6560.50 

ENVIRONMENTAL PROTECTION AGENCY 

40 CFR Part 98 

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

RIN 2060-A079 

Mandatory Reporting of Greenhouse Gases 

AGENCY: Environmental Protection Agency (EPA). 

ACTION: Proposed Rulemaking: Technical Corrections, 

Clarifying and Other Amendments to Certain Provisions of 

the Mandatory Greenhouse Gas Reporting Rule. 

SUMMARY: On October 30, 2009, EPA published the final 

rule titled: Mandatory Greenhouse Gas Reporting (74 FR 

56259), under the authority of Sections 114 and 208 of the 

Clean Air Act. The Mandatory Greenhouse Gas Reporting rule 

requires reporting of greenhouse gas (GHG) emissions from 

all sectors of the economy. The rule requires the 

monitoring of GHGs beginning with the 2010 calendar year, 

with reports submitted annually by a March 31 deadline in 

each following year. The rule does not require control of 

GHGs, rather it only requires that sources above certain 

threshold levels monitor and report emissions and other 

related data. 

Since promulgation of the rule, the Administrator has 

identified a number of technical issues that need to be 
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corrected and specific portions of the rule that need to be 

clarified. We are proposing to amend specific provisions 

in the 2009 Final Mandatory Greenhouse Gas Reporting rule 

(2009 Final MRR) to correct certain technical and editorial 

errors that have been identified since promulgation and to 

clarify or propose minor updates to certain provisions that 

have been the subject of questions from reporting entities. 

We are seeking comments only on the proposed amendments 

presented in this action. Comments addressing other 

provisions of the 2009 Final MRR or any related rulemakings 

will not be considered relevant to these amendments. EPA 

has also received six petitions for reconsideration on the 

2009 Final MRR. EPA is still considering these petitions, 

and the issues raised in the petitions are not discusssed 

or addressed in today’s action. 

DATES: Comments. Comments must be received on or 

before [INSERT THE DATE 45 DAYS AFTER PUBLICATION IN THE 

FEDERAL REGISTER]. 

Public Hearing. EPA does not plan to conduct a public 

hearing unless requested. To request a hearing, please 

contact the person listed in the following FOR FURTHER 

INFORMATION CONTACT section by [INSERT DATA 7 DAYS AFTER 

DATE OF PUBLICATION IN THE FEDERAL REGISTER]. If 

requested, the hearing will be conducted on [INSERT DATE 15 
3

DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER], in 

the Washington, DC area. EPA will provide further 

information about the hearing on its webpage if a hearing 

is requested. 

ADDRESSES: You may submit your comments, identified 

by docket ID No. EPA–HQ–OAR–2010-0109 by any of the 

following methods: 

• Federal eRulemaking Portal: 

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

instructions for submitting comments. 

• E-mail: MRR_Corrections@epa.gov. Include docket ID No. 

EPA–HQ–OAR–2010-0109 [and/or RIN number] in the 

subject line of the message. 

• Fax: (202) 566–1741. 

• Mail: Environmental Protection Agency, EPA Docket 

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

No. OAR–2010-0109, 1200 Pennsylvania Avenue, NW., 

Washington, DC 20004. 

• Hand/Courier Delivery: EPA Docket Center, Public 

Reading Room, EPA West Building, Room 3334, 1301 

Constitution Avenue, NW., Washington, DC 20004. Such 

deliveries are only accepted during the Docket’s 

normal hours of operation, and special arrangements 

should be made for deliveries of boxed information. 

Instructions: Direct your comments to Docket ID No. 

EPA–HQ–OAR–2010-0109, Technical Corrections, Clarifying and 

Other Amendments to Certain Provisions of the Mandatory 

Greenhouse Gas Reporting Rule. EPA’s policy is that all 

comments received will be included in the public docket 

without change and may be made available online at 

http://www.regulations.gov, including any personal 
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information provided, unless the comment includes 

information claimed to be confidential business information 

(CBI) or other information whose disclosure is restricted 

by statute. Do not submit information that you consider to 

be CBI or otherwise protected through 

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

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

system, which means EPA will not know your identity or 

contact information unless you provide it in the body of 

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

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

e-mail address will be automatically captured and included 

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

and made available on the Internet. If you submit an 

electronic comment, EPA recommends that you include your 

name and other contact information in the body of your 

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

cannot read your comment due to technical difficulties and 

cannot contact you for clarification, EPA may not be able 

to consider your comment. Electronic files should avoid 

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

be free of any defects or viruses. 

Docket: All documents in the docket are listed in the 

http://www.regulations.gov index. Although listed in the 
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index, some information is not publicly available, e.g., 

CBI or other information whose disclosure is restricted by 

statute. Certain other material, such as copyrighted 

material, will be publicly available only in hard copy. 

Publicly available docket materials are available either 

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

copy at the Air Docket, EPA/DC, EPA West Building, Room 

3334, 1301 Constitution Ave., NW., Washington, DC. This 

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

through Friday, excluding legal holidays. The telephone 

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

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

FOR FURTHER 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 

address: GHGReportingRule@epa.gov. For technical 

information contact the Greenhouse Gas Reporting Rule 

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

ghgmrr@epa.gov. To obtain information about the public 

hearings or to register to speak at the hearings, please go 

to http://www.epa.gov/climatechange/
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emissions/ghgrulemaking.html. Alternatively, contact 

Carole Cook at 202–343–9263. 

Worldwide Web (WWW). In addition to being available 

in the docket, an electronic copy of today's proposal will 

also be available through the WWW. Following the 

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

posted on EPA's greenhouse gas reporting rule website at 

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

emissions/ghgrulemaking.html. 

SUPPLEMENTARY INFORMATION: 

Additional Information on Submitting Comments: To 

expedite review of your comments by Agency staff, you are 

encouraged to send a separate copy of your comments, in 

addition to the copy you submit to the official docket, to 

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

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

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

GHGReportingRule@epa.gov. 

Regulated Entities. The Administrator determined that 

this action is subject to the provisions of Clean Air Act 

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

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

as the Administrator may determine”). These are proposed 

amendments to existing regulations. If finalized, these 
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amended regulations would affect owners or operators of 

certain fossil fuel suppliers, direct emitters of GHGs, 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. 

Glass Production 327211 Flat glass manufacturing 

facilities. 

327213 Glass container manufacturing 

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 Alkalies and chlorine manufacturing 

facilities. 

Soda Ash 

Manufacturing 

212391 Soda ash, natural, mining and/or 

beneficiation. 

Titanium Dioxide 

Production 

325188 Titanium dioxide manufacturing 

facilities. 

Zinc Production 331419 Primary zinc refining facilities. 
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Category NAICS Examples of affected facilities 

331492 Zinc dust reclaiming facilities, 

recovering from scrap and/or 

alloying purchased metals. 

Municipal Solid 

Waste Landfills 

562212 Solid 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 

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. 
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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 

CAA Clean Air Act 

CaO calcium oxide 

CBI confidential business information 

CEMS continuous emission monitoring system 

CFR Code of Federal Regulations 

CH4 methane 

CO2 carbon dioxide 

DE destruction efficiency 

EAF electric arc furnace 

EF emission factor 

EIA Energy Information Administration 

EO Executive Order 

EPA U.S. Environmental Protection Agency 

FR Federal Register 

GHG greenhouse gas 

HHV higher heating value 

ID identification 

kg kilograms 

LNG liquefied natural gas 

MgO magnesium oxide 

Mscf thousand standard cubic feet 

MRR mandatory GHG reporting rule 

N2O nitrous oxide 

NAICS North American Industry Classification System 

NGLs natural gas liquids 

NOx nitrogen oxides 

OMB Office of Management and Budget 
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QA/QC quality assurance/quality control 

RFA Regulatory Flexibility Act 

U.S. United States 

UMRA Unfunded Mandates Reform Act of 1995 

TABLE OF CONTENTS 

I. Background 

A. How is this Preamble Organized? 

B. Background on Today’s Action 

C. Legal Authority 

D. How Would These Amendments Apply to 2011 Reports? 

II. Technical Corrections and Other Amendments 

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 

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

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 
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B. Paperwork Reduction Act 

C. Regulatory Flexibility Act (RFA) 

D. Unfunded Mandates Reform Act (UMRA) 

E. Executive Order 13132: Federalism 

F. Executive Order 13175: Consultation and Coordination 

With Indian Tribal Governments 

G. Executive Order 13045: Protection of Children From 

Environmental Health Risks and Safety Risks 

H. Executive Order 13211: Actions That Significantly 

Affect Energy Supply, Distribution, or Use 

I. National Technology Transfer and Advancement Act 

J. Executive Order 12898: Federal Actions To Address 

Environmental Justice in Minority Populations and LowIncome Populations 

I. Background 

A. How is this Preamble Organized?

The first section of this preamble contains the basic 

background information about the origin of these proposed 

rule amendments and request for public comment. This 

section also discusses EPA’s use of our legal authority 

under the Clean Air Act to collect data under the mandatory 

GHG reporting rule. 

The second section of this preamble describes in 

detail the changes that are being proposed to correct 

technical errors, to provide clarification, or propose 

amendments to address implementation issues identified by 

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

for the proposed changes and identifies issues on which EPA 

is particularly interested in receiving public comments. 
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Finally, the last (third) section of the preamble 

discusses the various statutory and executive order 

requirements applicable to this proposed rulemaking. 

B. Background on Today’s Action

The 2009 Final MRR was signed by EPA Administrator 

Lisa Jackson on September 22, 2009 and published in the 

Federal Register on October 30, 2009 (74 FR 56260-56519, 

October 30, 2009). The 2009 Final MRR, which became 

effective on December 29, 2009, included reporting of GHGs 

from various facilities and suppliers, consistent with the 

2008 Consolidated Appropriations Act1. The source 

categories in the 2009 Final MRR cover approximately 85 

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

emitters as well as suppliers of fossil fuels and 

industrial gases. 

C. Legal Authority

EPA is proposing these rule amendments under its 

existing CAA authority, specifically authorities provided 

in section 114 and section 208 of the CAA. 

As stated in the preamble to the 2009 Final MRR (74 FR 

56260, October 30, 2009), CAA section 114 provides EPA 

broad authority to require the information proposed to be 

 

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

1844, 2128. 
13

gathered by this rule because such data would inform and 

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

provisions. As discussed in the preamble to the initial 

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

114(a)(1) of the CAA authorizes the Administrator to 

require emissions sources, persons subject to the CAA, 

manufacturers of control or process equipment, or persons 

whom the Administrator believes may have necessary 

information to monitor and report emissions and provide 

such other information the Administrator requests for the 

purposes of carrying out any provision of the CAA. For 

further information about EPA’s legal authority, see the 

preambles to the proposed and 2009 Final MRR.2

D. How Would These Amendments Apply to 2011 Reports?

EPA is planning to address the comments on these 

proposed amendments and publish the final amendments before 

the end of 2010. Therefore, reporters would be expected to 

calculate emissions and other relevant data for the reports 

that are submitted in 2011 using the 2009 Final MRR as 

amended. We have determined that it is feasible for the 

sources to implement these changes for the 2010 reporting 

year since the revisions primarily provide additional 

 

2 74 FR 16448 (April 10, 2009) and 74 FR 56260 (October 30, 2009). 
14

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. 

For example, many proposed revisions simply provide 

additional information to provide additional clarity on 

existing requirements. For example, in subpart E (Adipic 

Acid Production) we are proposing to clarify that the 

location of the testing point for determining the emission 

factor can occur before or after N2O abatement technology as 

long as the destruction efficiency of the N2O abatement 

technology is properly accounted for. This proposed 

clarification is consistent with clarifications EPA has 

issued in response to industry questions and would not 

change how facilities collected data during 2010. In 

subpart K, clarifying text is proposed in §98.112 to ensure 

that facilities calculate CH4 emissions for all ferroalloys 

included in Table K-1. Again, this clarification does not 

change the rule requirements for facilities collecting data 

in 2010 as the requirement was already clear in §98.113(d). 

Some proposed amendments are to the data reporting 

requirements to provide additional clarity on the level of 

reporting for a specific parameter (e.g., unit level or 

facility level). For example, in subpart CC (Soda Ash 
15

Manufacturing) we are proposing to clarify that reporting 

is by soda ash manufacturing line. While the data 

reporting requirements in the 2009 Final MRR could have 

been misinterpreted, the calculation methods in §98.293 are 

very clear that emissions calculations are by manufacturing 

line. EPA has concluded that amendments such as these can 

be implemented for the reports submitted to EPA in 2011 

because the proposed changes are consistent with the 

calculation methodologies in the 2009 Final MRR and the 

owners or operators are not required to actually report 

until March 2011, several months after we expect this 

proposal to be finalized. 

For some subparts, we propose amendments to address 

issues identified as a result of working with the affected 

sources during rule implementation. These proposed 

revisions provide additional flexibility to the sources. 

Thus, while they would be free to use the amended 

regulations once final, facilities are not required to 

follow the amendments for 2010 data collection. For 

example, in subpart H, cement production, facilities are 

provided an additional approach for calculating the weight 

fraction of total calcium oxide and total magnesium oxide 

in clinker. Some facilities were already determining their 

weight fraction following this method. In some cases, these 
16

facilities may have been following both their current 

practice during 2010 data collection, as well as the method 

required by the 2009 Final MRR. With these proposed 

amendments, these facilities would have the option, but not 

be required, to use the newly proposed option for the 

reports submitted to EPA in 2011. 

EPA is also proposing corrections to terms and 

definitions in certain equations. For example, in subpart 

NN, Suppliers of Natural Gas and Natural Gas Liquids, we 

are proposing to clarify in an equation that the fuelspecific emission factor should be developed for NGL 

product “g”. It was clear from the rest of the equation 

that the mass emissions should be developed for each NGL 

product “g”, but this phrase was omitted from the 

definition of EFg. Other examples are found in similar 

clarifications made in subpart P (Hydrogen Production) and 

subpart S (Lime Production). These clarifications do not 

result in additional requirements therefore EPA has 

concluded that reporters can follow the 2009 Final MRR, as 

amended, in submitting their first reports in 2011. 

Finally, EPA is proposing other technical corrections 

(example correcting cross references) that have no impact 

on facility’s data collection efforts in 2010. 
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In summary, these amendments would not require any 

additional monitoring or information collection above what 

was already included in the 2009 Final MRR. Therefore, we 

expect that sources can use the same information that they 

have been collecting under the 2009 Final MRR for each 

subpart to calculate and report GHG emissions for 2010 and 

submit reports in 2011 under the amended subparts. 

EPA generally seeks comment on the conclusion that it 

is appropriate to implement these amendments and 

incorporate the requirements in the data reported to EPA by 

March 31, 2011. Further, we seek comment on whether there 

are specific subparts for example, subpart MM, where this 

timeline may not be feasible or appropriate due to the 

nature of the proposed changes or the way in which data 

have been collected thus far in 2010. We request that 

commenters provide specific examples of how the proposed 

implementation schedule would or would not work. 

II. Technical Corrections and Other Amendments 

Following promulgation of the 2009 Final MRR, EPA has 

identified errors in the regulatory language that we are 

now proposing to correct. These errors were identified as 

a result of working with affected industries to implement 

the various subparts of the 2009 Final MRR. We have also 

identified certain rule provisions that should be amended 
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to provide greater clarity. The amendments we are now 

proposing include the following types of changes: 

• Changes to correct cross references within and between 

subparts. 

• Additional information to better or more fully 

understand compliance obligations in a specific 

provision, such as the reference to a standardized 

method that must be followed. 

• Amendments to certain equations to better reflect 

actual operating conditions. 

• Corrections to terms and definitions in certain 

equations. 

• Corrections to data reporting requirements so that 

they more closely conform to the information used to 

perform emission calculations. 

• Other amendments related to certain issues identified 

as a result of working with the affected sources 

during rule implementation and outreach. 

We are seeking public comment only on the issues 

specifically identified in this notice for the identified 

subparts. We will not respond to any comments addressing 

other aspects of the 2009 Final MRR or any other related 

rulemakings. 

A. Mobile Sources

Manufacturers of highway heavy-duty vehicles, as well 

as manufacturers of highway heavy-duty engines, are subject 

to GHG reporting requirements as proposed (see Section 

V.QQ.3.d starting on page 16589 of the proposed rule 

preamble), and as stated in the preamble for the 2009 Final 

MRR (see Table IV-1 on page 56353 of the final rule 
19

preamble). EPA inadvertently omitted the regulatory text 

covering manufacturers of highway heavy-duty vehicles. We 

are proposing to amend 40 CFR part 86 to correct that error 

by incorporating the appropriate language into the 

regulations at 40 CFR 86.1844-01. 

B. Subpart A – General Provisions

We are proposing to add or change several definitions 

to subpart A, to clarify terms used in other subparts of 

the 2009 Final MRR. Similarly, we are proposing to amend 

40 CFR 98.7 (incorporation by reference) to accommodate 

changes in the standard methods that are allowed by other 

subparts of the rule. 

We are proposing to amend the following definitions in 

40 CFR 98.6: 

• Carbonate-based mineral, 

• Carbonate-based mineral mass fraction, 

• Carbonate-based raw material, 

• Crude oil, and 

• Gas collection system or landfill gas collection 

system. 

We are proposing to amend the definitions of 

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

fraction” and “carbonate-based raw material” in order to 

include barium carbonate and potassium carbonate. These 

carbonates were not included in the 2009 Final MRR; 
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however, EPA has since learned that these are consumed in 

the glass industry subject to subpart N. Therefore, we are 

proposing emission factors for these carbonates in subpart 

N and, for consistency, we are proposing to concurrently 

amend these definitions in 40 CFR 98.6. 

We are proposing to amend the definition of “crude 

oil” in 40 CFR 98.6 to be identical to the definition in 

the Energy Information Administration’s (EIA) Definitions 

of Petroleum Products and Other Terms (Revised January 

2010)3. As indicated by our definition of crude oil in the 

Notice of Proposed Rulemaking (74 FR 16448), our intention 

is to collect information under 40 CFR 98.396(a)(20) on 

certain hydrocarbons from sources that are not liquid while 

underground as well as those that are liquid underground. 

We changed the definition of crude oil after proposal in 

response to a comment suggesting that the proposed 

definition could be interpreted to include natural gas (see 

comment EPA-HQ-OAR-2008-0508-0631.1, excerpt 36 in Volume 

13: Subpart A: Definitions, Incorporation by Reference, and 

Other Subpart A Comments). In making this change after 

proposal, we inadvertently limited the definition of crude 

oil in the 2009 Final MRR to hydrocarbons that exist in a 

 

3

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

pdf 
21

liquid phase underground. We are proposing to correct this 

error in today’s action. We also expect to increase 

clarity and reduce administrative burden for reporters by 

proposing to use EIA’s definition of “crude oil,” which 

many reporters already use to track crude oil for EIA’s 

petroleum supply surveys. 

We received several questions as to whether passive 

vents or flares are considered part of a landfill gas 

collection system at a municipal solid waste landfill. To 

clarify that the passive vents/flares are not considered 

part of a landfill gas collection system for purposes of 

subpart HH, we are proposing to amend the definition of 

"gas collection system or landfill gas collection system," 

in 40 CFR 98.6 to state that such a system collects gas by 

means of a fan or similar mechanical, versus passive, draft 

equipment. 

We are also proposing to amend the definition of 

“Mscf” in 40 CFR 98.6 to indicate that “Mscf” means 

thousand standard cubic feet, and not, as incorrectly 

stated in the 2009 Final MRR, a million standard cubic 

feet. 

We also are proposing to amend the definition of “noncrude feedstocks” in 40 CFR 98.6 to remove the phrase “as a 

feedstock” in order to avoid confusion with the definition 
22

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, including 

supplemental fuel burned to provide heat or thermal energy. 

The definition of “feedstock” in 40 CFR 98.6 excludes 

supplemental fuel burned to provide heat or thermal energy. 

By removing the term “as a feedstock” from the definition 

of “non-crude feedstock” and adding “including supplemental 

fuel burned to provide heat or thermal energy,” the 

proposed amendments align the definition to the original 

intent of the rule. 

Additional amendments to definitions are proposed in 

the relevant subparts. 

Today’s proposal would also correct an error in the 

title of a method incorporated by reference in 40 CFR 98.7 

for subpart Z, which would be updated to reflect the 

correct title, “Association of Fertilizer and Phosphate 

Chemists Analytical Methods Manual, 10th Edition.” We are 

also proposing to incorporate by reference ASTM D6349-09, 

“Standard Test Method for Determination of Major and Minor 

Elements in Coal, Coke, and Solid Residues from Combustion 
23

of Coal and Coke by Inductively Coupled Plasma—Atomic 

Emission Spectrometry” for subpart N. 

C. Subpart E – Adipic Acid Production

We are proposing to amend Equations E-1, Equation E-2 

and Equation E-3 in 40 CFR 98.53. First, we are proposing 

to amend 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 proposing to amend the 

equations so that emissions would be 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 sum the emissions for all such units 

or lines to determine the overall N2O emissions for the 

facility. For consistency with these amendments, we are 

also proposing amendments to 40 CFR 98.54(a), 98.56(j), and 

98.57(c) for monitoring and QA/QC, reporting, and 

recordkeeping, respectively. 
24

We are also proposing to amend equation E-3 to 

accommodate N2O abatement technology located after the 

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

equation E-3a. We are also proposing to add a new equation 

E-3b for facilities that do not have any N2O abatement 

technology located after the test (sampling) point. 

Second, we are proposing to amend 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 proposing to amend the 

language in 40 CFR 98.54(a)(1), (e), and (f) concerning the 

location of the test (sampling) point used for the 

performance test and to clarify when the performance test 

should be conducted. 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 are mandatory 

according to the facility operating permit. The proposed 

amendments would 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. Finally, we are proposing to clarify under 
25

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

collected during performance tests, not just the calculated 

emission factor. 

D. Subpart H – Cement Production

We are proposing to amend 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 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 proposing to amend 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 

proposing to amend 40 CFR 98.84(d) to allow facilities to 

use these procedures already used for measuring clinker 

produced and verify those on a monthly basis. Facilities 

are already required to measure clinker on a monthly basis. 
26

Concurrent with this change, we are proposing to amend 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. 

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 proposing to 

amend 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 proposing to correct and clarify the 

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

for facilities with CEMS and for facilities without CEMS. 

In the 2009 Final MRR, 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 
27

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). 

E. Subpart K – Ferroalloy Production 

We are proposing to amend 40 CFR 98.112(a) to be 

consistent with the requirement described in 40 CFR 

98.113(d) and in the preamble of the 2009 Final MRR 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. The 2009 Final MRR 

contained calculation and reporting procedures for 

quantifying process CH4 emissions from all ferroalloys 

listed in Table K-1, but CH4 was inadvertantly not included 

in the GHG’s to Report section. 

We are also proposing to amend 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 proposing minor amendments to 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 
28

ferroalloy product identified in 40 CFR 98.110. We are 

also proposing to amend 40 CFR 98.116(d) to correct an 

incorrect cross-reference to 40 CFR 98.36. 

F. Subpart N – Glass Production

We are proposing to amend subpart N to add CO2 emission 

factors to Table N-1 for barium carbonate and potassium 

carbonate. These raw materials were not included in the 

2009 Final MRR, but EPA has since learned that they are 

also used by the glass industry. EPA is requesting comment 

on whether the proposed amendments to Table N-1 are 

sufficient or if other raw materials or carbonaceous 

materials are used in glass manufacturing that should be 

included in the rule in Table N-1 with their associated 

emission factors. EPA has also learned from reporters that 

there is another more commonly used method for determining 

the carbonate mineral mass fraction of raw materials used 

in glass production. EPA proposes to amend the rule in 40 

CFR 98.144(b) to allow for another ASTM method. 

Specifically, in addition to ASTM D3682-01, reporters could 

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 proposing to amend the introductory language to 
29

40 CFR 98.146(a) to correct an incorrect cross-reference 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 proposing to amend 40 CFR 98.146(b)(7) and (9) to 

correct typographical errors. 

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

We are proposing to amend 40 CFR 98.154(k), the 

requirement to monitor HFC-23 emitted from process vents, 

to refer to Equation O-7 rather than the incorrect Equation 

O-6. In 40 CFR 98.154(k), (l), and (o) and in 40 CFR 

98.156(b), we are proposing to amend the language so that 

the term “destruction device” is used rather than the 

narrower term “thermal oxidizer.” 

We are proposing to amend 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 would be required to report 

the newly calculated DE of the device, the HFC-23 

concentration measurement used in the DE calculation, and 
30

whether 40 CFR 98.154(l)(1) or (l)(2) was used for the 

calculation. Under these two paragraphs, other HFC-23 

destruction facilities would be required to report only the 

results of their annual measurement of the HFC-23 

concentration at the outlet of the destruction device. 

Facilities that conduct the annual measurement of the HFC23 concentration only at the outlet of the destruction 

device would be required to report the results of the 

annual measurement. 

We are proposing to amend 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 

proposed amendment will make the due date in 40 CFR 

98.156(e) consistent with the due date for a similar report 

required in Subpart OO. 

In general, these proposed amendments to the reporting 

requirements for HFC-23 destruction facilities would make 

them consistent with the monitoring requirements for these 

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

are consistent with those elsewhere in the 2009 Final MRR 

for the source categories that are required to begin 

monitoring in 2010. 

H. Subpart P - Hydrogen Production 
31

We are proposing amendments to clarify the definition 

of the source category in 40 CFR 98.160(c). The original 

language in the 2009 Final MRR indicated that the hydrogen 

production source category included hydrogen production 

processes located within petroleum refineries. The intent 

of the 2009 Final MRR was that hydrogen production 

facilities located within facilities that are not petroleum 

refineries were also included within the definition of the 

source category. We are proposing to amend 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. 

Broadly, we are proposing to amend 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 proposing 
32

to clarify the text in the rule by removing references to 

the term “process” from the rule language. 

We are proposing to remove 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 would still be reported under 

98.162(a) using the procedures in 98.163(a) or 98.163(b). 

We are also proposing to amend language describing the 

calculation of GHG emissions from gaseous, liquid and solid 

fuels and feedstocks in 40 CFR 98.163. The clarified 

language would specify that each gaseous, liquid or solid 

fuel and feedstock would need to be calculated based on its 

respective equations detailed in the rule language. This 

removes the concern that the current language was unclear 

as to which fuel and feedstock stream would be used to 

calculate CO2 emissions. 

Lastly, we are proposing to amend 40 CFR 98.166(c) to 

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

subject to subpart P may also be subject to subpart PP – 
33

Suppliers of Carbon Dioxide. Quarterly reporting of CO2

quantities (in kilograms) was not consistent with subpart 

PP. 

I. Subpart Q – Iron and Steel Production

We are proposing to amend 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 the 2009 Final MRR required reporting of CO2

emissions from flares using procedures from subpart Y 

(Petroleum Refineries), without distinguishing flares 

burning off-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) in the 2009 Final MRR 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, 

proposing to amend the language in 40 CFR 98.172(b) to 

clarify that for subpart Q facilities, flare emissions must 

be estimated only for flares burning blast furnace gas or 

coke oven gas. Similarly, we are proposing to amend the 
34

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 proposing 

to amend 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 the 2009 Final MRR also referenced 

incorrect equations from subpart Y. We are proposing to 

amend and correct the references in 40 CFR 98.172(b) to the 

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

correct equations; the promulgated subpart Q incorrectly 

referenced Equation Y-1. 

We are proposing to amend 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 

proposing to add paragraphs (g) and (h) to 40 CFR 98.176. 

Paragraph (g) would require facilities to report the annual 

amount of coal charged to coke ovens because it is used to 

estimate CO2 emissions from coke pushing. Paragraph (g) 

would incorporate 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. 
35

We are proposing to amend 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 proposing to amend the requirements in the 

promulgated rule to estimate GHG emissions from argonoxygen decarburization vessels to clarify that they also 

apply to any other type of vessel used to remove carbon 

from molten steel (decarburization) and result in the 

venting of similar GHG. The promulgated rule would have 

required reporting of these alternative vessel emissions as 

part of flare emissions. Because of the proposed 

clarification noted above to limit the flare emission 

calculations to only those flares burning coke oven gas or 

blast furnace gas, we are proposing to replace the term 

“argon-oxygen decarburization vessels” with the term 

“decarburization vessels” throughout the rule and to 

replace 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. 

J. Subpart S – Lime Manufacturing
36

We are proposing to amend 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 proposing to amend 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 proposing amendments to the terminology in the subpart 

to clarify when the calculation and reporting requirements 

apply to lime products that are produced at the facility. 

K. Subpart V – Nitric Acid Production

We are proposing to amend 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 concerns 

the language for 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 are mandatory according to 

the facility operating permit. The proposed amendments 

would clarify that testing can occur before or after N2O 
37

abatement technology as long as the destruction efficiency 

is properly accounted for. 

We are also proposing to include a new Equation V-3b 

for facilities that do not have N2O abatement technology 

located after the test (sampling) point. Equation V-3 

would be redesignated as Equation V-3a, and would also be 

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

equation would be changed from EFN2Ot to EN2Ot. 

In addition we are proposing to clarify 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 are being proposed 

for the monitoring requirements in 40 CFR 98.224 to conform 

to the changes in the calculation methods being proposed in 

40 CFR 98.223. We are proposing to amend 40 CFR 

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

production campaign facilities must conduct the performance 

test. 

We are also proposing to amend 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 
38

an N2O emission factor. The language has been changed to 

correct this point. 

We are proposing to amend 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. 

L. Subpart Z – Phosphoric Acid Production

We are proposing to amend subpart Z to correct the 

title of the reference to the standard bulk sampling and 

analysis method in 40 CFR 98.6, and 40 CFR 98.264(a) and 

(b). The reference in the 2009 Final MRR currently reads, 

“Phosphate Mining States Methods Used and Adopted by the 

Association of Fertilizer and Phosphate Chemists AFPC 

Manual 10th Edition 2009 - Version 1.9.” This reference 

would be revised to read the “Association of Fertilizer and 

Phosphate Chemists Analytical Methods Manual 10th Edition,” 

which reflects the correct title of the document. 

We have learned from facilities that the AFPC manual 

does not currently contain a procedure for obtaining a 

representative grab sample of rock for testing, but that it 

will in the future. We are proposing to amend 40 CFR 

98.264(a) to allow facilities to use the appropriate 

industry consensus standards currently available, in 

addition to the AFPC manual. We are also proposing to 
39

amend 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 proposing to amend 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 proposing to add 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. 

M. Subpart CC – Soda Ash Manufacturing

We are proposing to amend 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) would be corrected from metric tons to short 

tons for consistency with other similar data reporting 
40

requirements. This change is also consistent with how 

facilities collect these data. 

We are also proposing to amend 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 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 

proposing to delete 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). 

N. Subpart EE – Titanium Dioxide Production

We are proposing to amend 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 proposing to amend 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 
41

petroleum coke can only be from the supplier. We are also 

proposing to amend 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). 

O. Subpart GG – Zinc Production

We are proposing to amend the definitions of the terms 

for (Electrode)k and (CElectrode)k in Equation GG-1 to remove 

the references to kilns because electrodes are only used in 

electrothermic furnaces and are not used in Waelz kilns. 

We are also proposing to amend 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 proposing to amend the data reporting 

requirements in 40 CFR 98.336(b)(7) and (10) to clarify 

that the carbon 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 
42

contents were determined through self measurement or based 

on reports from the supplier. 

P. Subpart HH – Municipal Solid Waste Landfills

We are proposing 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. Technical amendments to the rule are 

also proposed to address some of the more significant 

questions that were the result of insufficient detail being 

provided in the rule. 

Source Category Definition. We are proposing to amend 

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

include Resource Conservation and Recovery Act (RCRA) 

Subtitle C or Toxic Substances Control Act (TSCA) hazardous 

waste landfills, dedicated construction and demolition 

waste landfills, or industrial waste landfills.” This 

change would clarify the types of landfills that are not 

included in the MSW landfill source category. We are 

further proposing to add definitions within 40 CFR 98.348 

for the terms “dedicated construction and demolition waste 

landfills” and “industrial waste landfills” to further 

clarify what is meant by these excluded landfill types. 

These definitions are from 40 CFR 257.2 (Criteria for 
43

Classification of Solid Waste Disposal Facilities and 

Practices). 

Equation HH-1. We are proposing 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 as it no longer appears 

in the equation. This change provide clarity of terms 

and does not affect the way in which the methane 

generation rate is calculated by equation HH-1 since 

the new terms were already contained in the definition 

of LO. 

• 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,” for clarity. 

• 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)” to include the use of 

measurement data with the other methods specified. 

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

correction factor (fraction). Use the default value 

of 1,” to clarify that the default factor of 1 must be 

used. 

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

DOC dissimilated (fraction). Use the default value of 

0.5,” to clarify that the default factor of 0.5 must 

be used. 

• Revise the definition of “F” to clarify that F is 

determined on a dry basis as follows: “Fraction by 

volume of CH4 in landfill gas from measurement data on 

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

for clarification. 

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

from Table HH-1 of this subpart (yr-1). Select the 
44

most applicable k value for the majority of the past 

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

to clarify that k is not a measured value and that the 

selection of k should be based on precipitation and 

leachate recirculation rates over the past 10 years. 

We are also proposing to amend 40 CFR 98.343(a)(2) to 

replace “use the bulk waste parameter values for k and L0 

in Table HH-1” with “use the bulk waste parameter values 

for k and DOC in Table HH-1,” to be consistent with the 

proposed changes to Equation HH-1. 

Measuring Waste Quantity. We are proposing to amend 

40 CFR 98.343(a) by adding a new paragraph (a)(3) that 

serves to provide the necessary detail and clarification on 

the requirements for measuring the quantity of waste 

disposed in the landfill beginning with the first 

monitoring year (2010 or later, hereafter referred to as 

“monitoring years”), and re-designating the existing 40 CFR 

98.343(a)(3) as (a)(4). 

The proposed waste measurement requirements for the 

monitoring years would 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. Passenger vehicles and light duty pick-up 

trucks contribute only a small fraction of the total waste 

landfilled, but they significantly contribute to the total 

number of vehicles entering and exiting the landfill. As 
45

such, most landfills do not weigh individual passenger 

vehicles or light duty pick-up trucks. Instead, they 

commonly charge these customers a flat tipping fee. 

Requiring each of these vehicles to be weighed both in and 

out of the landfill would create a significant time and 

recordkeeping burden on the landfill owner or operator 

which was not included in the cost and economic impact 

analysis for subpart HH. Furthermore, we find that such a 

requirement is not appropriate because the significant 

increase in labor costs will not significantly reduce the 

uncertainty in the mass of waste landfilled. This is, in 

part, due to the small contribution these loads make on the 

total quantity of waste landfilled and, in part, due to the 

fact that these vehicles often have small loads relative to 

the vehicle weight so the direct measurements have greater 

uncertainty for small loads than they do for larger loads. 

When scales are present at the MSW landfill, they must 

be used, (except for passenger vehicles and light duty 

pick-up trucks). Two options for the use of scales are 

included in this proposal. 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 offloaded, and calculate the mass of waste disposed as the 

difference in the two measurements. The second option 
46

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 

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. 

While we originally assumed that scales would be 

present at all MSW landfills, some reporters indicated that 

this is not the case. After careful review of the 2009 

Final MRR and its technical record, it appears the intended 

requirement to use scales is not clearly defined in the 

2009 Final MRR and no details were provided as to how such 
47

measurements using scales were to be made. Furthermore, 

the definition of “Wx” in Equation HH-1 stated that “Wx = 

Quantity of waste disposed in the landfill in year x from 

tipping fee receipts or other company records.” This 

definition does not suggest a need to perform direct mass 

measurements. This definition was intended to allow use of 

tipping fee receipts or company records for the years prior 

to the first reporting year, but can also be interpreted to 

allow these same records to be used in the reporting year. 

While 40 CFR 98.343(a)(3) in the 2009 Final MRR provided 

methods for “years prior to reporting for which waste 

disposal quantities are not readily available,” there were 

no specific instructions for measurement methods for waste 

disposal quantities in the reporting year. 

For the few landfills that do not have scales, the 

cost of installing scales was evaluated. According to one 

of the commenters, the capital cost of installing scales 

could be as much as $50,000 per scale, with operating and 

driver time resulting in an estimated annualized cost of 

over $23,000. We also considered the uncertainty 

associated with different waste quantity measuring methods 

and their resulting uncertainty in the overall modeled 

methane generation. Relative to the uncertainty of the 

other model parameters, requiring all landfills to have 
48

scales for mass measurements would not significantly reduce 

the overall uncertainty in the modeled methane generation. 

Given the significant additional costs for requiring the 

installation of scales at a landfill and the limited 

improvement in the uncertainty of the reported methane 

emissions, we are proposing to allow the use of “truck 

counts and capacities” as an acceptable method of 

determining waste quantity landfilled. 

In addition, we are proposing to redesignate paragraph 

(a)(3) of 40 CFR 98.343 to (a)(4) and to amend that 

paragraph and the sub-paragraphs to clarify that 

measurement data can be used for historical years when the 

data are available. We are proposing to clarify 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 proposing to amend 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,” 

to properly account for situations when waste quantity data 

are available for some, but not all, historic years. We 

are proposing to amend 40 CFR 98.343(a)(4)(iii) by revising 
49

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

from the first year accepting waste,” to enhance the 

meaning of that sentence. 

In related amendments, we are also proposing to amend 

40 CFR 98.344(a) to clarify the requirements for 

measurement equipment by stating 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 Devices,” NIST 

Handbook 44 (2009) (incorporated by reference, see 40 CFR 

98.7).” We are also proposing to amend 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 proposed 

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

quantities determined using vehicle counts and load 

capacities. We are also proposing to amend 40 CFR 98.347 

to specifically require that records be maintained of all 

measurements used to determine vehicle tare weights or 

working capacities. 
50

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

following technical amendments to Equation HH-2 in 40 CFR 

98.343: 

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

“%SWDS” to simplify the equation since both terms were 

look-up values and the product can be expressed as a 

single value. 

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

Average per capita waste disposal rate for year x from 

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

year, wet basis; tons/cap/yr),” for consistency with 

the revisions of Equation HH-2. 

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

consistency with the revisions of Equation HH-2. 

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

correct a grammatical error. 

We are proposing the following technical amendments to 

Equation HH-3 in 40 CFR 98.343: 

• Replace the term “WDRx” with “Wx” for consistency with 

the same term as expressed in Equation HH-1. 

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

quantity of waste place in the landfill in year x 

(metric tons/wet basis),” for consistency with the 

same term as expressed in Equation HH-1. 

• 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),” for clarity. 

We are proposing the following technical amendments to 

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

• Amend Equation HH-4 and the terms in that equation to 

more clearly allow for daily averages (365 or 366 per 
51

year) from a continuous CH4 monitoring system, or from 

weekly sampling (with 52 measurement periods). 

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

because the measurement frequency is specified in 

subsequent paragraphs. 

• In 40 CFR 98.343(b)(2)(ii) and subparagraphs (A) and 

(B), replace “no less than weekly” with “once each 

calendar week, with at least three days between 

measurements,” to clarify what is meant by weekly 

sampling. 

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

all landfills, calculate...” to clarify and provide 

parallel sentence structure. 

Moisture Content Measurement. In addition to the 

other amendments to Equation HH-4 discussed above, we are 

proposing to amend the moisture content measurement 

requirements in Equation HH-4. We intended that Equation 

HH-4 would be calculated on a daily or weekly average 

basis, but it was not properly codified in the 2009 Final 

MRR to allow for weekly measurements. Specifically, the 

instructions to use N=52 for weekly sampling is incorrect 

given the fixed unit conversion factor for minutes per day. 

To correct this error, we are proposing to revise the 

definition of (V)n to be the cumulative volume for the 

measurement period (rather than the volumetric flow rate), 

eliminate the 1,440 conversion factor for minutes per day, 

and revise the reference to “day” in the definition of 

equation terms with “measurement period.” 
52

We also received numerous questions regarding the 

moisture correction term in Equation HH-4, suggesting that 

the instructions to replace this term with 1 within the 

definitions of (V)n and (C)n were confusing and incomplete. 

We intended that moisture content would be determined, 

if necessary, through measurement data. To address this 

issue, we are also proposing to amend Equation HH-4 to 

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

moisture correction factor, KMC. KMC would be 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. 

Equation HH-4 in the 2009 Final MRR did not consider 

the third scenario for KMC. While we do not anticipate that 

this scenario of measurements is likely, the proposed 

amendment is both clearer and more technically correct. We 

similarly propose to amend 40 CFR 98.343(b)(2)(iii)(B) to 

clarify that moisture content is needed “If the CH4

concentration is determined on a dry basis and flow is 
53

determined on a wet basis or CH4 concentration is determined 

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

Additionally, we received numerous inquiries about how 

reporters are to measure for moisture content, and asking 

whether measurements were really necessary because no 

moisture content measurement requirements are in 40 CFR 

98.344. To clarfiy how and when reporters are to measure 

for moisture content, we are proposing to amend 40 CFR 

98.344(d) and (e) to include reference to moisture content 

monitors. Specifically, we are proposing to amend 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 proposing to amend 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.” These 

proposed amendments clarify that the moisture content is to 

be based on measurement values and not assumed moisture 

content values. We do note that moisture content 

calculated from wet and dry bulb temperature measurements 

are a suitable measure of moisture content, but that 
54

measurement of dry bulb temperature alone, assuming the gas 

is saturated with water (i.e., 100 percent relative 

humidity) is not a direct measure of moisture content, and 

is not a suitable measurement technique. 

In related amendments, we are proposing to amend 40 

CFR 98.346(i)(3) and (4) to clarify the reporting 

requirements for temperature, pressure, and moisture 

content measurements. Section 98.346(i)(4) in the 2009 

Final MRR pertained to pressure measurements, but 

inadvertently referenced “...or indication that temperature 

is incorporated into internal calculations...” We are 

proposing to amend 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. Together, the proposed 

amendments to Equation HH-4 and 40 CFR 98.344 and 98.346 

would clarify that moisture content need only be determined 

when the concentration and flow measurements are made on 

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

the moisture content must be measured. 

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

proposing to clarify the difference between “active” gas 

collection systems and “passive” gas collection systems. 

Some landfills use “passive” vent flares to control odor. 
55

In these “passive” systems, landfill gas flows naturally to 

the surface of the landfill where an opening or pipe (vent) 

is installed to allow for natural gas flow. Because of the 

low and variable flow as well as the number of passive 

vents that are present at a single landfill, requiring flow 

meters for these systems is impractical. Furthermore, 

these systems do not meet the definition of gas collection 

system in 40 CFR 98.6 because the gas is not collected to a 

single location. However, to clarify our intent to only 

require monitoring of “active” gas collection systems, we 

are proposing to amend the definition of “gas collection 

system” in 40 CFR 98.6 as described in Section II.B. of 

this preamble. However, we are interested in understanding 

the number of landfills with passive vent controls, so we 

are also proposing to add 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 proposing other 

technical corrections for subpart HH to correct 

typographical errors, to correct equations, and to provide 

minor clarifications. 
56

We are proposing the following technical corrections 

to 40 CFR 98.344(b): 

• Delete the word “install” to clarify that the gas 

composition monitors do not need to be installed to 

meet this requirement and to allow use of portable 

monitoring devices. 

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

sampling location” to clarify the 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 

of the methods specified in paragraphs (b)(1) through 

(b)(5) of this section” because the sampling location 

is previously specified and to correct spelling error. 

• In 40 CFR 98.344(b)(6)(ii)(B), delete “that is 

collected and routed to a destruction device (before 

and teatment equipment)” because the sampling location 

is previously specified. 

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

Equation HH-4” to the definition of the term CCH4 as 

follows “Methane concentration in the landfill gas 

(volume %) for use in Equation HH-4,” for clarity. 

In 40 CFR 98.344(c), we are proposing to revise 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.” The amended 

language would conform with the general provisions for 

calibration of gas flow meters and with other amendments 

indicating when moisture corrections are necessary. 
57

We are proposing 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),” to clarify the 

reporting requirement. 

• 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 

correction factor (MCF), and fraction of DOC 

dissimilated (DOCF) values used in the calculations,” 

to comport with revisions of Equation HH-1. 

• Revise 40 CFR 98.346(f)(1) 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.” This 

change would clarify the reporting requirement and 

clarify that an average oxidation fraction does not 

need to be calculated because the default oxidation 

fraction must be used. 

• 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),” to clarify 

the reporting requirement. 

• 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),” to 

clarify the reporting requirement. 

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

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

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

correct the typographical error and to eliminate the 

open-ended reporting requirement implied by the 

etcetera. 
58

We are also proposing to include additional 

definitions of terms used in the rule to help clarify the 

rule requirements. The following terms are proposed to be 

defined within 40 CFR 98.348 of subpart HH: “destruction 

device”; “solid waste”; and “working capacity.” 

We are proposing to amend Table HH-1 of 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). In these cases, reporters would 

be required to use the highest decay rate values, even 

though the small or infrequent use of recirculation would 

not significantly alter the landfill’s moisture content. 

Instead of an all or nothing approach, the proposed 

amendments require that recirculation be calculated in 

units of inches/year (effectively representing it as an 

“additional precipitation rate”). The leachate 

recirculation rate would be calculated as the total volume 

of leachate recirculated during the year divided by the 

area of the portion of the landfill containing waste. This 

leachate recirculation rate (in inches/year) would be added 

to the precipitation rate and the sum would be used to 

determine what decay rate constant is appropriate. 
59

We are also proposing to amend Table HH-1 to delete 

the default value for LO as the amended Equation HH-1 would 

no longer use that term. Finally, we are proposing to 

amend Table HH-1 to include default values for DOC and k 

(decay rate) for inert materials because this category of 

waste is needed to properly account for non-degradable 

wastes that are managed in MSW landfills. 

We are proposing to amend Table HH-2 of 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). These revisions are 

commensurate with the proposed amendments to Equation HH-2. 

Additionally, we identified an inadvertent error in the 

waste generation rates included in Table HH-2 from 1989 to 

2006, so we are correcting this error with the values for 

waste disposal rates in the proposed amendments to Table 

HH-2. Finally, we propose to add waste disposal rates for 

2007, 2008, and 2009 so that Equation HH-2 can be used for 

projecting historical disposal quantities for these years. 

We are proposing to amend Table HH-3 of subpart HH to 

delete the references to the average depth of waste within 

an area (H2, H3, H4, and H5) as these terms are not used in 

the calculation for landfill gas collection efficiency. We 

also propose to amend Table HH-3 to clarify what is 
60

considered a “final soil cover.” The description for A5 is 

proposed to read, “Area with a final soil cover of 3 feet 

or thicker of clay and/or geomembrane cover system and 

active gas collection.” In the 2009 Final MRR, A5 included 

areas with both a final soil AND a geomembrane cover 

system. The amendment is needed so the definition of area 

A5 matches the types of cover systems for which the 

efficiency value was assessed. The description for A4 is 

proposed to read, “Area with an intermediate soil cover, or 

a final soil cover not meeting the criteria for A5 below, 

and active gas collection.” This revision is needed to 

clarify what is considered an intermediate soil cover and 

to better describe the types of cover systems for which the 

efficiency value of 0.75 applies. 

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

We are proposing to amend 40 CFR 98.386(a)(5) and (6) 

to clarify that fossil-fuel products that enter the 

facility would 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. 

R. Subpart MM - Suppliers of Petroleum Products 

We are proposing to add a definition of “batch” in 40 

CFR 98.398 to clarify the crude oil reporting requirements 
61

in 40 CFR 98.396(a)(20) and to minimize administrative 

burden. We are proposing to define a batch of crude oil as 

up to a calendar month of volume from a single country of 

origin or, if refiners do not know the country of origin, 

up to a total calendar month of volume. Our intention is 

to allow refiners to use sample data on crude oil American 

Petroleum Institute (API) gravity and sulfur content that 

they or a third party currently collect as part of normal 

business practices, including sample data refiners use to 

report monthly weighted average API gravity and sulfur 

content to EIA. 

To better align the API gravity and sulfur content 

reporting requirements with normal business practices, we 

are also proposing to amend the recordkeeping requirements 

in 40 CFR 98.397 so that refiners would no longer be 

required to maintain laboratory reports, calculations and 

worksheets used in the measurement of API gravity and 

sulfur content of crude oil as long as they maintain 

sufficient records to support the information they report 

to EPA (as required by 40 CFR 98.397(a) and (b)). 

We are also proposing to amend 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. We seek comment on 
62

our proposed definition of batch in 40 CFR 98.398 and the 

associated amendments in subpart MM. 

We also seek comment on any additional changes to the 

monitoring and QA/QC requirements in 40 CFR 98.394, 

procedures for estimating missing data in 40 CFR 98.395, 

description of reporting requirements in 40 CFR 

98.396(a)(20), or records that must be retained in 40 CFR 

98.397 related to measuring API gravity and sulfur content 

of crude oil that would better align these provisions with 

normal business practices. 

We also seek comment on defining a batch of crude oil, 

alternatively, as an annual volume of a specific type of 

crude oil where types of crude oil are characterized by EIA 

crude stream code categories4 or other parameters (e.g., 

ranges of API gravity and sulfur content, commonly-used 

industry names) that refiners use to differentiate between 

types of crude oil as part of normal business practices. 

We seek comment on whether this alternative definition 

would decrease burden for reporters compared to our 

proposed definition or provide better data for purposes of 

 

4 EIA’s foreign stream code categories are listed in Appendix A of Form 

EIA-856 available at 

www.eia.doe.gov/pub/oil_gas/petroleum/survey_forms/eia856appa.pdf. 

EIA’s domestic stream code categories are listed in Form EIA-182 

available at 

www.eia.doe.gov/pub/oil_gas/petroleum/survey_forms/eia182f.pdf. 
63

understanding upstream emissions associated with the 

production of crude oil and petroleum products. We also 

seek comment on the relative benefits of using EIA’s crude 

stream categories, as opposed to other parameters that 

refiners use in the ordinary course of business, to 

distinguish between different types of crude. 

We also seek comment on limiting the crude oil data 

reporting requirements under 40 CFR 98.396(a)(20) to just 

the annual volume of each EIA crude stream code category 

(i.e., remove requirements to report API gravity, sulfur 

content, and country of origin of each batch), given that 

each category already reflects country of origin and the 

range of API gravity and sulfur content for each category 

may be sufficiently narrow. 

We are proposing to amend 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 proposing to 

amend 40 CFR 98.396(a)(5) and (6) to clarify that these 

products are not reported. 
64

We are proposing to amend the procedure in 40 CFR 

98.393(f)(1) for calculating emission factors for solid 

products when using Calculation Method 1. The amendments 

would clarify that reporters should multiply the default 

carbon share factor in column B of Table MM-1 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 proposed amendment is necessary 

because otherwise reporters would calculate the emissions 

of carbon instead of carbon dioxide. 

We are proposing to amend 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 proposing to add 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 MM-1 that resembles most closely the 

blended product (Calculation Method 1) or by sampling and 

testing the blended product (Calculation Method 2). If a 
65

reporter applies the former method, the CO2 emissions 

calculation for the blended product will reflect the CO2

content of 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. The optional method we are 

proposing today would allow 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. This amendment is being proposed in an attempt 

to increase flexibility for facilities that receive and 

supply blends, especially at refineries with co-located 

terminals. This amendment would also improve accuracy of 

the summary calculation of total refinery CO2 because it 

would ensure that the same quantities and emission factors 

are used for blend components coming in to the refinery as 

for blended products going out. We are seeking comment on 

the value of adding this new optional method and on whether 

it would be worthwhile to finalize these proposed rule 

amendments with this method included. We are seeking 

comment on the occasions in which reporters would use this 

method so that we can ensure that we have fully accounted 

for such occasions in the text. Please be specific in your 
66

comments. We also seek comment on whether the list of 

products in Table MM-1 is comprehensive of all products 

contained in blends that petroleum product suppliers 

receive or supply. We seek comment on any other 

alternative methods that would allow reporters to calculate 

CO2 emissions for product blends using information already 

collected by industry in the course of normal business or 

as part of compliance with the mandatory reporting rule. 

We are proposing that the optional method would not be 

available for a product that is biomass-based because such 

biomass-based products are subject to paragraph (h) of 40 

CFR 98.393. We seek comment on whether there would be 

value in expanding the proposed method to include biomassbased blends, and if so how the proposed method could be 

amended to allow for biomass-based blends without 

contradicting or jeopardizing the procedures in paragraph 

(h) of 40 CFR 98.393. Please be specific in your comments. 

To align the existing regulatory text with the 

proposed optional method for blends, we are proposing to 

amend paragraphs (a)(1) and (b)(1) of 40 CFR 98.393 and to 

add paragraph (d) of 40 CFR 98.396 to create new data 

reporting requirements for blends. 

For additional discussion of the current approach to 

blends in subpart MM, please see the response to comment 
67

EPA-HQ-OAR-2008-0508-0712.1, excerpt 94 in Volume 38 of 

U.S. EPA’s Response to Public Comments on the Mandatory 

Greenhouse Gas Reporting Rule: Subpart MM—Suppliers of 

Petroleum Products (EPA-HQ-OAR-2008-0508-2254). 

We are proposing to amend the calculation procedures 

in 40 CFR 98.393(h) for blended biomass-based fuels. The 

2009 Final MRR 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. To 

address this fact for refineries using Calculation Method 1 

for petroleum products or non-crude petroleum feedstocks 

that contain denatured ethanol, we are proposing to amend 

the definition of the term “%vol” to exclude denaturant in 

equations MM-8 and MM-9, respectively. 

To address this fact 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 proposing a new equation MM-10a. Proposed 

equation MM-10a would require refineries to sample the 

petroleum-based products prior to blending them with 

denatured ethanol and use the resulting emissions factor 

and the volume of the petroleum-based product to calculate 
68

emissions for the ultimate petroleum products that leave 

the refinery. Equation MM-10 requires reporters to subract 

the CO2 emissions that would result from the biomass portion 

of the blended product by multiplying the volume of the 

blended product by both the percent volume of the biomass 

portion (which for ethanol would now include the 

denaturant) and the default emission factor. This new 

equation is necessary because the default factor for 

ethanol does not account for denaturant. Using equation 

MM-10 for a blended product containing denatured ethanol 

would therefore result in inaccurate CO2 emissions because 

the emission factors for 100% ethanol and for denaturant 

are different. We are proposing to split 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 the proposed 

equation MM-10a appears in (ii) for petroleum products 

blended with denatured ethanol. We are proposing to amend 

equation MM-10 so that the definition of the term “%vol” 

excludes denaturant. 

Together, these proposed amendments would 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 
69

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 denatured ethanol that enters the 

refinery as a feedstock always leaves the refinery as a 

product and is never used on site. We are seeking comment 

on this conclusion. 

We cannot identify a situation 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 

proposing to split 40 CFR 98.393(h)(4) into paragraphs (i) 

and (ii) so that equation MM-11 remains in (i) for noncrude 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 proposing 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 proposing to amend equation 

MM-11 so that the definition of the term “%vol” excludes 

denaturant. We seek comment on our proposal to have 

refineries, importers, and exporters use Calculation Method 
70

1 in these situations and on the assumption that no 

reporter would be adversely impacted by using Calculation 

Method 1 in these situations. 

If a refinery, importer, or exporter would be 

adversely impacted by only using Calculation Method 1 in 

these situations, we seek comment on an alternative 

approach to correcting the issue of accounting for 

denaturant in products but not in denatured ethanol 

feedstock, that would allow all reporters to use 

Calculation Method 2 for products and non-crude feedstocks 

containing denatured ethanol. One alternative approach, 

which is not included in the proposed regulatory text, 

would be to amend the emission factor for ethanol to 

reflect a 2.5 percent volume of denaturant and directing 

reporters to use Equations MM-10 and MM-11, respectively. 

We seek comment on this alternative approach. 

We are proposing amendments to 40 CFR 98.396(a)(3), 

(a)(7), (b)(3), and (c)(3) to align the reporting 

requirements with the proposed amendments to account for 

denaturant in ethanol. 

We are also seeking comment on the value of editing 

Table MM-1 so that refiners must report on quantities of 

“fuel gas” rather than “still gas.” We seek comment on 

whether this would increase clarity or decrease complexity 
71

for reporters as they determine how to categorize and 

report gas products received as non-crude feedstock or 

supplied to the economy. 

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

Liquids

We are proposing to amend the definition of the term 

“Fuelh” in Equation NN-1 to clarify that the abbreviation 

“Mscf” refers to “thousand standard cubic feet” in order to 

avoid confusion on whether this abbreviation means “million 

standard cubic feet”. We are also proposing to add the 

subscript “h” to the terms for Fuel and HHV in Equation NN1. 

We are proposing to amend the definition of the term 

“EF” in Equation NN-7 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 proposing to amend Equation NN-8 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 

proposing to amend Equation NN-8 to remove the summation 

signs that were unnecessary from this equation for 

clarification purposes. We are also proposing to amend the 

definition of the term CO2i to clarify that this term 
72

includes NGLs delivered to customers or on behalf of 

customers, recognizing that some customers may not receive 

the NGLs directly. 

We are proposing to amend 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 proposing to amend 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). 

We are proposing to amend 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 proposing to amend 40 CFR 98.407(a) to remove 

the word “daily” because daily meter readings are not 

specifically required under this subpart. 

Finally, we are proposing to update the high heat 

values (HHVs) and default CO2 emission factors in Tables NN1 and NN-2 to be consistent with the emission factors in 

Tables C-1 and MM-1. 

V. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory Planning and Review
73

This action is not a "significant regulatory action" 

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

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

under the EO. 

B. Paperwork Reduction Act

This action does not impose any new information 

collection burden. These proposed amendments do not make 

any substantive changes to the reporting requirements in 

any of the subparts for which amendments are being 

proposed. In many cases, the proposed amendments to the 

reporting requirements could potentially reduce the 

reporting burden by making the reporting requirements 

conform more closely to current industry practices. 

However, the OMB has previously approved the information 

collection requirements 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. 

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)
74

The RFA generally requires an agency to prepare a 

regulatory flexibility analysis of any rule subject to 

notice and comment rulemaking requirements under the 

Administrative Procedure Act or any other statute unless 

the agency certifies that the rule will not have a 

significant economic impact on a substantial number of 

small entities. Small entities include small businesses, 

small organizations, and small governmental jurisdictions. 

For purposes of assessing the impacts of this proposed 

rule on small entities, small entity is defined as: (1) a 

small business as defined by the Small Business 

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

governmental jurisdiction that is a government of a city, 

county, town, school district or special district with a 

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

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

independently owned and operated and is not dominant in its 

field. 

After considering the economic impacts of these 

proposed rule amendments on small entities, I certify that 

this action will not have a significant economic impact on 

a substantial number of small entities. The proposed rule 

amendments will not impose any new requirement on small 

entities that are not currently required by the rules 
75

promulgated on October 30, 2009 (i.e., calculating and 

reporting annual GHG emissions). 

EPA took several steps to reduce the impact of the 

2009 Final MRR 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. 

We continue to be interested in the potential impacts 

of the proposed rule amendments on small entities and 

welcome comments on issues related to such impacts. 

D. Unfunded Mandates Reform Act (UMRA)

The UMRA seeks to protect State, local, and Tribal 

governments from the imposition of unfunded Federal 
76

mandates. In addition, the Act seeks to strengthen the 

partnership between the Federal government and State, 

local, and Tribal governments and ensure that the Federal 

government covers the costs incurred during compliance with 

Federal mandates. 

Title II of the UMRA of 1995, Public Law 104-4, 

establishes requirements for Federal agencies to assess the 

effects of their regulatory actions on State, local, and 

tribal governments and the private segment. Under section 

202 of UMRA, EPA generally must prepare a written 

statement, including a cost-benefit analysis, for proposed 

and final rules with Federal mandates that may result in 

expenditures to State, local, and Tribal governments, in 

the aggregate, or to the private segment, of $100 million 

or more in any one year. 

Before promulgating an EPA rule for which a written 

statement is needed, section 205 of UMRA generally requires 

EPA to identify and consider a reasonable number of 

regulatory alternatives and adopt the least costly, most 

cost-effective or least burdensome alternative that 

achieves the objectives of the rule. The provisions of 

section 205 do not apply when they are inconsistent with 

applicable law. Moreover, section 205 allows EPA to adopt 

an alternative other than the least costly, most cost-
77

effective or least burdensome alternative if the 

Administrator publishes with the final rule an explanation 

why that alternative was not adopted. 

Before EPA establishes any regulatory requirements 

that may significantly or uniquely affect small 

governments, including Tribal governments, it must have 

developed under section 203 of UMRA a small government 

agency plan. The plan must provide for notifying 

potentially affected small governments, enabling officials 

of affected small governments to have meaningful and timely 

input in the development of EPA regulatory proposals with 

significant Federal intergovernmental mandates, and 

informing, educating, and advising small governments on 

compliance with the regulatory requirements. 

EPA has determined that these proposed rule amendments 

do not contain a Federal mandate that may result in 

expenditures of $100 million or more for State, local, and 

tribal governments, in the aggregate, or the private sector 

in any one year. Thus, the proposed rule amendments are 

not subject to the requirements of section 202 and 205 of 

the UMRA. In addition, EPA determined that the proposed 

rule amendments contain no regulatory requirements that 

might significantly or uniquely affect small governments 

because the amendments will not impose any new requirements 
78

that are not currently required by the rules promulgated on 

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

GHG emissions), and the rule amendments would not unfairly 

apply to small governments. Therefore, this action is not 

subject to the requirements of section 203 of the UMRA. 

E. Executive Order 13132: Federalism

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 proposed rule 

amendments would relate to existing State programs, please 

see Section II of the proposal preamble for the Mandatory 

GHG Reporting Rule (74 FR 16457 to 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 

few government facilities would be affected. This 

regulation also does not limit the power of States or 
79

localities to collect GHG data and/or regulate GHG 

emissions. Thus, EO 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 the 2009 Final MRR. A summary of EPA’s 

consultations with State and local governments is provided 

in Section VIII.E of the preamble to the 2009 Final MRR (74 

FR 56260, October 30, 2009). 

In the spirit of Executive Order 13132, and consistent 

with EPA policy to promote communications between EPA and 

State and local governments, EPA specifically solicits 

comment on this proposed action from State and local 

officials. 

F. Executive Order 13175: Consultation and Coordination 

with Indian Tribal Governments

This action does not have tribal implications, as 

specified in Executive Order 13175 (65 FR 67249, November 

9, 2000). The proposed rule amendments would not result in 

any changes to the requirements of the 2009 Final MRR. 

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 
80

development of the rules promulgated on October 30, 2009. 

A summary of the EPA’s consultations with Tribal officials 

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 EO 13045 (62 F.R. 19885, April 23, 

1997) as applying only to those regulatory actions that 

concern health or safety risks, such that the analysis 

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

influence the regulation. This action is not subject to EO 

13045 because it does not establish an environmental 

standard intended to mitigate health or safety risks. 

H. Executive Order 13211: Actions that Significantly 

Affect Energy Supply, Distribution, or Use

This action is not 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 
81

would be inconsistent with applicable law or otherwise 

impractical. Voluntary consensus standards are technical 

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

sampling procedures, and business practices) that are 

developed or adopted by voluntary consensus standards 

bodies. NTTAA directs EPA to provide Congress, through 

OMB, explanations when the Agency decides not to use 

available and applicable voluntary consensus standards. 

This proposed rulemaking involves the use of one new 

voluntary consensus standard from ASTM. Specifically, EPA 

proposes to 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 the 2009 Final MRR. 

This additional voluntary concensus 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 proposed rule. 

J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and LowIncome Populations
82

Executive Order (EO) 12898 (59 FR 7629 (Feb. 16, 

1994)) establishes federal executive policy on 

environmental justice. Its main provision directs federal 

agencies, to the greatest extent practicable and permitted 

by law, to make environmental justice part of their mission 

by identifying and addressing, as appropriate, 

disproportionately high and adverse human health or 

environmental effects of their programs, policies, and 

activities on minority populations and low-income 

populations in the United States. 

EPA has determined that this proposed rule will not 

have disproportionately high and adverse human health or 

environmental effects on minority or low-income populations 

because it does not affect the level of protection provided 

to human health or the environment because it is a rule 

addressing information collection and reporting procedures. 
Mandatory Reporting of GHG --Proposed Rulemaking: Technical 

Corrections, Clarifying and Other Amendments to Certain 

Provisions of the Mandatory GHG Reporting Rule. 

Page 83 of 178 

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. 
84

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

Chapter I, of the Code of Federal Regulations is proposed 

to be 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 aftertreatment to meet 

emission standards starting with model year 2013. 
85

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 
86

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), and 

potassium carbonate (K2CO3). 

Carbonate-based mineral mass fraction means the 

following: for limestone, the mass fraction of CaCO3 in the 

limestone; for dolomite, the mass fraction of CaMg(CO3)2 in 

the dolomite; for soda ash, the mass fraction of Na2CO3 in 

the soda ash; for barium carbonate, the mass fraction of 

BaCO3 in the barium carbonate; and for potassium carbonate, 

the mass fraction of K2CO3 in the potassium carbonate. 

Carbonate-based raw material means any of the 

following materials used in the manufacture of glass: 

limestone, dolomite, soda ash, barium carbonate, and 

potassium 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 
87

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 pressure after being recovered from 

oil well (casinghead) 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 nonhydrocarbons produced from 

oil, such as sulfur and various metals. 

(3) Drip gases, and liquid hydrocarbons produced from 

tar sands, oil sands, gilsonite, and oil shale. 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. 

* * * * * 
88

Decarburization vessel means any vessel used to 

further refine molten steel to reduce the carbon content of 

the steel. This definition includes vessels used for 

argon-oxygen decarburization, vacuum degassers, vacuum 

oxygen degassers, Rheinstahl-Heraus systems, and other 

decarburization vessels. 

* * * * * 

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. Landfill gas collection 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 
89

refined or otherwise used on site, including supplemental 

fuel burned to provide heat or thermal energy. 

* * * * * 

5. Section 98.7 is amended by revising paragraph 

(a)(1) and by adding paragraph (e)(43) to read as follows: 

§98.7 What standardized methods are incorporated by 

reference into this part? 

* * * * * 

(a) * * * 

(1) Association of Fertilizer and Phosphate Chemists 

Analytical Methods Manual 10th Edition, incorporation by 

reference (IBR) approved for §98.264(a) and §98.264(b). 

* * * * * 

(e) * * * 

(43) 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. 

Subpart E—[Amended] 

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. 
90

(1) Use a site-specific emission factor and 

production data according to paragraphs (b) through (h) 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 waste gas stream 

from the nitric acid oxidation step of the process, 

referred to as the test point, according to the methods 

specified in §98.54(b) through (f). 

(2) You must conduct the performance test under 

normal process operating conditions. 
91

(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 N

∑

∗ × ∗

=

−

1

7

2

2 ,

1.14 10

(Eq. E-1) 

Where: 

EFN2O,N = Average facility-specific N2O emission factor 

for each adipic acid production unit (lb N2O 

generated/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. 
92

(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. 

(3) Calculate the destruction efficiency by 

conducting an additional performance test on the emissions 

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. 

a

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). 

Pa,N = Annual adipic acid production during which N2O 

abatement technology “N” was used (ton adipic 

acid produced). 
93

Pa = Total annual adipic acid production (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) or (g)(2) of this section for each adipic 

acid production unit and sum the unit level emissions to 

determine the emissions for the facility. 

(1) If any N2O abatement technology “N” is located 

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 

utilization factor (determined in paragraph (e) of this 

section), according to Equation E-3a of this section: 

∑

∗ ∗ − ∗

=

N EFN N PaN DFN AFN N O

1

20

2

2205

(1 ( ))

(Eq. E-3a) 

Where: 

N2O = Annual N2O mass emissions from adipic acid 

production (metric tons). 

EFN2ON = N2O emissions factor for unit(s) on which N2O 

abatement technology “N” is operating (lb N2O 

generated/ton adipic acid produced). 

PaN = Annual adipic acid produced by unit(s) for 

which N2O abatement technology “N” is operating 

(tons). 
94

DFN = Destruction efficiency of N2O abatement 

technology “N” (percent of N2O removed from air 

stream). 

AFN = Abatement utilization factor of N2O abatement 

technology “N” (fraction of annual production 

for which N2O abatement technology “N” is 

operating). 

2205 = Conversion factor (lb/metric ton). 

N = Number of different N2O abatement technologies. 

(2) If no N2O abatement technologies are located after 

your test point, you must use the emissions factor 

(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-3b of this section 

for each adipic acid production unit. 

2205

20

2

EFN Pa N O∗

= (Eq. E-3b) 

Where: 

N2O = Annual N2O mass emissions from adipic acid 

production (metric tons). 

EFN2O = N2O emissions factor (lb N2O generated/ton adipic 

acid produced). 

Pa = Annual adipic acid produced (tons). 

2205 = Conversion factor (lb/metric ton). 

(h) 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. 
95

b. Adding second and third sentences to 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 from your process. You must document the 

methods used to determine the representative point. 

* * * * * 

(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. 

* * * * * 
96

(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 and the monthly amount of adipic acid 

produced during which N2O abatementtechnology, located after 

the test point, is operating according to the methods in 

paragraphs (c)(1) or (c)(2) of this section. 

(f) You must determine the annual amount of adipic 

acid produced and the annual amount of adipic produced 

during which N2O abatement technology located after the test 

point is operating 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 paragraph (c). 

b. Revising paragraph (j) introductory text. 

c. Revising paragraph (j)(1). 
97

d. Revising paragraph (k) introductory text. 

§98.56 Data reporting requirements. 

* * * * * 

(c) Annual adipic acid production during which N2O 

abatement technology (located after the test point) is 

operating (tons). 

* * * * * 

(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. 

* * * * * 

9. Section 98.57 is amended by: 

a. Revising paragraph (c). 

b. Revising paragraph (f). 

§98.57 Records that must be retained. 
98

* * * * * 

(c) Number of facility and unit operating hours in 

calendar year. 

* * * * * 

(f) Performance test reports. 

* * * * * 

Subpart H—[Amended] 

10. Section 98.83 is amended by revising the only 

sentence 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 
99

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 by revising paragraphs 

(b), (c), (d), and (f) to read as follows: 

§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 
100

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. 

* * * * * 

(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 

measurement using the same plant instruments used for 

accounting purposes, such as weigh hoppers, truck weigh 

scales, or belt weigh feeders. 

* * * * * 
101

12. Section 98.86 is amended by reivisng paragraphs 

(b)(12) and (b)(13); and by adding paragraph (b)(15) to 

read as follows: 

§98.86 Data reporting requirements. 

(b) * * * 

(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 

section, including monthly kiln-specific clinker factors, 

if used. 

13. Section 98.87 is amended by: 

a. Revising paragraph (a) introductory text. 

b. Removing and reserving paragraphs (a)(1) and 

(a)(2). 

c. Adding paragraphs (b)(1), (b)(2), and (b)(3). 

§98.87 Records that must be retained.

(a) If a CEMS is used to measure CO2 emisions, then in 

addition to the records required by §98.3(g), you must 
102

retain under this subpart the records required for the Tier 

4 Calculation Methodology in §98.37. 

(1) [Reserved] 

(2) [Reserved] 

* * * * * 

(b) * * * 

(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 

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 of this section. 

* * * * * 
103

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 revising 

paragraphs (b), (c), (d) introductory text, (d)(1), and 

(e)(1) to read as follows: 

§98.116 Data reporting requirements.

* * * * * 

(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 
104

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.

* * * * * 

(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 conducted by a certified laboratory 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 
105

§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 revising 

paragraphs (a) introductory text, (a)(2), (b)(7), and 

(b)(9) to read as follows: 

§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 

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 
106

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 is amended by adding entries for 

“Barium carbonate” and “Potassium carbonate” to read as 

follows: 

Table N-1 of 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 

a Emission factors in units of metric tons of CO2 emitted per 

metric ton of carbonate-based raw material charged to the 

furnace. 

Subpart O—[Amended] 

20. Section 98.154 is amended by revising the first 

and second sentences of paragraph (k), revising the second 

sentence of paragraph (l) introductory text, and revising 

paragraph (o) to read as follows: 

§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 
107

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 

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 revising 

paragraphs (b)(1), (b)(3), (c), and (d); and revising 

paragraph (e) introductory text to read as follows: 

§98.156 Data reporting requirements.

* * * * * 

(b) * * * 
108

(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 

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. 
109

(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 

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.

* * * * * 
110

(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.

* * * * * 

(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) and paragraph (b) 

introductory text. 

c. In paragraph (b)(1), revising the only sentence, 

and revising the definition of “CO2” in Equation P-1. 

d. Revising the only sentence 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 
111

procedures specified in either paragraph (a) or (b) of this 

section. 

(a) Continuous Emissions Montoring 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). 

(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: 

* * * * * 
112

(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 revising the 

introductory text and paragraphs (a)(1), (b)(1), and (c) 

to read as follows: 

§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 (c) and (d): 

(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. 

* * * * * 
113

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 

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 of subpart C in 

Equations Y-2 and Y-3 of subpart Y of this part. 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 of 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: 
114

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. 

c. Revising the first sentence of paragraph (d). 

§98.173 Calculating GHG emissions.

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 
115

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.* * * 

29. Section 98.174 is amended by revising 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 
116

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.

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 revising the 

introductory text and paragraphs (c) and (e)(3); and by 

adding paragraphs (g) and (h) to read as follows: 

§98.176 Data reporting requirements.

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

each annual report must contain the information required in 
117

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 

furnace; and flare burning coke oven gas or blast furnace 

gas: 

* * * * * 

(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). 

(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. 
118

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). 

* * * * * 

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. 
119

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: 

* * * * * 
120

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) * * * * * 
121

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.* * * 
122

* * * * * 

(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 
123

calculations is required (e.g., oxide content, quantity of 

lime products, etc.). * * * 

(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. 
124

(4) Beginning and end of year inventories for 

calcined lime byproducts/wastes sold, by type. 

(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. 
125

(5) Monthly results of chemical composition analysis 

of each type of lime product produced and calcined 

byproduct/waste sold. 

(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. 
126

(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). 

(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), (a)(2)(ii), (b) 

introductory text, (b)(1), (b)(2), (c), (d) introductory 

text, and (e). 

b. Removing and reserving paragraph (f). 

c. Revising paragraph (g). 

d. Adding paragraph (i). 

§98.223 Calculating GHG emissions. 

(a) * * * 
127

(1) Use a site-specific emission factor and 

production data according to paragraphs (b) through (i) of 

this section. 

(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). 

(2) You must conduct the performance test under 

normal process operating conditions. 

* * * * * 

(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: 
128

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 generated/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 

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 
129

technology “N” for each nitric acid train “t” according to 

Equation V-2 of this section. 

a t

a 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). 

Pa t = 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) or (g)(2) of 

this section. 

(1) If nitric acid train “t” exhausts to any 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 

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: 
130

∑=

−

=

z

N

N t a t t N t N

N Ot

EF P DF AF

E

1

20 , , ,

2205

* *(1 ( * ))

2

(Eq. V-3a) 

Where: 

EN2Ot = N2O mass emissions per year for nitric acid 

train “t” (metric tons). 

EFN2Ot = Average site-specific N2O emissions factor for 

nitric acid train ”t” (lb N2O generated/ton 

acid produced, 100 percent acid basis). 

Pa t = Annual nitric acid production from the train 

“t” (ton acid produced, 100 percent acid 

basis). 

DFt,N = Destruction efficiency of N2O abatement 

technology N that is used on nitric acid train 

“t” (percent of N2O removed from air stream). 

AFt,N = Abatement utilization factor of N2O abatement 

technology “N” for nitric acid train “t” 

(fraction of annual production that N2O 

abatement technology is operating). 

2204.63 = Conversion factor (lb/metric ton). 

z = Number of N2O abatement technologies on nitric 

acid train “t”. 

(2) 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 

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 a t

N Ot

EF P

E = (Eq. V-3b) 

Where: 

EN2Ot = N2O mass emissions per year for nitric acid 

train “t” (metric tons). 
131

EFN2Ot = Average site-specific N2O emissions factor 

for nitric acid train ”t” (lb N2O 

generated/ton acid produced, 100 percent 

acid basis). 

Pa, t = 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.

(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 over the entire 

campaign. Facilities must document the methods used to 
132

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. * * * 

* * * * * 

(e) You must determine the total monthly amount of 

nitric acid produced and the monthly amount of nitric acid 

produced while N2O abatement technology (located after the 

test point) is operating from each nitric acid train 

according to the methods in paragraphs (c)(1) or (c)(2) of 

this section. 
133

(f) You must determine the annual amount of nitric 

acid produced and the annual amount of nitric acid produced 

while N2O abatement technology (located after the test 

point) is operating for each train by summing the 

respective monthly nitric acid quantities determined in 

paragraph (e) of this section. 

40. Section 98.226 is amended by revising the 

introductory text, paragraph (g), and paragraphs (m) and 

(n) introductory text to read as follows: 

§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 (o) of this section. 

* * * * * 

(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. 

* * * * * 
134

(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 for each nitric acid production facility. 

* * * * * 

Subpart Z—[Amended] 

41. 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. Conduct the 

representative bulk sampling using the appropriate industry 

consensus standard or applicable standard method in the 

Association of Fertilizer and Phosphate Chemists Analytical 

Methods Manual 10th Edition (incorporated by reference, see 

§98.7). 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 inorganic carbon content 

of each monthly grab sample of phosphate rock (consumed in 

the production of phosphoric acid) using the applicable 

standard method in the Association of Fertilizer and 
135

Phosphate Chemists Analytical Methods Manual 10th Edition 

(incorporated by reference, see §98.7). 

* * * * * 

42. Section 98.265 is amended by revising the 

second sentence of paragraph (a) to read as follows: 

§98.265 Procedures for estimating missing data.

* * * * * 

(a) * * * Alternatively, you must determine 

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. * * * 

* * * * * 

43. Section 98.266 is amended by revising the 

introductory text, paragraph (c), and paragraph (f) 

introductory text; and by adding paragraph (f)(9) to read 

as follows: 

§98.266 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 (f) of this section. 

* * * * * 
136

(c) Annual arithmetic average percent inorganic 

carbon 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. 

* * * * * 

(9) Annual process CO2 emissions from phosphoric acid 

production facility (metric tons). 

Subpart CC—[Amended] 

44. 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.* * * 

* * * * * 

45. Section 98.296 is amended by revising 

paragraphs (a)(1), (b)(3), (b)(6), and (b)(10); and by 

removing paragraphs (11)(iv) through (11)(vi) to read as 

follows: 
137

§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). 
138

(iv) CO2 mass emission rate during performance test 

(metric tons/hour). 

* * * * * 

Subpart EE—[Amended] 

46. 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. 

* * * * * 

47. 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). 

* * * * * 
139

(11) Carbon content for carbon-containing waste for 

each process line (percent by weight expressed as a decimal 

fraction). 

* * * * * 

Subpart GG—[Amended] 

48. 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). 

* * * * * 

49. 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.

* * * * * 
140

(a) If a CEMS is used to measure CO2 emissions, then 

you must report under this subpart the relevant information 

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] 
141

50. Section 98.340 is amended by revising paragraph 

(b) to read as follows: 

§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, 

dedicated construction and demolition waste landfills, or 

industrial waste landfills. 

* * * * * 

51. 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); and revising paragraph (c) introductory 

text. 
142

§98.343 Calculating GHG emissions.

(a) * * * 

(1) * * * * * 

∑ ( )

−

=

− − − − −













= × × × × × × −

1

( 1) ( )

4

12

16 T

x S

k T x k T x

CH x F G W MCF DOC DOC 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. 

* * * * * 

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 of this subpart 

(yr-1). Select the most applicable k value for 

the majority of the past 10 years (or 

operating life, whichever is shorter). 

(2) * * * For years when waste composition 

data are not available, use the bulk waste parameter values 
143

for k and DOC in Table HH-1 of this subpart for the total 

quantity of waste disposed in those years. 

(3) Beginning in the first emissions monitoring year 

(2010 or later) 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, other than 

passenger cars or light duty pickup trucks, used to haul 

waste to the landfill. 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. 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 
144

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 

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 
145

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 monitoring 

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

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. 
146

(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 generation, and fraction of generated waste 

disposed of in solid waste disposal sites found in Table 

HH-2 of 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 of this subpart (metric 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: 
147

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 

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. 
148

( ) ( )

( )

( )

( )

1,000

0.454

1atm

P

T

520 R

0.0423

100%

C

R V

N

n 1

n

n

n ∑ n

=

















× ×

°

= × × × × K MC n

(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 

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 

(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/cf at 520°R or 60°F and 1 

atm. 

(T)n = Temperature at which flow is measured for 

the measurement period (°R). 

(P)n = Pressure at which flow is measured for the 

measurement period (atm). 
149

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 

representative of the location of the gas flow meter once 

each calendar week, with 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 

once each calendar week, with at least three days between 

measurements. 
150

(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 once each calendar week, 

with at least three days between measurements. 

(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. 

* * * * * 

52. Section 98.344 is amended by: 

a. Revising paragraph (a). 

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

c. Revising paragraphs (b)(6)(ii), (b)(6)(ii)(A), and 

(b)(6)(ii)(B). 

d. Revising the definition of “CCH4” in Equation HH-9 

of paragraph (b)(6)(iii). 
151

e. Revising the second and third sentences of 

paragraph (c). 

f. Revising paragraph (d) and 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 

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 
152

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 

of the landfilll gas using either Method 25A or 25B at 40 

CFR part 60, appendix A-7 as specified in paragaph 

(b)(6)(i) of this section. 

* * * * * 

(iii)* * * * * 

CCH4 = Methane concentration in the landfill gas 

(volume %) for use in Equation HH-4. 

* * * * * 

(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. 
153

* * * * * 

(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. * * * 

53. Section 98.346 is amended by revising 

paragraphs (a), (b), (d)(1), (f), (h), (i)(1), (i)(2), 

(i)(3), (i)(4), (i)(5), and (i)(7) to read as follows: 

§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, 
154

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. 

* * * * * 

(d) * * * 
155

(1) Degradable organic carbon (DOC), methane 

correction factor (MCF), and fraction of DOC dissimilated 

(DOCF) values used in the calculations. 

* * * * * 

(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 

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°F and 1 atm). 

(2) Annual average CH4 concentration of landfill gas 

collected for destruction (percent by volume). 
156

(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 calcuations 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

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

required for Equation HH-4, 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 

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 of this subpart, the 
157

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. 

* * * * * 

54. 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 

capacities by vehicle/containter type if these are used to 

determine the annual waste quantities. 

55. 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. 

Dedicated construction and demolition landfill means a 

landfill that only receives materials generated from the 

construction or destruction of structures such as 

buildings, roads, and bridges. 
158

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. 

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 40 CFR 257.2), commercial solid wastes, or 

conditionally exempt small quantity generator wastes, is 

placed. An industrial waste landfill includes all disposal 

areas at the facility. 

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 perceont filled and/or 100 percent emptied 

for each load. 

56. Table HH-1 is amended by: 
159

a. Revising the entries for “k (precipitation <20 

inches/year and no leachate recirculation),” “k 

(precipitation 20-40 inches/year and no leachate 

recirculation),” and “k (precipitation >40 inches/year or 

for landfill areas with leachate recirculation).” 

b. Adding an entry for “DOC (bulk waste)” to follow 

the revised entry for “k (precipitation plus recirculated 

leachatea >40 inches/year).” 

c. Removing the entry for “L0 (Equivalent to DOC = 

0.2028 when MCF=1, DOCF=0.5, and F=0.5).” 

d. Adding an entry for “DOC (inerts, e.g. glass, 

plastics, metal, cement)” to follow the entry for “DOC 

(sewage sludge).” 

e. Revising the entries for “k (food waste),” “k 

(garden),” “k (paper),” “k (wood and straw),” “k 

(textiles),” “k (diapers),” and “k (sewage sludge).” 

f. Adding a new entry for “k (inerts e.g. glass, 

plastics, metal, cement).” 

g. Redesignating footnote “a” as footnote “b,” and 

revising new footnote “b.” 

h. Adding a new footnote “a.” 

Table HH-1 of Subpart HH—Emissions Factors, Oxidation 

Factors and Methods 

Factor Default value Units 

Waste model-- bulk waste option 
160

Factor Default value Units 

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 (bulk waste) 0.20 Weight fraction, wet 

basis 

* * * * * * *

DOC (inerts, e.g. 

glass, plastics, metal, 

cement) 

0.00 Weight fraction, wet 

basis 

* * * * * * *

k (food waste) 0.06 to 

0.185b

yr-1

k (garden) 0.05 to 0.10b yr-1

k (paper) 0.04 to 0.06b yr-1

k (wood and straw) 0.02 to 0.03b yr-1

k (textiles) 0.04 to 0.06b yr-1

k (diapers) 0.05 to 0.10b yr-1

k (sewage sludge) 0.06 to 

0.185b

yr-1

k (inerts e.g. glass, 

plastics, metal, 

cement) 

0.00b yr-1

* * * * * * *

a Recirculated leachate (in inches/year) is the total volume of leachate 

recirculated divided by the area of the portion of the landfill 

containing waste with appropriate unit conversions.

b

 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. 

57. Table HH-2 is amended by: 

a. Removing the entries for “1950” through “1959.” 

b. Revising the entries for “1989” through “2006.” 
161

c. Adding entries for “2007” through “2009.” 

Table HH-2 of 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 

58. Table 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 and active gas 
162

collection H5: Average depth of waste in area A5” to 

read as follows: 

Table HH-3 of 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 sold 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] 

59. Section 98.386 is amended by adding a third 

sentence to paragraphs (a)(5) and (a)(6) to read as 

follows: 

§98.386 Data reporting requirements. 

* * * * * 

(a) * * * 

(5) * * * Those products that enter the 

facility, but are not reported in (a)(1), shall not be 

reported under this paragraph. 
163

(6) * * * Those products that enter the 

facility, but are not reported in (a)(2), shall not be 

reported under this paragraph. 

* * * * * 

Subpart MM—[Amended] 

60. 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 paragraphs (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 
164

product and natural gas liquid using Equation MM-1 of this 

section. 

* * * * * 

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 of this subpart. 

* * * * * 

(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, 
165

multiply the default carbon share factor (i.e., percent 

carbon by mass) in column B of Table MM–1 of 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 Methodology 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) 
166

Where: 

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 of 

this subpart 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); 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). 
167

(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 of 

this subpart 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. 
168

(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. 

(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. 
169

(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 = [ * ] Compon i...n EFi...n ∑ Blending ent (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 = [ * ] Compon i...n EFi...n ∑ Blending ent (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). 

Blending Componenti...n = Annual volume or mass of each 

blending component that is blended (barrels or 

metric tons). 
170

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. 

61. Section 98.394 is amended by revising 

paragraphs (d)(1), (d)(3), and (d)(4) to read as follows: 

§98.394 Monitoring and QA/QC requirements.

(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. 

* * * * * 
171

(3) API gravity shall be measured using an 

appropriate standard method published by a consensus-based 

standards organization. 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. 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. 

* * * * * 

62. Section 98.396 is amended by: 

a. Revising paragraph (a)(3). 

b. Revising paragraphs (a)(5) and (a)(6) by adding a 

third sentence. 

c. Revising paragraphs (a)(7), (a)(20)(ii), 

(a)(20)(iii), (b)(3), and (c)(3). 

d. Adding a new paragraph (d). 

§98.396 Data reporting requirements. 
172

* * * * * 

(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 

section that is petroleum-based (excluding any denaturant 

that may be present in any ethanol product). 

* * * * * 

(20) * * * 
173

(ii) Weighted average API gravity of the batch at the 

point of entry at the refinery. 

(iii) Weighted average sulfur content of the batch at 

the point of entry at the refinery. 

* * * * * 

(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). 

* * * * * 

(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 non-
174

crude 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. 

(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 

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. 

63. Section 98.397 is amended by removing paragaph 

(e); and by redesignating paragraphs (f) and (g) as (e) 

and (f), respectively, to read as follows: 

§98.397 Records that must be retained.

* * * * * 
175

(e) Estimates of missing data shall be documented and 

records maintained showing the calculations. 

(f) Reporters described in this subpart shall also 

retain all records described in §98.3(g). 

64. 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 up to a calendar month of crude oil volume 

from a single country of origin or up to a calendar month 

of crude oil volume for which the country of origin is 

unknown. 

Subpart NN—[Amended] 

65. Section 98.403 is amended by: 

a. Revising the definitions of "Fuel" and “HHV” in 

Equation NN-1 of paragraph (a)(1). 

b. Revising the definition of "Fuel" 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 "EF" in Equation NN-7 

of paragraph (c)(1). 
176

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) 

* * * * * 

(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) * * * * * 
177

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). 

* * * * * 

66. 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 

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: 

* * * * * 

67. Section 98.407 is amended by revising 

paragraphs (a) and (d) to read as follows: 

§98.407 Records that must be retained.

* * * * * 
178

(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). 

* * * * * 

68. Tables NN-1 and NN-2 are amended to read as 

follows: 

Table NN-1 of 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 

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 of 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