follows: 

§98.160 Definition of the source category.

* * * * * 

(c) This source category includes merchant hydrogen 

production facilities located within another facility if 

they are not owned by, or under the direct control of, the 

other facility’s owner and operator. 

24. Section 98.162 is amended by revising paragraph 

(a); and by removing and reserving paragraph (b) to read as 

follows: 

§98.162 GHGs to report.
Page 163 of 246 

* * * * * 

(a) CO2 emissions from each hydrogen production 

process unit. 

(b) [Reserved] 

* * * * * 

25. Section 98.163 is amended by: 

a. Revising the introductory text. 

b. Revising paragraph (a). 

c. Revising paragraph (b) introductory text. 

d. In paragraph (b)(1), revising the only sentence, 

and revising the definition of “CO2” in Equation P-1. 

e. Revising the only sentences of paragraphs (b)(2) 

and (b)(3). 

§98.163 Calculating GHG emissions.

You must calculate and report the annual CO2 emissions 

from each hydrogen production process unit using the 

procedures specified in either paragraph (a) or (b) of this 

section. 

(a) Continuous Emissions Monitoring Systems (CEMS). 

Calculate and report under this subpart the CO2 emissions by 

operating and maintaining CEMS according to the Tier 4 

Calculation Methodology specified in §98.33(a)(4) and all 

associated requirements for Tier 4 in subpart C of this 

part (General Stationary Fuel Combustion Sources). 
Page 164 of 246 

(b) Fuel and feedstock material balance approach. 

Calculate and report CO2 emissions as the sum of the annual 

emissions associated with each fuel and feedstock used for 

hydrogen production by following paragraphs (b)(1) through 

(b)(3) of this section. 

(1) Gaseous fuel and feedstock. You must calculate 

the annual CO2 emissions from each gaseous fuel and 

feedstock according to Equation P-1 of this section: 

* * * * * 

CO2 = Annual CO2 emissions arising from fuel and 

feedstock consumption (metric tons/yr). 

* * * * * 

(2) Liquid fuel and feedstock. You must calculate 

the annual CO2 emissions from each liquid fuel and feedstock 

according to Equation P-2 of this section: 

* * * * * 

(3) Solid fuel and feedstock. You must calculate the 

annual CO2 emissions from each solid fuel and feedstock 

according to Equation P-3 of this section: 

* * * * * 

26. Section 98.166 is amended by: 

a. Revising the introductory text. 

b. Revising paragraph (a)(1). 

c. Revising paragraph (b)(1). 

d. Revising paragraph (c). 
Page 165 of 246 

§98.166 Data reporting requirements. 

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

each annual report must contain the information specified 

in paragraphs (a) or (b) of this section, as appropriate, 

and paragraphs (c) and (d) of this section: 

(a) * * * 

(1) Unit identification number and annual CO2

emissions. 

* * * * * 

(b) * * * 

(1) Unit identification number and annual CO2

emissions. 

* * * * * 

(c) Quantity of CO2 collected and transferred off site 

in either gas, liquid, or solid forms, following the 

requirements of subpart PP of this part. 

* * * * * 

Subpart Q—[Amended] 

27. Section 98.172 is amended by revising paragraphs 

(b) and (c) to read as follows: 

§98.172 GHGs to report.

* * * * * 

(b) You must report CO2 emissions from flares that 

burn blast furnace gas or coke oven gas according to the 
Page 166 of 246 

procedures in §98.253(b)(1) of subpart Y (Petroleum 

Refineries) of this part. When using the alternatives set 

forth in §98.253(b)(1)(ii)(B) and §98.253(b)(1)(iii)(C), 

you must use the default CO2 emission factors for coke oven 

gas and blast furnace gas from Table C-1 to subpart C in 

Equations Y-2 and Y-3 of subpart Y. You must report CH4 and 

N2O emissions from flares according to the requirements in 

§98.33(c)(2) using the emission factors for coke oven gas 

and blast furnace gas in Table C-2 to subpart C of this 

part. 

(c) You must report process CO2 emissions from each 

taconite indurating furnace; basic oxygen furnace; nonrecovery coke oven battery combustion stack; coke pushing 

process; sinter process; EAF; decarburization vessel; and 

direct reduction furnace by following the procedures in 

this subpart. 

28. Section 98.173 is amended by: 

a. Revising the first sentence of the introductory 

text. 

b. In paragraph (b)(1)(vi), revising the introductory 

text and the definition of “CO2” in Equation Q-6 of subpart 

Q. 

c. Revising the first sentence of paragraph (d). 

§98.173 Calculating GHG emissions.
Page 167 of 246 

You must calculate and report the annual process CO2

emissions from each taconite indurating furnace, basic 

oxygen furnace, non-recovery coke oven battery, sinter 

process, EAF, decarburization vessel, and direct reduction 

furnace using the procedures in either paragraph (a) or (b) 

of this section. * * * 

(b) * * * 

(1) * * * 

(vi) For decarburization vessels, estimate CO2 

emissions using Equation Q-6 of this section. 

* * * * * 

CO2 = Annual CO2 mass emissions from the 

decarburization vessel (metric tons). 

* * * * * 

(d) If GHG emissions from a taconite indurating 

furnace, basic oxygen furnace, non-recovery coke oven 

battery, sinter process, EAF, decarburization vessel, or 

direct reduction furnace are vented through the same stack 

as any combustion unit or process equipment that reports CO2

emissions using a CEMS that complies with the Tier 4 

Calculation Methodology in subpart C of this part (General 

Stationary Fuel Combustion Sources), then the calculation 

methodology in paragraph (b) of this section shall not be 

used to calculate process emissions. * * * 
Page 168 of 246 

29. Section 98.174 is amended by revising the first 

sentence of paragraph (c)(2) and revising paragraph (c)(7) 

to read as follows: 

§98.174 Monitoring and QA/QC requirements.

* * * * * 

(c) * * * 

(2) For the furnace exhaust from basic oxygen 

furnaces, EAFs, decarburization vessels, and direct 

reduction furnaces, sample the furnace exhaust for at least 

three complete production cycles that start when the 

furnace is being charged and end after steel or iron and 

slag have been tapped. * * * 

* * * * * 

(7) If your EAF and decarburization vessel exhaust to 

a common emission control device and stack, you must sample 

each process in the ducts before the emissions are 

combined, sample each process when only one process is 

operating, or sample the combined emissions when both 

processes are operating and base the site-specific emission 

factor on the steel production rate of the EAF. 

* * * * * 

30. Section 98.175 is amended by revising the 

introductory text to read as follows: 

§98.175 Procedures for estimating missing data.
Page 169 of 246 

A complete record of all measured parameters used in 

the GHG emissions calculations in §98.173 is required. 

Therefore, whenever a quality-assured value of a required 

parameter is unavailable, a substitute data value for the 

missing parameter shall be used in the calculations as 

specified in the paragraphs (a) and (b) of this section. 

You must follow the missing data procedures in §98.255(b) 

of subpart Y (Petroleum Refineries) of this part for flares 

burning coke oven gas or blast furnace gas. You must 

document and keep records of the procedures used for all 

such estimates. 

* * * * * 

31. Section 98.176 is amended by: 

a. Revising the introductory text. 

b. Revising paragraph (c). 

c. Revising paragraph (e)(3). 

d. Adding paragraphs (g) and (h). 

§98.176 Data reporting requirements.

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

each annual report must contain the information required in 

paragraphs (a) through (h) of this section for each coke 

pushing operation; taconite indurating furnace; basic 

oxygen furnace; non-recovery coke oven battery; sinter 

process; EAF; decarburization vessel; direct reduction 
Page 170 of 246 

furnace; and flare burning coke oven gas or blast furnace 

gas. For reporting year 2010, the information required in 

paragraphs (a) through (h) of this section is not required 

for decarburization vessels that are not argon-oxygen 

decarburization vessels. For reporting year 2011 and each 

subsequent reporting year, the information in paragraphs 

(a) through (h) of this section must be reported for all 

decarburization vessels. 

* * * * * 

(c) If a CEMS is used to measure CO2 emissions, then 

you must report the relevant information required under 

§98.36 for the Tier 4 Calculation Methodology. 

* * * * * 

(e) * * * 

(3) The annual volume of each type of gaseous fuel 

(reported separately for each type in standard cubic feet), 

the annual volume of each type of liquid fuel (reported 

separately for each type in gallons), and the annual mass 

(in metric tons) of each other process inputs and outputs 

used to determine CO2 emissions. 

* * * * * 

(g) The annual amount of coal charged to the coke 

ovens (in metric tons). 
Page 171 of 246 

(h) For flares burning coke oven gas or blast furnace 

gas, the information specified in §98.256(e) of subpart Y 

(Petroleum Refineries) of this part. 

32. Section 98.177 is amended by revising paragraph 

(d) to read as follows: 

§98.177 Records that must be retained.

* * * * * 

(d) Annual operating hours for each taconite 

indurating furnace, basic oxygen furnace, non-recovery coke 

oven battery, sinter process, electric arc furnace, 

decarburization vessel, and direct reduction furnace. 

* * * * * 

Subpart S—[Amended] 

33. Section 98.190 is amended by revising paragraph 

(a) to read as follows: 

§98.190 Definition of the source category.

(a) Lime manufacturing plants (LMPs) engage in the 

manufacture of a lime product (e.g., calcium oxide, highcalcium quicklime, calcium hydroxide, hydrated lime, 

dolomitic quicklime, dolomitic hydrate, or other lime 

products) by calcination of limestone, dolomite, shells or 

other calcareous substances as defined in 40 CFR 

63.7081(a)(1). 

* * * * * 
Page 172 of 246 

34. Section 98.193 is amended by: 

a. In paragraph (b)(2)(i), revising the second 

sentence and the definition of "2000/2205" in Equation S-1. 

b. In paragraph (b)(2)(ii), revising the only 

sentence and the definitions of "EFLKD,i,n", "CaOLKD,i,n", 

"MgOLKD,i,n", and "2000/2205" in Equation S-2. 

c. In paragraph (b)(2)(iii), revising the only 

sentence and the definitions of "Ewaste,i", "CaOwaste,i", 

"MgOwaste,i", "Mwaste,i", and "2000/2205" in Equation S-3. 

d. In Paragraph (b)(2)(iv), revising the definitions 

of "EFLIME,i,n", "MLIME,i,n", "EFLKD,i,n", "MLKD,i,n", "Ewaste,i", "t", 

"b", and "z" in Equation S-4. 

§98.193 Calculating GHG emissions. 

* * * * * 

(b) * * * 

(2) * * * 

(i) * * * Calcium oxide and magnesium oxide 

content must be analyzed monthly for each lime product type 

that is produced: 

* * * * * 

2000/2205 = Conversion factor for tons to metric tons. 

(ii) You must calculate a monthly emission factor for 

each type of calcined byproduct/waste sold (including lime 

kiln dust) using Equation S-2 of this section: 
Page 173 of 246 

* * * * * 

EFLKD,i,n = Emission factor for calcined lime 

byproduct/waste type i sold, for month n 

(metric tons CO2/ton lime byproduct). 

* * * * * 

CaOLKD,i,n = Calcium oxide content for calcined lime 

byproduct/waste type i sold, for month n 

(metric tons CaO/metric ton lime). 

MgOLKD,i,n = Magnesium oxide content for calcined lime 

byproduct/waste type i sold, for month n 

(metric tons MgO/metric ton lime). 

2000/2205 = Conversion factor for tons to metric tons. 

(iii) You must calculate the annual CO2 emissions from 

each type of calcined byproduct/waste that is not sold 

(including lime kiln dust and scrubber sludge) using 

Equation S-3 of this section: 

* * * * * 

Ewaste,i = Annual CO2 emissions for calcined lime 

byproduct/waste type i that is not sold 

(metric tons CO2). 

* * * * * 

CaOwaste,i = Calcium oxide content for calcined lime 

byproduct/waste type i that is not sold 

(metric tons CaO/metric ton lime). 

MgOwaste,i = Magnesium oxide content for calcined lime 

byproduct/waste type i that is not sold 

(metric tons MgO/metric ton lime). 

Mwaste,i = Annual weight or mass of calcined 

byproducts/wastes for lime type i that is not 

sold (tons). 

2000/2205 = Conversion factor for tons to metric tons. 

(iv) * * * * * 
Page 174 of 246 

EFLIME,i,n = Emission factor for lime type i produced, in 

calendar month n (metric tons CO2/ton lime) 

from Equation S-1 of this section. 

MLIME,i,n = Weight or mass of lime type i produced in 

calendar month n (tons). 

EFLKD,i,n = Emission factor of calcined byproducts/wastes 

sold for lime type i in calendar month n, 

(metric tons CO2/ton byproduct/waste) from 

Equation S-2 of this section. 

MLKD,i,n = Monthly weight or mass of calcined 

byproducts/waste sold (such as lime kiln dust, 

LKD) for lime type i in calendar month n 

(tons). 

Ewaste,i = Annual CO2 emissions for calcined lime 

byproduct/waste type i that is not sold 

(metric tons CO2) from Equation S-3 of this 

section. 

t = Number of lime types produced 

b = Number of calcined byproducts/wastes that are 

sold 

z = Number of calcined byproducts/wastes that are 

not sold 

* * * * * 

35. Section 98.194 is amended by: 

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

b. Revising paragraph (c) introductory text. 

c. Revising paragraph (d). 

§98.194 Monitoring and QA/QC requirements.

(a) You must determine the total quantity of each 

type of lime product that is produced and each calcined 

byproduct/waste (such as lime kiln dust) that is sold.* * * 

* * * * * 
Page 175 of 246 

(c) You must determine the chemical composition 

(percent total CaO and percent total MgO) of each type of 

lime product that is produced and each type of calcined 

byproduct/waste sold according to paragraph (c)(1) or 

(c)(2) of this section. You must determine the chemical 

composition of each type of lime product that is produced 

and each type of calcined byproduct/waste sold on a monthly 

basis. You must determine the chemical composition for 

each type of calcined byproduct/waste that is not sold on 

an annual basis. 

* * * * * 

(d) You must use the analysis of calcium oxide and 

magnesium oxide content of each lime product that is 

produced and that is collected during the same month as the 

production data in monthly calculations. 

* * * * * 

36. Section 98.195 is amended by revising the first 

sentence of the introductory text; and by revising 

paragraph (a) to read as follows: 

§98.195 Procedures for estimating missing data.

For the procedure in §98.193(b)(1), a complete record 

of all measured parameters used in the GHG emissions 

calculations is required (e.g., oxide content, quantity of 

lime products, etc.). * * * 
Page 176 of 246 

(a) For each missing value of the quantity of lime 

produced (by lime type), and quantity of calcined 

byproduct/waste produced and sold, the substitute data 

value shall be the best available estimate based on all 

available process data or data used for accounting 

purposes. 

* * * * * 

37. Section 98.196 is revised to read as follows: 

§98.196 Data reporting requirements.

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

each annual report must contain the information specified 

in paragraphs (a) or (b) of this section, as applicable. 

(a) If a CEMS is used to measure CO2 emissions, then 

you must report under this subpart the relevant information 

required by §98.36 and the information listed in paragraphs 

(a)(1) through (a)(8) of this section. 

(1) Method used to determine the quantity of lime 

that is produced and sold. 

(2) Method used to determine the quantity of calcined 

lime byproduct/waste sold. 

(3) Beginning and end of year inventories for each 

lime product that is produced, by type. 

(4) Beginning and end of year inventories for 

calcined lime byproducts/wastes sold, by type. 
Page 177 of 246 

(5) Annual amount of calcined lime byproduct/waste 

sold, by type (tons). 

(6) Annual amount of lime product sold, by type 

(tons). 

(7) Annual amount of calcined lime byproduct/waste 

that is not sold, by type (tons). 

(8) Annual amount of lime product not sold, by type 

(tons). 

(b) If a CEMS is not used to measure CO2 emissions, 

then you must report the information listed in paragraphs 

(b)(1) through (b)(17) of this section. 

(1) Annual CO2 process emissions from all kilns 

combined (metric tons). 

(2) Monthly emission factors for each lime type 

produced. 

(3) Monthly emission factors for each calcined 

byproduct/waste by lime type that is sold. 

(4) Standard method used (ASTM or NLA testing method) 

to determine chemical compositions of each lime type 

produced and each calcined lime byproduct/waste type. 

(5) Monthly results of chemical composition analysis 

of each type of lime product produced and calcined 

byproduct/waste sold. 
Page 178 of 246 

(6) Annual results of chemical composition analysis 

of each type of lime byproduct/waste that is not sold. 

(7) Method used to determine the quantity of lime 

produced and/or lime sold. 

(8) Monthly amount of lime product sold, by type 

(tons). 

(9) Method used to determine the quantity of calcined 

lime byproduct/waste sold. 

(10) Monthly amount of calcined lime byproduct/waste 

sold, by type (tons). 

(11) Annual amount of calcined lime byproduct/waste 

that is not sold, by type (tons). 

(12) Monthly weight or mass of each lime type 

produced (tons). 

(13) Beginning and end of year inventories for each 

lime product that is produced. 

(14) Beginning and end of year inventories for 

calcined lime byproducts/wastes sold. 

(15) Annual lime production capacity (tons) per 

facility. 

(16) Number of times in the reporting year that 

missing data procedures were followed to measure lime 

production (months) or the chemical composition of lime 

products sold (months). 
Page 179 of 246 

(17) Indicate whether CO2 was used on-site (i.e. for 

use in a purification process). If CO2 was used on-site, 

provide the information in paragraphs (b)(17)(i) and 

(b)(17)(ii) of this section. 

(i) The annual amount of CO2 captured for use in the 

on-site process. 

(ii) The method used to determine the amount of CO2

captured. 

Subpart V—[Amended] 

38. Section 98.223 is amended by: 

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

b. Revising paragraph (b) introductory text. 

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

d. Revising paragraph (c). 

e. Revising paragraph (d) introductory text. 

f. Revising paragraph (e). 

g. Removing and reserving paragraph (f). 

h. Revising paragraph (g). 

i. Adding paragraph (i). 

§98.223 Calculating GHG emissions. 

(a) * * * 

(1) Use a site-specific emission factor and 

production data according to paragraphs (b) through (i) of 

this section. 
Page 180 of 246 

(2) * * * 

(ii) If the Administrator does not approve your 

requested alternative method within 150 days of the end of 

the reporting year, you must determine the N2O emissions for 

the current reporting period using the procedures specified 

in paragraph (a)(1) of this section. 

(b) You must conduct an annual performance test for 

each nitric acid train according to paragraphs (b)(1) 

through (b)(3) of this section. 

(1) You must conduct the performance test at the 

absorber tail gas vent, referred to as the test point, for 

each nitric acid train according to §98.224(b) through (f). 

If multiple nitric acid production units exhaust to a 

common abatement technology and/or emission point, you must 

sample each process in the ducts before the emissions are 

combined, sample each process when only one process is 

operating, or sample the combined emissions when multiple 

processes are operating and base the site-specific emission 

factor on the combined production rate of the multiple 

nitric acid production units. 

(2) You must conduct the performance test under 

normal process operating conditions. 

* * * * * 
Page 181 of 246 

(c) Using the results of the performance test in 

paragraph (b) of this section, you must calculate an 

average site-specific emission factor for each nitric acid 

train “t” according to Equation V-1 of this section: 

n

P

C Q

EF

n

N O

N Ot

∑

∗ × ∗

=

−

1

7

2

2

1.14 10

(Eq. V-1) 

Where: 

EFN2Ot = Average site-specific N2O emissions factor for 

nitric acid train “t” (lb N2O/ton nitric acid 

produced, 100 percent acid basis). 

CN2O = N2O concentration for each test run during the 

performance test (ppm N2O). 

1.14x10-7= Conversion factor (lb/dscf-ppm N2O). 

Q = Volumetric flow rate of effluent gas for each 

test run during the performance test (dscf/hr). 

P = Production rate for each test run during the 

performance test (tons nitric acid produced per 

hour, 100 percent acid basis). 

n = Number of test runs. 

(d) If nitric acid train “t” exhausts to any N2O 

abatement technology “N” after the test point, you must 

determine the destruction efficiency for each N2O abatement 

technology “N” according to paragraphs (d)(1), (d)(2), or 

(d)(3) of this section. 

* * * * * 

(e) If nitric acid train “t” exhausts to any N2O 

abatement technology “N” after the test point, you must 
Page 182 of 246 

determine the annual amount of nitric acid produced on 

train “t” while N2O abatement technology “N” is operating 

according to §98.224(f). Then you must calculate the 

abatement utilization factor for each N2O abatement 

technology “N” for each nitric acid train “t” according to 

Equation V-2 of this section. 

t

t N

t N

P

P

AF ,

, = (Eq. V-2) 

Where: 

AFt,N = Abatement utilization factor of N2O abatement 

technology “N” at nitric acid train “t” 

(fraction of annual production that 

abatement technology is operating). 

Pt = Total annual nitric acid production from 

nitric acid train “t” (ton acid produced, 

100 percent acid basis). 

Pa,t,N = Annual nitric acid production from nitric 

acid train “t” during which N2O abatement 

technology “N” was operational (ton acid 

produced, 100 percent acid basis). 

(f) [Reserved] 

(g) You must calculate N2O emissions for each nitric 

acid train “t” according to paragraph (g)(1), (g)(2), 

(g)(3), or (g)(4) of this section. 

(1) If nitric acid train “t” exhausts to one N2O 

abatement technology “N” after the test point, you must use 

the emissions factor (determined in Equation V-1 of this 

section), the destruction efficiency (determined in 

paragraph (d) of this section), the annual nitric acid 
Page 183 of 246 

production (determined in paragraph (i) of this section), 

and the abatement utilization factor (determined in 

paragraph (e) of this section) according to Equation V-3a 

of this section: 

( (DF AF))

EF P

E

N t t

N Ot ∗ − ∗

∗

= 1

2205

20

2 (Eq. V-3a) 

Where: 

EN2Ot = Annual N2O mass emissions from nitric acid 

production unit “t” according to this Equation 

V-3a (metric tons). 

EFN2Ot = Average site-specific N2O emissions factor for 

nitric acid train ”t” (lb N2O/ton acid 

produced, 100 percent acid basis). 

Pt = Annual nitric acid production from the train 

“t” (ton acid produced, 100 percent acid 

basis). 

DF = Destruction efficiency of N2O abatement 

technology N that is used on nitric acid train 

“t” (percent of N2O removed from vent stream). 

AF = Abatement utilization factor of N2O abatement 

technology “N” for nitric acid train “t” 

(percent of time that the abatement technology 

is operating). 

2205 = Conversion factor (lb/metric ton). 

(2) If multiple N2O abatement technologies are located 

in series after your test point, you must use the emissions 

factor (determined in Equation V-1 of this section), the 

destruction efficiency (determined in paragraph (d) of this 

section), the annual nitric acid production (determined in 

paragraph (f) of this section), and the abatement 

utilization factor (determined in paragraph (e) of this 

section), according to Equation V-3b of this section: 
Page 184 of 246 

( ( )) *( ( )) * ... *( ( )) ,

N N

N t t

N Ot DF AF DF AF DF AF

EF P

E ∗ − ∗ − ∗ − ∗

∗

= 1 1 1

2205 1 1 2 2

20

2 (Eq. V-3b)

Where: 

EN2Ot = Annual N2O mass emissions from nitric acid 

production unit “t” according to this Equation 

V-3b (metric tons). 

EFN2O,t = N2O emissions factor for unit “t” (lb N2O/ton 

nitric acid produced). 

Pt = Annual nitric acid produced from unit “t” (ton 

acid produced, 100 percent acid basis). 

DF1 = Destruction efficiency of N2O abatement 

technology 1 (percent of N2O removed from vent 

stream). 

AF1 = Abatement utilization factor of N2O abatement 

technology 1 (percent of time that abatement 

technology 1 is operating). 

DF2 = Destruction efficiency of N2O abatement 

technology 2 (percent of N2O removed from vent 

stream). 

AF2 = Abatement utilization factor of N2O abatement 

technology 2 (percent of time that abatement 

technology 2 is operating). 

DFN = Destruction efficiency of N2O abatement 

technology N (percent of N2O removed from vent 

stream). 

AFN = Abatement utilization factor of N2O abatement 

technology N (percent of time that abatement 

technology N is operating). 

2205 = Conversion factor (lb/metric ton). 

N = Number of different N2O abatement technologies. 

(3) If multiple N2O abatement technologies are located 

in parallel after your test point, you must use the 

emissions factor (determined in Equation V-1 of this 

section), the destruction efficiency (determined in 
Page 185 of 246 

paragraph (d) of this section), the annual nitric acid 

production (determined in paragraph (f) of this section), 

and the abatement utilization factor (determined in 

paragraph (e) of this section), according to Equation V-3c 

of this section: 

∗ ∑ − ∗

∗

=

N

N N N

N t t

N Ot DF AF FC

EF P

E

1

20

2

1

2205

(( ( )) * )

, (Eq. V-3c) 

Where: 

EN2Ot = Annual N2O mass emissions from nitric acid 

production unit “t” according to this Equation 

V-3c (metric tons). 

EFN2O,t = N2O emissions factor for unit “t” (lb N2O/ton 

nitric acid produced). 

Pt = Annual nitric acid produced from unit “t” (ton 

acid produced, 100 percent acid basis). 

DFN = Destruction efficiency of N2O abatement 

technology “N” (percent of N2O removed from 

vent stream). 

AFN = Abatement utilization factor of N2O abatement 

technology “N” (percent of time that abatement 

technology “N” is operating). 

FCN = Fraction control factor of N2O abatement 

technology “N” (percent of total emissions from 

unit “t” that are sent to abatement technology 

“N”). 

2205 = Conversion factor (lb/metric ton). 

N = Number of different N2O abatement technologies 

with a fraction control factor. 

(4) If nitric acid train “t” does not exhaust to any 

N2O abatement technology after the test point, you must use 

the emissions factor (determined in Equation V-1 of this 
Page 186 of 246 

section), and the annual nitric acid production (determined 

in paragraph (i) of this section) according to Equation V3b of this section: 

2205

20

2

N t t

N Ot

EF P

E

*

= (Eq. V-3d) 

Where: 

EN2Ot = Annual N2O mass emissions from nitric acid 

production unit “t” according to this 

Equation V-3d (metric tons). 

EFN2Ot = Average site-specific N2O emissions factor 

for nitric acid train ”t” (lb N2O/ton acid 

produced, 100 percent acid basis). 

Pt = Annual nitric acid production from nitric 

acid train “t” (ton acid produced, 100 

percent acid basis). 

2205 = Conversion factor (lb/metric ton). 

* * * * * 

(i) You must determine the total annual amount of 

nitric acid produced on nitric acid train “t” for each 

nitric acid train (tons acid produced, 100 percent acid 

basis), according to §98.224(f). 

39. Section 98.224 is amended by: 

a. Revising paragraph (a). 

b. Revising the first sentence in paragraph (d) 

introductory text. 

c. Revising paragraphs (e) and (f). 

§98.224 Monitoring and QA/QC requirements.
Page 187 of 246 

(a) You must conduct a new performance test according 

to a test plan as specified in paragraphs (a)(1) through 

(a)(3) of this section. 

(1) Conduct the performance test annually. The test 

should be conducted at a point during the campaign which is 

representative of the average emissions rate from the 

nitric acid campaigns. Facilities must document the 

methods used to determine the representative point of the 

campaign when the performance test is conducted. 

(2) Conduct the performance test when your nitric 

acid production process is changed, specifically when 

abatement equipment is installed. 

(3) If you requested Administrator approval for an 

alternative method of determining N2O emissions under 

§98.223(a)(2), you must conduct the performance test if 

your request has not been approved by the Administrator 

within 150 days of the end of the reporting year in which 

it was submitted. 

* * * * * 

(d) You must determine the volumetric flow rate 

during the performance test in conjunction with the 

applicable EPA methods in 40 CFR part 60, appendices A-1 

through A-4. * * * 

* * * * * 
Page 188 of 246 

(e) You must determine the total monthly amount of 

nitric acid produced. You must also determine the monthly 

amount of nitric acid produced while N2O abatement 

technology (located after the test point) is operating from 

each nitric acid train. These monthly amounts are 

determined according to the methods in paragraphs (c)(1) or 

(c)(2) of this section. 

(f) You must determine the annual amount of nitric 

acid produced. You must also determine the annual amount 

of nitric acid produced while N2O abatement technology 

(located after the test point) is operating for each train. 

These annual amounts are determined by summing the 

respective monthly nitric acid quantities determined in 

paragraph (e) of this section. 

40. Section 98.226 is amended by: 

a. Revising the introductory text. 

b. Revising paragraph (g). 

c. Revising paragraph (m) introductory text. 

d. Revising paragraph (n) introductory text. 

e. Adding paragraph (p). 

§98.226 Data reporting requirements. 

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

each annual report must contain the information specified 

in paragraphs (a) through (p) of this section. 
Page 189 of 246 

* * * * * 

(g) Number of different N2O abatement technologies per 

nitric acid train “t”. 

* * * * * 

(m) If you conducted a performance test and 

calculated a site-specific emissions factor according to 

§98.223(a)(1), each annual report must also contain the 

information specified in paragraphs (m)(1) through (m)(7) 

of this section. 

* * * * * 

(n) If you requested Administrator approval for an 

alternative method of determining N2O emissions under 

§98.223(a)(2), each annual report must also contain the 

information specified in paragraphs (n)(1) through (n)(4) 

of this section. 

* * * * * 

(p) Fraction control factor for each abatement 

technology (percent of total emissions from the production 

unit that are sent to the abatement technology) if equation 

V-3c is used. 

* * * * * 

Subpart Z—[Amended] 

41. Section 98.263 is amended by revising paragraph 

(b)(1) to read as follows: 
Page 190 of 246 

§98.263 Calculating GHG emissions.

* * * * * 

(b) * * * 

(1) Calculate the annual CO2 mass emissions from each 

wet-process phosphoric acid process line using the methods 

in paragraphs (b)(1)(i) or (b)(1)(ii) of this section, as 

applicable. 

(i) If your process measurement provides the 

inorganic carbon content of phosphate rock as an output, 

calculate and report the process CO2 emissions from each 

wet-process phosphoric acid process line using Equation Z1a of this section: 

12

44

2205

2000

1 1

∑ ∑ ( , * , ) * *

= =

=

b

i

z

n

Em ICn i Pn i (Eq. Z-1a) 

Where: 

Em = Annual CO2 mass emissions from a wet-process 

phosphoric acid process line m according to 

this Equation Z-1a (metric tons). 

ICn,i = Inorganic carbon content of a grab sample 

batch of phosphate rock by origin i obtained 

during month n, from the carbon analysis 

results (percent by weight, expressed as a 

decimal fraction). 

Pn,i = Mass of phosphate rock by origin i consumed in 

month n by wet-process phosphoric acid process 

line m (tons). 

z = Number of months during which the process line 

m operates. 
Page 191 of 246 

b = Number of different types of phosphate rock in 

month, by origin. If the grab sample is a 

composite sample of rock from more than one 

origin, b=1. 

2000/2205 = Conversion factor to convert tons to metric 

tons. 

44/12 = Ratio of molecular weights, CO2 to carbon. 

(ii) If your process measurement provides the CO2

emissions directly as an output, calculate and report the 

process CO2 emissions from each wet-process phosphoric acid 

process line using Equation Z-1b of this section: 

2205

2000

1 1

( 2 * , ) * ∑ ∑ ,

= =

=

b

i

z

n

Em CO n iPn i (Eq. Z-1b) 

Where: 

Em = Annual CO2 mass emissions from a wet-process 

phosphoric acid process line m according to 

this Equation Z-1b (metric tons). 

CO2n,i = Carbon dioxide emissions of a grab sample 

batch of phosphate rock by origin i obtained 

during month n (percent by weight, expressed 

as a decimal fraction). 

Pn,i = Mass of phosphate rock by origin i consumed in 

month n by wet-process phosphoric acid process 

line m (tons). 

z = Number of months during which the process line 

m operates. 

b = Number of different types of phosphate rock in 

month, by origin. If the grab sample is a 

composite sample of rock from more than one 

origin, b=1. 

2000/2205 = Conversion factor to convert tons to metric 

tons. 
Page 192 of 246 

42. Section 98.264 is amended by revising paragraphs 

(a) and (b) to read as follows: 

§98.264 Monitoring and QA/QC requirements.

(a) You must obtain a monthly grab sample of 

phosphate rock directly from the rock being fed to the 

process line before it enters the mill using one of the 

following methods. You may conduct the representative bulk 

sampling using a method published by a consensus standards 

organization, or you may use industry consensus standard 

practice methods, including but not limited to the 

Phosphate Mining States Methods Used and Adopted by the 

Association of Fertilizer and Phosphate Chemists (AFPC). 

If phosphate rock is obtained from more than one origin in 

a month, you must obtain a sample from each origin of rock 

or obtain a composite representative sample. 

(b) You must determine the carbon dioxide or 

inorganic carbon content of each monthly grab sample of 

phosphate rock (consumed in the production of phosphoric 

acid). You may use a method published by a consensus 

standards organization, or you may use industry consensus 

standard practice methods, including but not limited to the 

Phosphate Mining States Methods Used and Adopted by AFPC. 

* * * * * 
Page 193 of 246 

43. Section 98.265 is amended by revising the first 

and second sentences of paragraph (a) to read as follows: 

§98.265 Procedures for estimating missing data.

* * * * * 

(a) For each missing value of the inorganic carbon 

content of phosphate rock or carbon dioxide (by origin), 

you must use the appropriate default factor provided in 

Table Z-1 this subpart. Alternatively, you must determine 

a substitute data value by calculating the arithmetic 

average of the quality-assured values of inorganic carbon 

contents of phosphate rock of origin i from samples 

immediately preceding and immediately following the missing 

data incident. * * * 

* * * * * 

44. Section 98.266 is amended by: 

a. Revising the introductory text. 

b. Revising paragraph (c). 

c. Revising paragraph (f) introductory text. 

d. Revising paragraph (f)(2). 

e. Revising paragraph (f)(4). 

f. Revising paragraph (f)(5). 

g. Adding paragraph (f)(9). 

§98.266 Data reporting requirements. 
Page 194 of 246 

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

each annual report must contain the information specified 

in paragraphs (a) through (f) of this section. 

* * * * * 

(c) Annual arithmetic average percent inorganic 

carbon or carbon dioxide in phosphate rock from monthly 

records (percent by weight, expressed as a decimal 

fraction). 

* * * * * 

(f) If you do not use a CEMS to measure emissions, 

then you must report the information in paragraphs (f)(1) 

through (f)(9) of this section. 

* * * * * 

(2) Annual CO2 emissions from each wet-process 

phosphoric acid process line (metric tons) as calculated by 

either Equation Z-1a or Equation Z-1b of this subpart. 

* * * * * 

(4) Method used to estimate any missing values of 

inorganic carbon content or carbon dioxide content of 

phosphate rock for each wet-process phosphoric acid process 

line. 

(5) Monthly inorganic carbon content of phosphate 

rock for each wet-process phosphoric acid process line for 

which Equation Z-1a is used (percent by weight, expressed 
Page 195 of 246 

as a decimal fraction), or CO2 (percent by weight, 

expressed as a decimal fraction) for which Equation Z-1b is 

used. 

* * * * * 

(9) Annual process CO2 emissions from phosphoric acid 

production facility (metric tons). 

Subpart CC—[Amended] 

45. Section 98.294 is amended by revising the third 

sentence of paragraph (a)(1) to read as follows: 

§98.294 Monitoring and QA/QC requirements.

* * * * * 

(a) * * * 

(1) * * * The modified method referred to above 

adjusts the regular ASTM method to express the results in 

terms of trona.* * * 

* * * * * 

46. Section 98.296 is amended by: 

a. Revising paragraph (a)(1). 

b. Revising paragraph (b)(3). 

c. Revising paragraph (b)(6). 

d. Revising paragraph (b)(10). 

e. Removing paragraph (b)(11)(iv). 

f. Removing paragraph (b)(11)(v). 

g. Removing paragraph (b)(11)(vi). 
Page 196 of 246 

§98.296 Data reporting requirements. 

* * * * * 

(a) * * * 

(1) Annual consumption of trona or liquid alkaline 

feedstock for each manufacturing line (tons). 

* * * * * 

(b) * * * 

(3) Annual production of soda ash for each 

manufacturing line (tons). 

* * * * * 

(6) Monthly production of soda ash for each 

manufacturing line (tons). 

* * * * * 

(10) If you produce soda ash using the liquid 

alkaline feedstock process and use the site-specific 

emission factor method (§98.293(b)(3)) to estimate 

emissions then you must report the following relevant 

information for each manufacturing line or stack: 

(i) Stack gas volumetric flow rate during performance 

test (dscfm). 

(ii) Hourly CO2 concentration during performance test 

(percent CO2). 

(iii) CO2 emission factor (metric tons CO2/metric tons 

of process vent flow from mine water stripper/evaporator). 
Page 197 of 246 

(iv) CO2 mass emission rate during performance test 

(metric tons/hour). 

* * * * * 

Subpart EE—[Amended] 

47. Section 98.314 is amended by revising paragraph 

(e) to read as follows: 

§98.314 Monitoring and QA/QC requirements. 

* * * * * 

(e) You must determine the quantity of carboncontaining waste generated from each titanium dioxide 

production line on a monthly basis using plant instruments 

used for accounting purposes including direct measurement 

weighing the carbon-containing waste not used during the 

process (by belt scales or a similar device) or through the 

use of sales records. 

* * * * * 

48. Section 98.316 is amended by revising paragraphs 

(b)(9) and (b)(11) to read as follows: 

§98.316 Data reporting requirements.

* * * * * 

(b) * * * 

(9) Monthly carbon content factor of petroleum coke 

(percent by weight expressed as a decimal fraction). 

* * * * * 
Page 198 of 246 

(11) Carbon content for carbon-containing waste for 

each process line (percent by weight expressed as a decimal 

fraction). 

* * * * * 

Subpart GG—[Amended] 

49. Section 98.333 is amended by revising the 

definitions of “(Electrode)k” and “(CElectrode)k” in Equation 

GG-1 of paragraph (b)(1) to read as follows: 

§98.333 Calculating GHG emissions.

* * * * * 

(b) * * * 

(1) * * * * * 

(Electrode)k = Annual mass of carbon electrode consumed 

in furnace “k” (tons). 

(CElectrode)k = Carbon content of the carbon electrode 

consumed in furnace “k”, from the annual 

carbon analysis (percent by weight, 

expressed as a decimal fraction). 

* * * * * 

50. Section 98.336 is amended by revising paragraph 

(a) introductory text; and by revising paragraphs (b)(1), 

(b)(7), and (b)(10) to read as follows: 

§98.336 Data reporting requirements.

* * * * * 

(a) If a CEMS is used to measure CO2 emissions, then 

you must report under this subpart the relevant information 
Page 199 of 246 

required for the Tier 4 Calculation Methodology in §98.36 

and the information listed in this paragraph (a): 

* * * * * 

(b) * * * 

(1) Identification number and annual process CO2

emissions from each individual Waelz kiln or electrothermic 

furnace (metric tons). 

* * * * * 

(7) Carbon content of each carbon-containing input 

material charged to each kiln or furnace (including zinc 

bearing material, flux materials, and other carbonaceous 

materials) from the annual carbon analysis or from 

information provided by the material supplier for each kiln 

or furnace (percent by weight, expressed as a decimal 

fraction). 

* * * * * 

(10) Carbon content of the carbon electrode used in 

each furnace from the annual carbon analysis or from 

information provided by the material supplier (percent by 

weight, expressed as a decimal fraction). 

* * * * * 

Subpart HH—[Amended] 

51. Section 98.340 is amended by revising paragraph 

(b) to read as follows: 
Page 200 of 246 

§98.340 Definition of the source category.

* * * * * 

(b) 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 waste landfills, or industrial 

waste landfills. 

* * * * * 

52. Section 98.343 is amended by: 

a. In paragraph (a)(1), revising Equation HH-1 and 

the definitions of “x,” “S,” “Wx,” “MCF,” “DOCF,” “F,” and 

“k” in Equation HH-1; and removing the definition of “L0” in 

Equation HH-1. 

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

c. Redesignating paragraph (a)(3) as (a)(4) and 

revising new paragraph (a)(4). 

d. Adding a new paragraph (a)(3). 

e. Revising paragraph (b)(1), and revising paragraph 

(b)(2) introductory text. 

f. Revising paragraphs (b)(2)(ii), (b)(2)(iii)(A), 

and (b)(2)(iii)(B). 

g. Revising paragraph (c) introductory text. 

§98.343 Calculating GHG emissions.

(a) * * * 
Page 201 of 246 

(1) * * * * * 

∑ ( )

−

=

− − − − −













= × × × × × × −

1

1

4

12

16 T

x S

k T x k T x

GCH Wx MCF DOC DOCF F e e

( ) ( ) (Eq. HH-1) 

* * * * * 

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. 

* * * * * 

Wx = Quantity of waste disposed in the landfill in 

year x from measurement data, tipping fee 

receipts, or other company records (metric 

tons, as received (wet weight)). 

MCF = Methane correction factor (fraction). Use the 

default value of 1 unless there is active 

aeration of waste within the landfill during 

the reporting year. If there is active 

aeration of waste within the landfill during 

the reporting year, use either the default 

value of 1 or select an alternative value no 

less than 0.5 based on site-specific aeration 

parameters. 

* * * * * 

DOCF = Fraction of DOC dissimilated (fraction). Use 

the default value of 0.5. 

F = Fraction by volume of CH4 in landfill gas from 

measurement data on a dry basis, if available 

(fraction); default is 0.5. 

k = Rate constant from Table HH-1 to this subpart 

(yr-1). Select the most applicable k value for 

the majority of the past 10 years (or 

operating life, whichever is shorter). 
Page 202 of 246 

(2) * * * For years when waste composition 

data are not available, use the bulk waste parameter values 

for k and DOC in Table HH-1 to this subpart for the total 

quantity of waste disposed in those years. 

(3) Beginning in the first emissions reporting year 

and for each year thereafter, if scales are in place, you 

must determine the annual quantity of waste (in metric tons 

as received, i.e., wet weight) disposed of in the landfill 

using paragraph (a)(3)(i) of this section for all 

containers and for all vehicles used to haul waste to the 

landfill, except for passenger cars, light duty pickup 

trucks, or waste loads that cannot be measured using the 

scales due to physical limitations (load cannot physically 

access or fit on the scale) and/or operational limitations 

of the scale (load exceeding the limits or sensitivity 

range of the scale). If scales are not in place, you must 

use paragraph (a)(3)(ii) of this section to determine the 

annual quantity of waste disposed. For waste hauled to the 

landfill in passenger cars or light duty pickup trucks, you 

may use either paragraph (a)(3)(i) or paragraph (a)(3)(ii) 

of this section to determine the annual quantity of waste 

disposed. For loads that cannot be measured using the 

scales due to physical and/or operational limitations of 

the scale, you must use paragraph (a)(3)(ii) of this 
Page 203 of 246 

section or similar engineering calculations to determine 

the annual quantity of waste disposed. The approach used 

to determine the annual quantity of waste disposed of must 

be documented in the monitoring plan. 

(i) Use direct mass measurements of each individual 

load received at the landfill using either of the following 

methods: 

(A) Weigh using mass scales each vehicle or container 

used to haul waste as it enters the landfill or disposal 

area; weigh using mass scales each vehicle or container 

after it has off-loaded the waste; determine the quantity 

of waste received from the individual load as the 

difference in the two mass measurements; and determine the 

annual quantity of waste received as the sum of all waste 

loads received during the year. Alternatively, you may 

determine annual quantity of waste by summing the weights 

of all vehicles and containers entering the landfill and 

subtracting from it the sum of all the weights of vehicles 

and containers after they have off-loaded the waste in the 

landfill. 

(B) Weigh using mass scales each vehicle or container 

used to haul waste as it enters the landfill or disposal 

area; determine a representative tare weight by vehicle or 

container type by weighing no less than 5 of each type of 
Page 204 of 246 

vehicle or container after it has off-loaded the waste; 

determine the quantity of waste received from the 

individual load as the difference between the measured 

weight in and the tare weight determined for that 

container/vehicle type; and determine the annual quantity 

of waste received as the sum of all waste loads received 

during the year. 

(ii) Determine the working capacity in units of mass 

for each type of container or vehicle used to haul waste to 

the landfill (e.g., using volumetric capacity and waste 

density measurements; direct measurement of a selected 

number of passenger vehicles and light duty pick-up trucks; 

or similar methods); record the number of loads received at 

the landfill by vehicle/container type; calculate the 

annual mass per vehicle/container type as the mass product 

of the number of loads of that vehicle/container multiplied 

by its working capacity; and calculate the annual quantity 

of waste received as the sum of the annual mass per 

vehicle/container type across all of the vehicle/container 

types used to haul waste to the landfill. 

(4) For years prior to the first emissions reporting 

year, use methods in paragraph (a)(3) of this section when 

waste disposal quantity data are readily available. When 

waste disposal quantity data are not readily available, Wx
Page 205 of 246 

shall be estimated using one of the applicable methods in 

paragraphs (a)(4)(i) through (a)(4)(iii) of this section. 

You must determine which method is most applicable to the 

conditions and disposal history of your facility. 

Historical waste disposal quantities should only be 

determined once, as part of the first annual report, and 

the same values should be used for all subsequent annual 

reports, supplemented by the next year’s data on new waste 

disposal. 

(i) Assume all prior years waste disposal quantities 

are the same as the waste quantity in the first year for 

which waste quantities are available. 

(ii) Use the estimated population served by the 

landfill in each year, the values for national average per 

capita waste disposal rates found in Table HH-2 to this 

subpart, and calculate the waste quantity landfilled using 

Equation HH-2 of this section. 

Wx = POPx × WDRx (Eq. HH-2) 

Where: 

Wx = Quantity of waste placed in the landfill in 

year x (metric tons, wet basis). 

POPx = Population served by the landfill in year x 

from city population, census data, or other 

estimates (capita). 

WDRx = Average per capita waste disposal rate for 

year x from Table HH-2 to this subpart (metric 
Page 206 of 246 

tons per capita per year, wet basis; 

tons/cap/yr). 

(iii) Use a constant average waste disposal quantity 

calculated using Equation HH-3 of this section for each 

year the landfill was in operation (i.e., from the first 

year accepting waste until the last year for which waste 

disposal data is unavailable, inclusive). 

( − + 1)

=

YrData YrOpen

LFC

Wx (Eq. HH-3) 

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 

year prior to the year when waste disposal 

data are available 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 first reporting year when waste disposal 

data is first available from company records, 

or best available data. 

YrOpen = Year in which the landfill first received 

waste from company records or best available 

data. If no data are available for estimating 

YrOpen for a closed landfill, use 30 years as 

the default operating life of the landfill. 

(b) * * * 

(1) If you continuously monitor the flow rate, CH4

concentration, temperature, pressure, and, if necessary, 

moisture content of the landfill gas that is collected and 
Page 207 of 246 

routed to a destruction device (before any treatment 

equipment) using a monitoring meter specifically for CH4

gas, as specified in §98.344, you must use this monitoring 

system and calculate the quantity of CH4 recovered for 

destruction using Equation HH-4 of this section. A fully 

integrated system that directly reports CH4 content requires 

no other calculation than summing the results of all 

monitoring periods for a given year. 

( ) ( )

( )

( )

( )

1,000

0.454

1 atm

P

T

520 R

0.0423

100%

C

R V

N

n 1

n

n

n ∑ n

=

















× ×

°

= × × × × MC nK (Eq. HH-4) 

Where: 

R = Annual quantity of recovered CH4 (metric 

tons CH4). 

N = Total number of measurement periods in a 

year. Use daily averaging periods for a 

continuous monitoring system and N=365 (or 

N=366 for leap years). For weekly 

sampling, as provided in paragraph (b)(2) 

of this section, use N=52. 

n = Index for measurement period. 

(V)n = Cumulative volumetric flow for the 

measurement period in actual cubic feet 

(acf). If the flow rate meter 

automatically corrects for temperature and 

pressure, replace “520°R/(T)n × (P)n/1 atm” 

with “1”. 

(KMC)n = Moisture correction term for the 

measurement period, volumetric basis, as 

follows: (KMC)n= 1 when (V)n and (C)n are 

both measured on a dry basis or if both are 

measured on a wet basis; (KMC)n = [1-(fH2O)n] 

when (V)n is measured on a wet basis and 
Page 208 of 246 

(C)n is measured on a dry basis; and (KMC)n = 

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

basis and (C)n is measured on a wet basis. 

(fH2O)n = Average moisture content of landfill gas 

during the measurement period, volumetric 

basis (cubic feet water per cubic feet 

landfill gas) 

(CCH4)n = Average CH4 concentration of landfill gas 

for the measurement period (volume %). 

0.0423 = Density of CH4 lb/cfm at 520°R or 60 degrees 

Fahrenheit and 1 atm. 

(T)n = Average temperature at which flow is 

measured for the measurement period (°R). 

(P)n = Average pressure at which flow is measured 

for the measurement period (atm). 

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

(2) If you do not continuously monitor according to 

paragraph (b)(1) of this section, you must determine the 

flow rate, CH4 concentration, temperature, pressure, and 

moisture content of the landfill gas that is collected and 

routed to a destruction device (before any treatment 

equipment) according to the requirements in paragraphs 

(b)(2)(i) through (b)(2)(iii) of this section and calculate 

the quantity of CH4 recovered for destruction using Equation 

HH-4 of this section. 

* * * * * 

(ii) Determine the CH4 concentration in the landfill 

gas that is collected and routed to a destruction device 

(before any treatment equipment) in a location near or 
Page 209 of 246 

representative of the location of the gas flow meter at 

least once each calendar week; if only one measurement is 

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

between measurements. 

(iii) * * * 

(A) Determine the temperature and pressure in the 

landfill gas that is collected and routed to a destruction 

device (before any treatment equipment) in a location near 

or representative of the location of the gas flow meter at 

least once each calendar week; if only one measurement is 

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

between measurements. 

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

basis and flow is determined on a wet basis or CH4

concentration is determined on a wet basis and flow is 

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

automatically correct for moisture content, determine the 

moisture content in the landfill gas that is collected and 

routed to a destruction device (before any treatment 

equipment) in a location near or representative of the 

location of the gas flow meter at least once each calendar 

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

there must be at least three days between measurements. 
Page 210 of 246 

(c) For all landfills, calculate CH4 generation 

(adjusted for oxidation in cover materials) and actual CH4

emissions (taking into account any CH4 recovery, and 

oxidation in cover materials) according to the applicable 

methods in paragraphs (c)(1) through (c)(3) of this 

section. 

* * * * * 

53. Section 98.344 is amended by: 

a. Revising paragraph (a). 

b. Revising the first sentence of paragraph (b) 

introductory text. 

c. Revising paragraphs (b)(6)(ii) introductory text, 

(b)(6)(ii)(A), and (b)(6)(ii)(B). 

d. Revising the definition of “CCH4” in Equation HH-9 

of paragraph (b)(6)(iii). 

e. Revising the second and third sentences of 

paragraph (c) introductory text. 

f. Revising paragraph (d). 

g. Revising the first sentence of paragraph (e). 

§98.344 Monitoring and QA/QC requirements. 

(a) Mass measurement equipment used to determine the 

quantity of waste landfilled on or after January 1, 2010 

must meet the requirements for weighing equipment as 

described in “Specifications, Tolerances, and Other 
Page 211 of 246 

Technical Requirements For Weighing and Measuring Devices” 

NIST Handbook 44 (2009)(incorporated by reference, see 

§98.7). 

(b) For landfills with gas collection systems, 

operate, maintain, and calibrate a gas composition monitor 

capable of measuring the concentration of CH4 in the 

recovered landfill gas using one of the methods specified 

in paragraphs (b)(1) through (b)(6) of this section or as 

specified by the manufacturer.* * * 

* * * * * 

(6) * * * 

(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 (b)(6)(ii)(A) through 

(b)(6)(ii)(C) of this section. 

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

landfill gas with a minimum of 20 minutes between samples 

and determine the methane composition of the landfill gas 

using one of the methods specified in paragraphs (b)(1) 

through (b)(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 
Page 212 of 246 

of the landfill gas using either Method 25A or 25B at 40 

CFR part 60, appendix A-7 as specified in paragraph 

(b)(6)(i) of this section. 

* * * * * 

(iii) * * * * * 

CCH4 = Methane concentration in the landfill gas 

(volume %) for use in Equation HH-4 of this 

subpart. 

* * * * * 

(c) * * * Each gas flow meter shall be 

recalibrated either biennially (every 2 years) or at the 

minimum frequency specified by the manufacturer. Except as 

provided in §98.343(b)(2)(i), each gas flow meter must be 

capable of correcting for the temperature and pressure and, 

if necessary, moisture content. 

* * * * * 

(d) All temperature, pressure, and if necessary, 

moisture content monitors must be calibrated using the 

procedures and frequencies specified by the manufacturer. 

(e) The owner or operator shall document the 

procedures used to ensure the accuracy of the estimates of 

disposal quantities and, if applicable, gas flow rate, gas 

composition, temperature, pressure, and moisture content 

measurements. * * * 

54. Section 98.346 is amended by: 
Page 213 of 246 

a. Revising paragraph (a). 

b. Revising paragraph (b). 

c. Revising paragraph (c). 

d. Revising paragraph (d)(1). 

e. Revising paragraph (f). 

f. Revising paragraph (h). 

g. Revising paragraph (i)(1) 

h. Revising paragraph (i)(2) 

i. Revising paragraph (i)(3) 

j. Revising paragraph (i)(4) 

k. Revising paragraph (i)(5) 

l. Revising paragraph (i)(7). 

§98.346 Data reporting requirements. 

* * * * * 

(a) A classification of the landfill as “open” 

(actively received waste in the reporting year) or “closed” 

(no longer receiving waste), the year in which the landfill 

first started accepting waste for disposal, the last year 

the landfill accepted waste (for open landfills, enter the 

estimated year of landfill closure), the capacity (in 

metric tons) of the landfill, 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, 
Page 214 of 246 

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

occasionally but not every year over the past 10 years, not 

used), an indication as to whether scales are present at 

the landfill, and the waste disposal quantity for each year 

of landfilling required to be included when using Equation 

HH-1 of this subpart (in metric tons, wet weight). 

(b) Method for estimating reporting year and 

historical waste disposal quantities, reason for its 

selection, and the range of years it is applied. For years 

when waste quantity data are determined using the methods 

in §98.343(a)(3), report separately the quantity of waste 

determined using the methods in §98.343(a)(3)(i) and the 

quantity of waste determined using the methods in 

§98.343(a)(3)(ii). For historical waste disposal 

quantities that were not determined using the methods in 

§98.343(a)(3), provide the population served by the 

landfill for each year the Equation HH-2 of this subpart is 

applied, if applicable, or, for open landfills using 

Equation HH-3 of this subpart, provide the value of 

landfill capacity (LFC) used in the calculation. 

(c) Waste composition for each year required for 

Equation HH-1 of this subpart, in percentage by weight, for 

each waste category listed in Table HH-1 to this subpart 
Page 215 of 246 

that is used in Equation HH-1 of this subpart to calculate 

the annual modeled CH4 generation. 

(d) * * * 

(1) Degradable organic carbon (DOC), methane 

correction factor (MCF), and fraction of DOC dissimilated 

(DOCF) values used in the calculations. If an MCF value 

other than the default of 1 is used, provide an indication 

of whether active aeration of the waste in the landfill was 

conducted during the reporting year, a description of the 

aeration system, including aeration blower capacity, the 

fraction of the landfill containing waste affected by the 

aeration, the total number of hours during the year the 

aeration blower was operated, and other factors used as a 

basis for the selected MCF value. 

* * * * * 

(f) The surface area of the landfill containing waste 

(in square meters), identification of the type of cover 

material used (as either organic cover, clay cover, sand 

cover, or other soil mixtures). If multiple cover types 

are used, the surface area associated with each cover type. 

* * * * * 

(h) For landfills without gas collection systems, the 

annual methane emissions (i.e., the methane generation, 

adjusted for oxidation, calculated using Equation HH-5 of 
Page 216 of 246 

this subpart), reported in metric tons CH4, and an 

indication of whether passive vents and/or passive flares 

(vents or flares that are not considered part of the gas 

collection system as defined in §98.6) are present at this 

landfill. 

(i) * * * 

(1) Total volumetric flow of landfill gas collected 

for destruction for the reporting year (cubic feet at 520°R 

or 60 degrees Fahrenheit and 1 atm). 

(2) Annual average CH4 concentration of landfill gas 

collected for destruction (percent by volume). 

(3) Monthly average temperature and pressure for each 

month at which flow is measured for landfill gas collected 

for destruction, or statement that temperature and/or 

pressure is incorporated into internal calculations run by 

the monitoring equipment. 

(4) 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 HH-4 of this subpart, monthly average 

moisture content for each month at which flow is measured 

for landfill gas collected for destruction. 

(5) An indication of whether destruction occurs at 

the landfill facility or off-site. If destruction occurs 
Page 217 of 246 

at the landfill facility, also report an indication of 

whether a back-up destruction device is present at the 

landfill, the annual operating hours for the primary 

destruction device, the annual operating hours for the 

back-up destruction device (if present), and the 

destruction efficiency used (percent). 

* * * * * 

(7) A description of the gas collection system 

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

area (square meters) and estimated waste depth (meters) for 

each area specified in Table HH-3 to this subpart, the 

estimated gas collection system efficiency for landfills 

with this gas collection system, the annual operating hours 

of the gas collection system, and an indication of whether 

passive vents and/or passive flares (vents or flares that 

are not considered part of the gas collection system as 

defined in §98.6) are present at the landfill. 

* * * * * 

55. Section 98.347 is amended by adding a second 

sentence to the introductory text to read as follows: 

§98.347 Records that must be retained. 

* * * You must retain records of all 

measurements made to determine tare weights and working 
Page 218 of 246 

capacities by vehicle/container type if these are used to 

determine the annual waste quantities. 

56. Section 98.348 is revised to read as follows: 

§98.348 Definitions.

Except as specified in this section, all terms used in 

this subpart have the same meaning given in the Clean Air 

Act and subpart A of this part. 

Construction and demolition (C&D) waste landfill means 

a solid waste disposal facility subject to the requirements 

of part 257, subparts A or B of this chapter that receives 

construction and demolition waste and does not receive 

hazardous waste (defined in §261.3 of this chapter) or 

industrial solid waste (defined in §258.2 of this chapter) 

or municipal solid waste (as defined in §98.6) other than 

residential lead-based paint waste. A C&D waste landfill 

typically receives any one or more of the following types 

of solid wastes: roadwork material, excavated material, 

demolition waste, construction/renovation waste, and site 

clearance waste. 

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. 
Page 219 of 246 

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 a RCRA 

Subtitle D wastes (nonhazardous industrial solid waste, 

defined in §257.2 of this chapter), commercial solid 

wastes, or conditionally exempt small quantity generator 

wastes, is placed. An industrial waste landfill includes 

all disposal areas at the facility. 

Solid waste has the meaning established by the 

Administrator pursuant to the Solid Waste Disposal Act (42 

U.S.C.A. 6901 et seq.) 

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 account that the container may not be 

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

for each load. 

57. Table HH-1 to subpart HH is revised to read as 

follows: 

Table HH-1 to Subpart HH—Emissions Factors, Oxidation 

Factors and Methods 

 Factor Default value Units 

DOC and k values—Bulk waste option 
Page 220 of 246 

 Factor Default value Units 

DOC (bulk waste) 0.20 Weight fraction, wet 

basis 

k (precipitation plus 

recirculated leachatea

<20 inches/year) 

0.02 yr-1

k (precipitation plus 

recirculated leachatea

20-40 inches/year) 

0.038 yr-1

k (precipitation plus 

recirculated leachatea

>40 inches/year) 

0.057 yr-1

DOC and k values—Modified bulk MSW option 

DOC (bulk MSW, 

excluding inerts and 

C&D waste) 

0.31 Weight fraction, wet 

basis 

DOC (inerts, e.g., 

glass, plastics, metal, 

concrete) 

0.00 Weight fraction, wet 

basis 

DOC (C&D waste) 0.08 Weight fraction, wet 

basis 

k (bulk MSW, excluding 

inerts and C&D waste) 

0.02 to 

0.057b

yr-1

k (inerts, e.g., glass, 

plastics, metal, 

concrete) 

0.00 yr-1

k (C&D waste) 0.02 to 0.04b yr-1

DOC and k values—Waste composition option 

DOC (food waste) 0.15 Weight fraction, wet 

basis 

DOC (garden) 0.2 Weight fraction, wet 

basis 

DOC (paper) 0.4 Weight fraction, wet 

basis 

DOC (wood and straw) 0.43 Weight fraction, wet 

basis 

DOC (textiles) 0.24 Weight fraction, wet 

basis 

DOC (diapers) 0.24 Weight fraction, wet 

basis 

DOC (sewage sludge) 0.05 Weight fraction, wet 

basis 

DOC (inerts, e.g., 

glass, plastics, metal, 

cement) 

0.00 Weight fraction, wet 

basis 

k (food waste) 0.06 to 

0.185c

yr-1
Page 221 of 246 

 Factor Default value Units 

k (garden) 0.05 to 0.10c yr-1

k (paper) 0.04 to 0.06c yr-1

k (wood and straw) 0.02 to 0.03c yr-1

k (textiles) 0.04 to 0.06c yr-1

k (diapers) 0.05 to 0.10c yr-1

k (sewage sludge) 0.06 to 

0.185c

yr-1

k (inerts e.g. glass, 

plastics, metal, 

concrete) 

0.00 yr-1

Other parameters—All MSW landfills

MCF 1 

DOCF 0.5 

F 0.5 

OX 0.1 

DE 0.99 

a Recirculated leachate (in inches/year) is the total volume of leachate 

recirculated from company records or engineering estimates divided by 

the area of the portion of the landfill containing waste with 

appropriate unit conversions. Alternatively, landfills that use 

leachate recirculation can elect to use the k value of 0.057 rather 

than calculating the recirculated leachate rate. 

b Use the lesser value when precipitation plus recirculated leachate is 

less than 20 inches/year. Use the greater value when precipitation 

plus recirculated leachate is greater than 40 inches/year. Use the 

average of the range of values when precipitation plus recirculated 

leachate is 20 to 40 inches/year (inclusive). Alternatively, landfills 

that use leachate recirculation can elect to use the greater value 

rather than calculating the recirculated leachate rate.

c

 Use the lesser value when the potential evapotranspiration rate 

exceeds the mean annual precipitation rate plus recirculated leachate. 

Use the greater value when the potential evapotranspiration rate does 

not exceed the mean annual precipitation rate plus recirculated 

leachate. Alternatively, landfills that use leachate recirculation can 

elect to use the greater value rather than assessing the potential 

evapotranspiration rate or recirculated leachate rate. 

58. Table HH-2 to subpart HH is amended by: 

a. Removing the third column “% to SWDS.” 

b. Removing the entries for “1950” through “1959.” 

c. Revising the entries for “1989” through “2006.” 
Page 222 of 246 

d. Adding entries for “2007” through “2009.” 

Table HH-2 to Subpart HH—U.S. Per Capita Waste Disposal 

Rates 

Year 

Waste per capita 

ton/cap/yr

* * * * * * *

1989 0.83 

1990 0.82 

1991 0.76 

1992 0.74 

1993 0.76 

1994 0.75 

1995 0.70 

1996 0.68 

1997 0.69 

1998 0.75 

1999 0.75 

2000 0.80 

2001 0.91 

2002 1.02 

2003 1.02 

2004 1.01 

2005 0.98 

2006 0.95 

2007 0.95 

2008 0.95 

2009 0.95 

59. Table HH-3 to subpart HH-3 is amended by revising 

the entries for “A2: Area without active gas collection, 

regardless of cover type H2: Average depth of waste in 

area A2,” “A3: Area with daily soil cover and active gas 

collection H3: Average depth of waste in area A3,” “A4: 

Area with an intermediate soil cover and active gas 

collection H4: Average depth of waste in area A4,” and 

“A5: Area with a final soil and geomembrane cover system 
Page 223 of 246 

and active gas collection H5: Average depth of waste in 

area A5” to read as follows: 

Table HH-3 to Subpart HH—Landfill Gas Collection 

Efficiencies 

Description Landfill Gas Collection 

Efficiency 

* * * * * * *

A2: Area without active gas collection, 

regardless of cover type 

CE2: 0%. 

A3: Area with daily soil cover and 

active gas collection 

CE3: 60%. 

A4: Area with an intermediate soil 

cover, or a final soil cover not meeting 

the criteria for A5 below, and active 

gas collection 

CE4: 75%. 

A5: Area with a final soil cover of 3 

feet or thicker of clay and/or 

geomembrane cover system and active gas 

collection 

CE5: 95%. 

* * * * * * *

Subpart LL—[Amended] 

60. Section 98.386 is amended by: 

a. Revising paragraph (a)(3). 

b. Adding a third sentence to the end of paragraph 

(a)(5). 

c. Adding a third sentence to the end of paragraph 

(a)(6). 

d. Revising paragraph (a)(7). 

e. Revising paragraphs (a)(16) and (a)(17). 

f. Revising paragraphs (b)(3) and (c)(3). 

g. Adding paragraph (d). 
Page 224 of 246 

§98.386 Data reporting requirements. 

* * * * * 

(a) * * * 

(3) For each feedstock reported in paragraph (a)(2) 

of this section that was produced by blending a fossil 

fuel-based product with a biomass-based product, report the 

percent of the volume reported in paragraph (a)(2) of this 

section that is fossil fuel-based (excluding any denaturant 

that may be present in any ethanol product). 

* * * * * 

(5) * * * Those products that enter the 

facility, but are not reported in (a)(1), shall not be 

reported under this paragraph. 

(6) * * * Those products that enter the 

facility, but are not reported in (a)(2), shall not be 

reported under this paragraph. 

(7) For each product reported in paragraph (a)(6) of 

this section that was produced by blending a fossil fuelbased product with a biomass-based product, report the 

percent of the volume reported in paragraph (a)(6) of this 

section that is fossil fuel-based (excluding any denaturant 

that may be present in any ethanol product). 

* * * * * 
Page 225 of 246 

(16) The CO2 emissions in metric tons that would 

result from the complete combustion or oxidation of each 

feedstock reported in paragraph (a)(2) of this section that 

were calculated according to §98.393(b) or (h). 

(17) The CO2 emissions in metric tons that would 

result from the complete combustion or oxidation of each 

product (leaving the coal-to-liquid facility) reported in 

paragraph (a)(6) of this section that were calculated 

according to §98.393(a) or (h). 

* * * * * 

(b) * * * 

(3) For each product reported in paragraph (b)(2) of 

this section that was produced by blending a fossil fuelbased product with a biomass-based product, report the 

percent of the volume reported in paragraph (b)(2) of this 

section that is fossil fuel-based (excluding any denaturant 

that may be present in any ethanol product). 

* * * * * 

(c) * * * 

(3) For each product reported in paragraph (c)(2) of 

this section that was produced by blending a fossil fuelbased product with a biomass-based product, report the 

percent of the volume reported in paragraph (c)(2) of this 
Page 226 of 246 

section that is fossil fuel-based (excluding any denaturant 

that may be present in any ethanol product). 

* * * * * 

(d) Blended feedstock and products. 

(1) Producers, exporters, and importers must report 

the following information for each blended product and 

feedstock where emissions were calculated according to 

§98.393(i): 

(i) Volume or mass of each blending component. 

(ii) The CO2 emissions in metric tons that would 

result from the complete combustion or oxidation of each 

blended feedstock or product, using Equation MM-12 or 

Equation MM-13 of §98.393. 

(iii) Whether it is a blended feedstock or a blended 

product. 

(2) For a product that enters the facility to be 

further refined or otherwise used on site that is a blended 

feedstock, producers must meet the reporting requirements 

of paragraphs (a)(1) and (a)(2) of this section by 

reflecting the individual components of the blended 

feedstock. 

(3) For a product that is produced, imported, or 

exported that is a blended product, producers, importers, 

and exporters must meet the reporting requirements of 
Page 227 of 246 

paragraphs (a)(5), (a)(6), (b)(1), (b)(2), (c)(1), and 

(c)(2) of this section, as applicable, by reflecting the 

individual components of the blended product. 

Subpart MM—[Amended] 

61. Section 98.393 is amended by: 

a. In paragraph (a)(1), revising the only sentence 

and the definition of "Producti" in Equation MM-1. 

b. Revising the definition of "Producti" in Equation 

MM-2 of paragraph (a)(2). 

c. Revising the only sentence of paragraph (b)(1) and 

the first sentence in paragraph (f)(1). 

d. Revising the definition of “%Voli” in Equation MM-8 

in paragraph (h)(1). 

e. Revising Equation MM-9 and the definition of 

“%Volj” in paragraph (h)(2). 

f. Revising paragraphs (h)(3) and (h)(4). 

g. Adding paragraph (i). 

§98.393 Calculating GHG emissions.

(a) * * * 

(1) Except as provided in paragraphs (h) and (i) of 

this section, any refiner, importer, or exporter shall 

calculate CO2 emissions from each individual petroleum 

product and natural gas liquid using Equation MM-1 of this 

section. 
Page 228 of 246 

* * * * * 

Producti = Annual volume of product “i” produced, 

imported, or exported by the reporting party 

(barrels). For refiners, this volume only 

includes products ex refinery gate, and 

excludes products that entered the refinery but 

are not reported under §98.396(a)(1). For 

natural gas liquids, volumes shall reflect the 

individual components of the product as listed 

in Table MM-1 to subpart MM. 

* * * * * 

(2) * * * * * 

Producti = Annual mass of product “i” produced, imported, 

or exported by the reporting party (metric 

tons). For refiners, this mass only includes 

products ex refinery gate, and excludes 

products that entered the refinery but are not 

reported under §98.396(a)(1). 

* * * * * 

(b) * * * 

(1) Except as provided in paragraphs (h) and (i) of 

this section, any refiner shall calculate CO2 emissions from 

each non-crude feedstock using Equation MM-2 of this 

section. 

* * * * * 

(f) * * * 

(1) Calculation Method 1. To determine the emission 

factor (i.e., EFi in Equation MM-1) for solid products, 

multiply the default carbon share factor (i.e., percent 
Page 229 of 246 

carbon by mass) in column B of Table MM–1 to this subpart 

for the appropriate product by 44/12. * * * 

* * * * * 

(h) * * * 

(1) * * * 

%Voli = Percent volume of product “i” that is 

petroleum-based, not including any denaturant 

that may be present in any ethanol product, 

expressed as a fraction (e.g., 75% would be 

expressed as 0.75 in the above equation). 

(2) * * * * * 

CO2j = Feedstockj * EFj * %Volj (Eq. MM-9) 

* * * * * 

%Volj = Percent volume of feedstock “j” that is 

petroleum-based, not including any denaturant 

that may be present in any ethanol product, 

expressed as a fraction (e.g., 75% would be 

expressed as 0.75 in the above equation). 

(3) Calculation Method 2 procedures for products. 

(i) A reporter using Calculation Method 2 of this 

subpart to determine the emission factor of a petroleum 

product that does not contain denatured ethanol must 

calculate the CO2 emissions associated with that product 

using Equation MM-10 of this section in place of Equation 

MM-1 of this section. 

CO2i = (Producti * EFi )-(Producti * EFm * %Volm) (Eq. MM-10) 

Where: 
Page 230 of 246 

CO2i = Annual CO2 emissions that would result from the 

complete combustion or oxidation of each 

product “i” (metric tons). 

Producti = Annual volume of each petroleum product “i” 

produced, imported, or exported by the 

reporting party (barrels). For refiners, this 

volume only includes products ex refinery gate. 

EFi = Product-specific CO2 emission factor (metric 

tons CO2 per barrel). 

EFm = Default CO2 emission factor from Table MM-2 to 

subpart MM that most closely represents the 

component of product “i” that is biomass-based. 

%Volm = Percent volume of petroleum product “i” that is 

biomass-based, expressed as a fraction (e.g., 

75% would be expressed as 0.75 in the above 

equation). 

(ii) In the event that a petroleum product contains 

denatured ethanol, importers and exporters must follow 

Calculation Method 1 procedures in paragraph (h)(1) of this 

section; and refineries must sample the petroleum portion 

of the blended biomass-based fuel prior to blending and 

calculate CO2 emissions using Equation MM-10a of this 

section. 

CO2i = Productp * EFi (Eq. MM-10a) 

Where: 

CO2i = Annual CO2 emissions that would result from the 

complete combustion or oxidation of each 

biomass-blended fuel “i” (metric tons). 

Productp = Annual volume of the petroleum-based portion of 

each biomass blended fuel “i” produced by the 

refiner (barrels). 

EFi = Petroleum product-specific CO2 emission factor 

(metric tons CO2 per barrel). 
Page 231 of 246 

(4) Calculation Method 2 procedures for non-crude 

feedstocks. 

(i) A refiner using Calculation Method 2 of this 

subpart to determine the emission factor of a non-crude 

petroleum feedstock that does not contain denatured ethanol 

must calculate the CO2 emissions associated with that 

feedstock using Equation MM-11 of this section in place of 

Equation MM-2 of this section. 

CO2j = (Feedstockj * EFj)-(Feedstockj * EFm * %Volm)(Eq. MM-11) 

Where: 

CO2j = Annual CO2 emissions that would result from 

the complete combustion or oxidation of each 

non-crude feedstock “j” (metric tons). 

Feedstockj = Annual volume of each petroleum product “j” 

that enters the refinery to be further 

refined or otherwise used on site (barrels). 

EFj = Feedstock-specific CO2 emission factor 

(metric tons CO2 per barrel). 

EFm = Default CO2 emission factor from Table MM-2 

to subpart MM that most closely represents 

the component of petroleum product “j” that 

is biomass-based. 

%Volm = Percent volume of non-crude feedstock “j” 

that is biomass-based, expressed as a 

fraction (e.g., 75% would be expressed as 

0.75 in the above equation). 

(ii) In the event that a non-crude feedstock contains 

denatured ethanol, refiners must follow Calculation Method 

1 procedures in paragraph (h)(2) of this section. 
Page 232 of 246 

(i) Optional procedures for blended products that do 

not contain biomass. 

(1) In the event that a reporter produces, imports, 

or exports a blended product that does not include biomass, 

the reporter may calculate emissions for the blended 

product according to the method in paragraph (i)(2) of this 

section. In the event that a refiner receives a blended 

non-crude feedstock that does not include biomass, the 

refiner may calculate emission for the blended non-crude 

feedstock according to the method in paragraph (i)(3) of 

this section. The procedures in this section may be used 

only if all of the following criteria are met: 

(i) The reporter knows the relative proportion of 

each component of the blend (i.e., the mass or volume 

percentage). 

(ii) Each component of blended product “i” or blended 

non-crude feedstock “j” meets the strict definition of a 

product listed in Table MM-1 to subpart MM. 

(iii) The blended product or non-crude feedstock is 

not comprised entirely of natural gas liquids. 

(iv) The reporter uses Calculation Method 1. 

(v) Solid components are blended only with other 

solid components. 
Page 233 of 246 

(2) The reporter must calculate emissions for the 

blended product using Equation MM-12 of this section in 

place of Equation MM-1 of this section. 

CO2i = ∑[Blending Componenti...n * EFi...n] (Eq. MM-12) 

Where: 

CO2i = Annual CO2 emissions that would 

result from the complete 

combustion or oxidation of a 

blended product ”i" (metric tons). 

Blending Componenti...n = Annual volume or mass of each 

blending component that is blended 

(barrels or metric tons). 

EFi...n = CO2 emission factors specific to 

each blending component (metric 

tons CO2 per barrel or per metric 

ton of product). 

n = Number of blending components 

blended into blended product ”i”. 

(3) For refineries, the reporter must calculate 

emissions for the blended non-crude feedstock using 

Equation MM-13 of this section in place of Equation MM-2 of 

this section. 

CO2i = ∑[Blending Componenti...n * EFi...n] (Eq. MM-13) 

Where: 

CO2j = Annual CO2 emissions that would 

result from the complete 

combustion or oxidation of a 

blended non-crude feedstock ”j” 

(metric tons). 
Page 234 of 246 

Blending Componenti...n = Annual volume or mass of each 

blending component that is blended 

(barrels or metric tons). 

EFi...n = CO2 emission factors specific to 

each blending component (metric 

tons CO2 per barrel or per metric 

ton of product). 

n = Number of blending components 

blended into blended non-crude 

feedstock “j”. 

(4) For refineries, if a blending component “k” used 

in paragraph (i)(2) of this section enters the refinery 

before blending as non-crude feedstock: 

(i) The emissions that would result from the complete 

combustion or oxidation of non-crude feedstock “k” must 

still be calculated separately using Equation MM-2 of this 

section and applied in Equation MM-4 of this section. 

(ii) The quantity of blending component “k” applied 

in Equation MM-12 of this section and the quantity of noncrude feedstock “k” applied in Equation MM-2 of this 

section must be determined using the same method or 

practice. 

62. Section 98.394 is amended by: 

a. Revising paragraph (a)(1). 

b. Adding paragraph (a)(3). 

c. Revising paragraph (d)(1). 

d. Revising paragraph (d)(2). 

e. Revising paragraph (d)(3). 
Page 235 of 246 

f. Revising paragraph (d)(4). 

§98.394 Monitoring and QA/QC requirements.

(a) * * * 

(1) The quantity of petroleum products, natural gas 

liquids, and biomass, as well as the quantity of crude oil 

measured on site at a refinery, shall be determined as 

follows: 

* * * * * 

(3) The quantity of crude oil not measured on site at 

a refinery shall be determined using an appropriate method 

published by a consensus-based standards organization or 

industry standard practice. 

* * * * * 

(d) * * * 

(1) A representative sample or multiple 

representative samples of each batch of crude oil shall be 

taken according to an appropriate standard method published 

by a consensus-based standards organization or industry 

standard practice. 

(2) Samples shall be handled according to an 

appropriate standard method published by a consensus-based 

standards organization or according to an industry standard 

practice. 
Page 236 of 246 

(3) API gravity shall be measured using an 

appropriate standard method published by a consensus-based 

standards organization or industry standard practice. The 

weighted average API gravity for each batch shall be 

calculated by multiplying the volume associated with each 

representative sample by the API gravity, adding these 

values for all the samples, and then dividing that total 

value by the volume of the batch. 

(4) Sulfur content shall be measured using an 

appropriate standard method published by a consensus-based 

standards organization or industry standard practice. The 

weighted average sulfur content for each batch shall be 

calculated by multiplying the volume associated with each 

representative sample by the sulfur content, adding these 

values for all the samples, and then dividing that total 

value by the volume of the batch. 

* * * * * 

63. Section 98.396 is amended by: 

a. Revising paragraph (a)(3). 

b. Amending paragraphs (a)(5) and (a)(6) by adding a 

third sentence. 

c. Revising paragraphs (a)(7), (a)(16), and (a)(17), 

(a)(20)(ii), (a)(20)(iii), and (a)(20)(iv). 
Page 237 of 246 

d. Adding paragraphs (a)(20)(v), (a)(20)(vi), 

(a)(22), and (a)(23). 

e. Revising paragraphs (b)(3) and (c)(3). 

f. Adding paragraph (d). 

§98.396 Data reporting requirements. 

* * * * * 

(a) * * * 

(3) For each feedstock reported in paragraph (a)(2) 

of this section that was produced by blending a petroleumbased product with a biomass-based product, report the 

percent of the volume reported in paragraph (a)(2) of this 

section that is petroleum-based (excluding any denaturant 

that may be present in any ethanol product). 

* * * * * 

(5) * * * Petroleum products and natural gas 

liquids that enter the refinery, but are not reported in 

(a)(1), shall not be reported under this paragraph. 

(6) * * * Petroleum products and natural gas 

liquids that enter the refinery, but are not reported in 

(a)(2), shall not be reported under this paragraph. 

(7) For each product reported in paragraph (a)(6) of 

this section that was produced by blending a petroleumbased product with a biomass-based product, report the 

percent of the volume reported in paragraph (a)(6) of this 
Page 238 of 246 

section that is petroleum-based (excluding any denaturant 

that may be present in any ethanol product). 

* * * * * 

(16) The CO2 emissions in metric tons that would 

result from the complete combustion or oxidation of each 

petroleum product and natural gas liquid (ex refinery gate) 

reported in paragraph (a)(6) of this section that were 

calculated according to §98.393(a) or (h). 

(17) The CO2 emissions in metric tons that would 

result from the complete combustion or oxidation of each 

feedstock reported in paragraph (a)(2) of this section that 

were calculated according to §98.393(b) or (h). 

* * * * * 

(20) * * * 

(ii) Weighted average API gravity representing the 

batch at the point of entry at the refinery. 

(iii) Weighted average sulfur content representing 

the batch at the point of entry at the refinery. 

(iv) Country of origin, of the batch, if known and 

data in paragraphs (a)(20)(v) and (a)(20)(vi) of this 

section are unknown. 

(v) EIA crude stream code and crude stream name of 

the batch, if known. 
Page 239 of 246 

(vi) Generic name for the crude stream and the 

appropriate EIA two-letter country or state and production 

area code of the batch, if known and no appropriate EIA 

crude stream code exists. 

* * * * * 

(22) Volume of crude oil in barrels that you injected 

into a crude oil supply or reservoir. A volume of crude 

oil that entered the refinery, but was not reported in 

paragraphs (a)(2) or (a)(20), shall not be reported under 

this paragraph. 

(23) Special provisions for 2010. For reporting year 

2010 only, a refiner that knows the information under a 

specific tier of the batch definition in 40 CFR 98.398, but 

does not have the necessary data collection and management 

in place to readily report this information, can use the 

next most appropriate tier of the batch definition for 

reporting batch information under paragraph 98.396(a)(20). 

(b) * * * 

(3) For each product reported in paragraph (b)(2) of 

this section that was produced by blending a petroleumbased product with a biomass-based product, report the 

percent of the volume reported in paragraph (b)(2) of this 

section that is petroleum-based (excluding any denaturant 

that may be present in any ethanol product). 
Page 240 of 246 

* * * * * 

(c) * * * 

(3) For each product reported in paragraph (c)(2) of 

this section that was produced by blending a petroleumbased product with a biomass-based product, report the 

percent of the volume reported in paragraph (c)(2) of this 

section that is petroleum based (excluding any denaturant 

that may be present in any ethanol product). 

* * * * * 

(d) Blended non-crude feedstock and products. 

(1) Refineries, exporters, and importers must report 

the following information for each blended product and noncrude feedstock where emissions were calculated according 

to §98.393(i): 

(i) Volume or mass of each blending component. 

(ii) The CO2 emissions in metric tons that would 

result from the complete combustion or oxidation of each 

blended non-crude feedstock or product, using Equation MM12 or Equation MM-13 of this section. 

(iii) Whether it is a blended non-crude feedstock or 

a blended product. 

(2) For a product that enters the refinery to be 

further refined or otherwise used on site that is a blended 

non-crude feedstock, refiners must meet the reporting 
Page 241 of 246 

requirements of paragraphs (a)(1) and (a)(2) of this 

section by reflecting the individual components of the 

blended non-crude feedstock. 

(3) For a product that is produced, imported, or 

exported that is a blended product, refiners, importers, 

and exporters must meet the reporting requirements of 

paragraphs (a)(5), (a)(6), (b)(1), (b)(2), (c)(1), and 

(c)(2) of this section, as applicable, by reflecting the 

individual components of the blended product. 

64. Section 98.397 is amended by: 

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

b. Removing paragraph (e). 

c. Redesignating paragraphs (f) and (g) as (e) and 

(f), respectively. 

§98.397 Records that must be retained.

* * * * * 

(b) * * * For all reported quantities of 

petroleum products, natural gas liquids, and biomass, as 

well as crude oil quantities measured on site at a 

refinery, reporters shall maintain metering, gauging, and 

other records normally maintained in the course of business 

to document product and feedstock flows including the date 

of initial calibration and the frequency of recalibration 

for the measurement equipment used. 
Page 242 of 246 

65. Section 98.398 is revised to read as follows: 

§98.398 Definitions.

Except as specified in this section, all terms used in 

this subpart have the same meaning given in the Clean Air 

Act and subpart A of this part. 

Batch means either a volume of crude oil that enters a 

refinery or the components of such volume (e.g., the 

volumes of different crude streams that are blended 

together and then delivered to a refinery). The batch 

volume is the first appropriate tier in the following list: 

(1) Up to an annual volume of a type of crude oil 

identified by an EIA crude stream code, if the EIA crude 

stream code is known. 

(2) Up to an annual volume of a type of crude oil 

identified by a generic name for the crude stream and an 

appropriate EIA two-letter country or state and production 

area code, if the generic name and EIA two-letter code are 

known but no appropriate EIA crude stream code exists. 

(3) Up to a calendar month of crude oil volume from a 

single known foreign country of origin if the crude stream 

name is unknown. 

(4) Up to a calendar month of crude oil volume from 

the United States if the crude stream name and production 

area are unknown. 
Page 243 of 246 

(5) Up to a calendar month of crude oil volume if the 

country of origin is unknown. 

Subpart NN—[Amended] 

66. Section 98.403 is amended by: 

a. Revising the definitions of "Fuelh" and “HHVh” in 

Equation NN-1 of paragraph (a)(1). 

b. Revising the definition of "Fuelh" in Equation NN-2 

of paragraph (a)(2). 

c. Revising the definition of “Fuel1” in Equation NN-5 

of paragraph (b)(3). 

d. Revising the definition of "EFg" in Equation NN-7 

of paragraph (c)(1). 

e. In paragraph (c)(2), revising Equation NN-8 and 

the definition of “CO2i” in Equation NN-8. 

§98.403 Calculating GHG emissions.

(a) * * * 

(1) * * * * * 

Fuelh = Total annual volume of product “h” supplied 

(volume per year, in thousand standard cubic 

feet (Mscf) for natural gas and bbl for NGLs). 

HHVh = Higher heating value of product “h” supplied 

(MMBtu/ Mscf or MMBtu/bbl). 

* * * * * 

(2) * * * * * 

Fuelh = Total annual volume of product “h” supplied (bbl 

or Mscf per year) 
Page 244 of 246 

* * * * * 

(b) * * * 

(3) * * * * * 

Fuel1 = Total annual volume of natural gas received by 

the LDC at the city gate and stored on-system 

or liquefied and stored in the reporting year 

(Mscf per year). 

* * * * * 

(c) * * * 

(1) * * * * * 

EFg = Fuel-specific CO2 emission factor of NGL product 

“g” (MT CO2/bbl). 

(2) * * * * * 

CO2 = CO2i − CO2m (Eq. NN-8) 

* * * * * 

CO2i = Annual CO2 mass emissions that would result from 

the combustion or oxidation of fractionated NGLs 

delivered to all customers or on behalf of 

customers as calculated in paragraph (a)(1) or 

(a)(2) of this section (metric tons). 

* * * * * 

67. Section 98.406 is amended by revising paragraphs 

(a)(6) and (a)(9) introductory text to read as follows: 

§98.406 Data reporting requirements. 

(a) * * * 

(6) Annual CO2 emissions (metric tons) that would 

result from the complete combustion or oxidation of the 
Page 245 of 246 

quantities in paragraphs (a)(1) and (a)(2) of this section, 

calculated in accordance with §98.403(a) and (c)(1). 

* * * * * 

(9) If the NGL fractionator developed reporterspecific EFs or HHVs, report the following for each product 

type: 

* * * * * 

68. Section 98.407 is amended by revising paragraphs 

(a) and (d) to read as follows: 

§98.407 Records that must be retained.

* * * * * 

(a) Records of all meter readings and documentation 

to support volumes of natural gas and NGLs that are 

reported under this part. 

* * * * * 

(d) Records related to the large end-users identified 

in §98.406(b)(7). 

* * * * * 

69. Tables NN-1 and NN-2 to Subpart NN are amended to 

read as follows: 

Table NN-1 to Subpart NN—Default Factors for Calculation 

Methodology 1 of this Subpart 

Fuel Default High Heating 

Value Factor

Default CO2 Emission 

Factor (kg CO2 /MMBtu) 

Natural Gas 1.028 MMBtu/Mscf 53.02 

Propane 3.822 MMBtu/bbl 61.46 

Normal butane 4.242 MMBtu/bbl 65.15 
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Fuel Default High Heating 

Value Factor

Default CO2 Emission 

Factor (kg CO2 /MMBtu) 

Ethane 4.032 MMBtu/bbl 62.64 

Isobutane 4.074 MMBtu/bbl 64.91 

Pentanes plus 4.620 MMBtu/bbl 70.02 

Table NN-2 to Subpart NN—Lookup Default Values for 

Calculation Methodology 2 of this Subpart 

Fuel Unit 

Default CO2 Emission 

Value 

(MT CO2/Unit) 

Natural Gas Mscf 0.055 

Propane Barrel 0.235 

Normal butane Barrel 0.276 

Ethane Barrel 0.253 

Isobutane Barrel 0.266 

Pentanes plus Barrel 0.324