Tuesday, 

June 15, 2010 

Part III 

Environmental 

Protection Agency 

40 CFR Parts 86 and 98 

Mandatory Reporting of Greenhouse 

Gases; Proposed Rule 

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33950 Federal Register / Vol. 75, No. 114 / Tuesday, June 15, 2010 / Proposed Rules 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Parts 86 and 98 

[EPA–HQ–OAR–2010–0109; FRL–9158–6] 

RIN 2060–A079 

Mandatory Reporting of Greenhouse 

Gases 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Proposed rule. 

SUMMARY: EPA is 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. These proposed changes 

include additional information to better 

or more fully understand compliance 

obligations, corrections to data reporting 

elements so they more closely conform 

to the information used to perform 

emission calculations and other 

corrections and amendments. EPA has 

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 July 30, 2010. 

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 June 22, 2010. If 

requested, the hearing will be 

conducted on June 30, 2010, 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 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 Web site 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 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 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/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 

Web site 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 

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: 

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Federal Register / Vol. 75, No. 114 / Tuesday, June 15, 2010 / Proposed Rules 33951 

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. 

Soda Ash Manufacturing .......... 325181 Alkalies and chlorine manufacturing facilities. 

212391 Soda ash, natural, mining and/or beneficiation. 

Titanium Dioxide Production ..... 325188 Titanium dioxide manufacturing facilities. 

Zinc Production ......................... 331419 Primary zinc refining 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. 

Suppliers of Natural Gas and 

NGLs.

221210 Natural gas distribution facilities. 

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 heavyduty 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. 

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 

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 

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 Low-Income 

Populations 

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33952 Federal Register / Vol. 75, No. 114 / Tuesday, June 15, 2010 / Proposed Rules 

1Consolidated Appropriations Act, 2008, Public 

Law 110–161, 121 Stat. 1844, 2128. 

2 74 FR 16448 (April 10, 2009) and 74 FR 56260 

(October 30, 2009). 

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. 

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 Act.1 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 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 

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 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 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 fuel-specific 

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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Federal Register / Vol. 75, No. 114 / Tuesday, June 15, 2010 / Proposed Rules 33953 

3http://www.eia.doe.gov/pub/oil_gas/petroleum/ 

survey_forms/psmdefs_2010.pdf. 

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 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 

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; 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 

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 ‘‘non-crude feedstocks’’ in 

40 CFR 98.6 to remove the phrase ‘‘as a 

feedstock’’ in order to avoid confusion 

with the definition of ‘‘feedstock.’’ 

Under subpart MM, refiners must 

calculate annual CO2 emissions that 

would result from the complete 

combustion or oxidation of each noncrude 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 

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33954 Federal Register / Vol. 75, No. 114 / Tuesday, June 15, 2010 / Proposed Rules 

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 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. 

We are also proposing to amend 

equation E–3 to accommodate N2O 

abatement technology located after the 

emission test (sampling) point, and redesignate 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 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. 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 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 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– 

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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 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 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 

HFC–23 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 

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 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 combustion-related 

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—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 argonoxygen 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 offgases 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 

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emissions must be estimated only for 

flares burning blast furnace gas or coke 

oven gas. Similarly, we are proposing to 

amend the introductory text in 40 CFR 

98.175 to specify that the missing data 

procedures in subpart Y (Petroleum 

Refineries) at 40 CFR 98.255(b) must be 

followed for flares burning coke oven 

gas or blast furnace gas. We are also 

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. 

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 

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 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 lefthand 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 Administratorapproved alternative method for 

determining N2O emissions in 40 CFR 

98.223(a)(2)(ii), 98.224(a)(3), and 

98.226(n). The alternative method is for 

determining N2O emissions rather than 

N2O concentration or an N2O emission 

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 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 

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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 

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 sitespecific 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 carboncontaining 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 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 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 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 L0. 

• 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 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 pickup trucks. Passenger vehicles and light 

duty pick-up trucks contribute only a 

small fraction of the total waste 

landfilled, but they significantly 

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contribute to the total number of 

vehicles entering and exiting the 

landfill. As 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 pickup 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 

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 

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 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 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. 

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: 

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• 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 

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.’’ 

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 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 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. 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. 

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33960 Federal Register / Vol. 75, No. 114 / Tuesday, June 15, 2010 / Proposed Rules 

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. 

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. 

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. 

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 

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 fossilfuel products that enter the facility 

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Federal Register / Vol. 75, No. 114 / Tuesday, June 15, 2010 / Proposed Rules 33961 

4EIA’s foreign stream code categories are listed in 

Appendix A of Form EIA–856 available at http:// 

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 http://www.eia.doe.gov/pub/oil_gas/ 

petroleum/survey_forms/eia182f.pdf. 

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 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 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 

categories 4 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 

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. 

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 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 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 

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33962 Federal Register / Vol. 75, No. 114 / Tuesday, June 15, 2010 / Proposed Rules 

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 biomass-based 

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 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 emissions for the 

ultimate petroleum products that leave 

the refinery. Equation MM–10 requires 

reporters to subtract 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 biomassblended product or feedstock. We have 

concluded that these amendments 

simplify reporting for reporters while 

maintaining the level of data quality and 

accuracy required by EPA for subpart 

MM because 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 non-crude 

feedstocks blended with biomass other 

than denatured ethanol while directions 

to use Calculation Method 1 appear in 

(ii) for non-crude feedstocks blended 

with denatured ethanol by refineries. 

We are also 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 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 

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 NN–1. 

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 

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this term 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 NN–1 

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 

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) 

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-forprofit 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 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 

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 

sector. 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-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 

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33964 Federal Register / Vol. 75, No. 114 / Tuesday, June 15, 2010 / Proposed Rules 

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 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 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 development of the rules 

promulgated on October 30, 2009. A 

summary of the EPA’s consultations 

with Tribal officials is provided in 

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 FR 

19885, April 23, 1997) as applying only 

to those regulatory actions that concern 

health or safety risks, such that the 

analysis required under section 5–501 of 

the EO has the potential to influence the 

regulation. This action is not subject to 

EO 13045 because it does not establish 

an environmental standard intended to 

mitigate health or safety risks. 

H. Executive Order 13211: Actions That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This action is not subject to Executive 

Order 13211 (66 FR 28355 (May 22, 

2001)), because it is not a significant 

regulatory action under Executive Order 

12866. 

I. National Technology Transfer and 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (NTTAA), Public Law No. 

104–113 (15 U.S.C. 272 note) directs 

EPA to use voluntary consensus 

standards in its regulatory activities 

unless to do so would be inconsistent 

with applicable law or otherwise 

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 

Low-Income Populations 

Executive Order (EO) 12898 (59 FR 

7629 (Feb. 16, 1994)) establishes federal 

executive policy on environmental 

justice. Its main provision directs 

federal agencies, to the greatest extent 

practicable and permitted by law, to 

make environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority 

populations and low-income 

populations in the United States. 

EPA has determined that 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. 

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: May 27, 2010. 

Lisa P. Jackson, 

Administrator. 

For the reasons set out in the 

preamble, title 40, Chapter I, of the Code 

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Federal Register / Vol. 75, No. 114 / Tuesday, June 15, 2010 / Proposed Rules 33965 

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. 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 ‘‘Argonoxygen decarburization (AOD) vessel.’’ 

b. Adding a definition for 

‘‘Decarburization vessel.’’ 

c. Revising the definitions of 

‘‘Carbonate-based mineral,’’ ‘‘Carbonatebased mineral mass fraction,’’ 

‘‘Carbonate-based raw material,’’ ‘‘Crude 

oil,’’ ‘‘Gas 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 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. 

* * * * * 

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 

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. 

(1) Use a site-specific emission factor 

and production data according to 

paragraphs (b) through (h) of this 

section. 

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33966 Federal Register / Vol. 75, No. 114 / Tuesday, June 15, 2010 / Proposed Rules 

(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. 

(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: 

EF

C Q

P

n N O,N

N O n

2

2

7

1

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). 

1.14 × 10¥7 = Conversion factor (lb/dscf-ppm 

N2O). 

Q = Volumetric flow rate of effluent gas per 

test run during the performance test 

(dscf/hr). 

P = Production rate per test run during the 

performance test (tons adipic acid 

produced/hr). 

n = Number of test runs. 

(d) If any N2O abatement technology 

‘‘N’’ is located after your test point, you 

must determine the destruction 

efficiency according to paragraphs 

(d)(1), (d)(2), or (d)(3) of this section. 

(1) Use the manufacturer’s specified 

destruction efficiency. 

(2) Estimate the destruction efficiency 

through process knowledge. Examples 

of information that could constitute 

process knowledge include calculations 

based on material balances, process 

stoichiometry, or previous test results 

provided the results are still relevant to 

the current vent stream conditions. You 

must document how process knowledge 

was used to determine the destruction 

efficiency. 

(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. 

AF =

P N

a,N

a

P

(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). 

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 O

EF P DF AF N aN N N N

2 = (Eq. E-3a) ∗ ∗− ∗ ( ) ( ) ∑ 20

1

1

2205

N

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). 

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. 

N O2 = (Eq. E-3b) EF P∗ N a 20

2205

Where: 

N2O = Annual N2O mass emissions from 

adipic acid production (metric tons). 


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Federal Register / Vol. 75, No. 114 / Tuesday, June 15, 2010 / Proposed Rules 33967 

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. 

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. 

* * * * * 

(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 abatement 

technology, 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). 

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. 

* * * * * 

(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 introductory text of 

paragraph (d)(3); and by revising the 

definitions of ‘‘rm’’, ‘‘TOCrm’’, and ‘‘M’’ 

in Equation H–5 of paragraph (d)(3) to 

read as follows: 

§ 98.83 Calculating GHG emissions. 

* * * * * 

(d) * * * 

(3) CO2 emissions from raw materials. 

Calculate CO2 emissions from raw 

materials using Equation H–5 of this 

section: 

* * * * * 

rm = The amount of raw material i consumed 

annually, tons/yr (dry basis) or the 

amount of raw kiln feed consumed 

annually, tons/yr (dry basis). 

* * * * * 

TOCrm = Organic carbon content of raw 

material i or organic carbon content of 

combined raw kiln feed(dry basis), as 

determined in § 98.84(c) or using a 

default factor of 0.2 percent of total raw 

material weight. 

M = Number of raw materials or 1 if 

calculating emissions based on 

combined raw kiln feed. 

* * * * * 

11. Section 98.84 is amended 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 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 

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33968 Federal Register / Vol. 75, No. 114 / Tuesday, June 15, 2010 / Proposed Rules 

raw kiln feed and application of a kilnspecific 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. 

* * * * * 

12. Section 98.86 is amended by 

revising 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

emissions, then in addition to the 

records required by § 98.3(g), you must 

retain under this subpart the records 

required for the Tier 4 Calculation 

Methodology in § 98.37. 

* * * * * 

(b) * * * 

(1) Documentation of monthly 

calculated kiln-specific clinker CO2

emission factor. 

(2) Documentation of quarterly 

calculated kiln-specific 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. 

* * * * * 

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 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 carbonatebased 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 § 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 quantities of carbonate-based 

raw materials or mass fraction of the 

carbonate-based minerals for any 

continuous glass melting furnace 

(months). 

19. Table N–1 to subpart N is 

amended by adding entries for ‘‘Barium 

carbonate’’ and ‘‘Potassium carbonate’’ to 

read as follows: 

TABLE N–1—TO SUBPART N—CO2

EMISSION FACTORS FOR CARBONATE-BASED RAW MATERIALS

Carbonate-Based raw material— 

mineral 

CO2

emission 

factora

* * * * * 

Barium carbonate—BaCO3 ........... 0.223 

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Federal Register / Vol. 75, No. 114 / Tuesday, June 15, 2010 / Proposed Rules 33969 

TABLE N–1—TO SUBPART N—CO2

EMISSION FACTORS FOR CARBONATE-BASED RAW MATERIALS— 

Continued 

Carbonate-Based raw material— 

mineral 

CO2

emission 

factora

Potassium carbonate—K2CO3 ...... 0.318 

aEmission factors in units of metric tons of 

CO2 emitted per metric ton of carbonatebased 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 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) * * * 

(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. 

(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 onetime and annual reports in § 98.156(b) 

through (e). 

* * * * * 

Subpart P—[Amended] 

23. Section 98.160 is amended by 

revising paragraph (c) to read as follows: 

§ 98.160 Definition of the source category. 

* * * * * 

(c) This source category includes 

merchant hydrogen production facilities 

located within another facility if they 

are not owned by, or under the direct 

control of, the other facility’s owner and 

operator. 

24. Section 98.162 is amended by 

revising paragraph (a); and by removing 

and reserving paragraph (b) to read as 

follows: 

§ 98.162 GHGs to report. 

* * * * * 

(a) CO2 emissions from each hydrogen 

production process unit. 

* * * * * 

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 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: 

* * * * * 

(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 

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33970 Federal Register / Vol. 75, No. 114 / Tuesday, June 15, 2010 / Proposed Rules 

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. 

* * * * * 

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: 

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 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 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 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. 

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: 

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§ 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. 

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: 

* * * * * 

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) * * * 

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. * * * 

* * * * * 

(c) You must determine the chemical 

composition (percent total CaO and 

percent total MgO) of each type of lime 

product that is produced and each type 

of calcined byproduct/waste sold 

according to paragraph (c)(1) or (c)(2) of 

this section. You must determine the 

chemical composition of each type of 

lime product that is produced and each 

type of calcined byproduct/waste sold 

on a monthly basis. You must determine 

the chemical composition for each type 

of calcined byproduct/waste that is not 

sold on an annual basis. 

* * * * * 

(d) You must use the analysis of 

calcium oxide and magnesium oxide 

content of each lime product that is 

produced and that is collected during 

the same month as the production data 

in monthly calculations. 

* * * * * 

36. Section 98.195 is amended by 

revising the first sentence of the 

introductory text; and by revising 

paragraph (a) to read as follows: 

§ 98.195 Procedures for estimating 

missing data. 

For the procedure in § 98.193(b)(1), a 

complete record of all measured 

parameters used in the GHG emissions 

calculations is required (e.g., oxide 

content, quantity of lime products, etc.). 

* * * 

(a) For each missing value of the 

quantity of lime produced (by lime 

type), and quantity of calcined 

byproduct/waste produced and sold, the 

substitute data value shall be the best 

available estimate based on all available 

process data or data used for accounting 

purposes. 

* * * * * 

37. Section 98.196 is revised to read 

as follows: 

§ 98.196 Data reporting requirements. 

In addition to the information 

required by § 98.3(c), each annual report 

must contain the information specified 

in paragraphs (a) or (b) of this section, 

as applicable. 

(a) If a CEMS is used to measure CO2

emissions, then you must report under 

this subpart the relevant information 

required by § 98.36 and the information 

listed in paragraphs (a)(1) through (a)(8) 

of this section. 

(1) Method used to determine the 

quantity of lime that is produced and 

sold. 

(2) Method used to determine the 

quantity of calcined lime byproduct/ 

waste sold. 

(3) Beginning and end of year 

inventories for each lime product that is 

produced, by type. 

(4) Beginning and end of year 

inventories for calcined lime 

byproducts/wastes sold, by type. 

(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). 

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(b) If a CEMS is not used to measure 

CO2 emissions, then you must report the 

information listed in paragraphs (b)(1) 

through (b)(17) of this section. 

(1) Annual CO2 process emissions 

from all kilns combined (metric tons). 

(2) Monthly emission factors for each 

lime type produced. 

(3) Monthly emission factors for each 

calcined byproduct/waste by lime type 

that is sold. 

(4) Standard method used (ASTM or 

NLA testing method) to determine 

chemical compositions of each lime 

type produced and each calcined lime 

byproduct/waste type. 

(5) Monthly results of chemical 

composition analysis of each type of 

lime product produced and calcined 

byproduct/waste sold. 

(6) Annual results of chemical 

composition analysis of each type of 

lime byproduct/waste that is not sold. 

(7) Method used to determine the 

quantity of lime produced and/or lime 

sold. 

(8) Monthly amount of lime product 

sold, by type (tons). 

(9) Method used to determine the 

quantity of calcined lime byproduct/ 

waste sold. 

(10) Monthly amount of calcined lime 

byproduct/waste sold, by type (tons). 

(11) Annual amount of calcined lime 

byproduct/waste that is not sold, by 

type (tons). 

(12) Monthly weight or mass of each 

lime type produced (tons). 

(13) Beginning and end of year 

inventories for each lime product that is 

produced. 

(14) Beginning and end of year 

inventories for calcined lime 

byproducts/wastes sold. 

(15) Annual lime production capacity 

(tons) per facility. 

(16) Number of times in the reporting 

year that missing data procedures were 

followed to measure lime production 

(months) or the chemical composition of 

lime products sold (months). 

(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) * * * 

(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: 

EF

C Q

P

n

N Ot

N O n

2

2

7

1

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). 

1.14 × 10¥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 technology ‘‘N’’ for each 

nitric acid train ‘‘t’’ according to 

Equation V–2 of this section. 

AF =

P t,N

a,t,N

a,t

P

(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: 


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E

EF P DF AF

N Ot

N t a,t t,N t,N

N

z

2

20

1

1

2205 = ∗ ∗− ∗ ( ) ( )

=

∑ (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 V–3b of 

this section: 

EN Ot 2 = (Eq. V-3b)

EF P∗ N t a,t 20

2205

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 

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 

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. 

(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. 

* * * * * 

(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 

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 


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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. 

* * * * * 

(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: 

§ 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). 

(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 carbon-containing 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). 

* * * * * 

(11) Carbon content for carboncontaining 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. 

* * * * * 

(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 carboncontaining 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] 

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. 

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f. Revising paragraphs (b)(2)(ii), 

(b)(2)(iii)(A), and (b)(2)(iii)(B); and 

revising paragraph (c) introductory text. 

§ 98.343 Calculating GHG emissions. 

(a) * * * 

(1) * * * 

G W MCF DOC DOC F e e CH x F

kT x kT x

x S

4 = × × × ×× × − ( ) ⎧

⎨

⎩

⎫

⎬

⎭

− −− − −

=

16

12

( ) () 1

T −

∑

1

( . 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 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 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 offloaded the waste; determine the 

quantity of waste received from the 

individual load as the difference 

between the measured weight in and the 

tare weight determined for that 

container/vehicle type; and determine 

the annual quantity of waste received as 

the sum of all waste loads received 

during the year. 

(ii) Determine the working capacity in 

units of mass for each type of container 

or vehicle used to haul waste to the 

landfill (e.g., using volumetric capacity 

and waste density measurements; direct 

measurement of a selected number of 

passenger vehicles and light duty pickup 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. 

(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. 

W POP WDR xxx = × (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). 

W LFC

YrData YrOpen x = ( ) − +1 (Eq. HH-3)


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Where: 

WX = Quantity of waste placed in the landfill 

in year x (metric tons, wet basis). 

LFC = Landfill capacity or, for operating 

landfills, capacity of the landfill used (or 

the total quantity of waste-in-place) at 

the end of the year prior to the year 

when waste disposal data are available 

from design drawings or engineering 

estimates (metric tons). 

YrData = Year in which the landfill last 

received waste or, for operating landfills, 

the year prior to the first reporting year 

when waste disposal data is first 

available from company records, or best 

available data. 

YrOpen = Year in which the landfill first 

received waste from company records or 

best available data. If no data are 

available for estimating YrOpen for a 

closed landfill, use 30 years as the 

default operating life of the landfill. 

(b) * * * 

(1) If you continuously monitor the 

flow rate, CH4 concentration, 

temperature, pressure, and, if necessary, 

moisture content of the landfill gas that 

is collected and 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. 

R V C R

T

P n n o

n

n = × ( ) ( ) × × × ×× ( )

% . ( )

( ) .

, KMC n 100

0 0423 520

1

0 454

 atm 1 000 1

⎛

⎝

⎜ ⎞

⎠

⎟ =

∑ ( . Eq

n

N

 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 measu rement period 

(°R). 

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

the measurement period (atm). 

0.454/1,000 = Conversion factor (metric ton/ 

lb). 

(2) If you do not continuously monitor 

according to paragraph (b)(1) of this 

section, you must determine the flow 

rate, CH4 concentration, temperature, 

pressure, and moisture content of the 

landfill gas that is collected and routed 

to a destruction device (before any 

treatment equipment) according to the 

requirements in paragraphs (b)(2)(i) 

through (b)(2)(iii) of this section and 

calculate the quantity of CH4 recovered 

for destruction using Equation HH–4 of 

this section. 

* * * * * 

(ii) Determine the CH4 concentration 

in the landfill gas that is collected and 

routed to a destruction device (before 

any treatment equipment) in a location 

near or 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. 

(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). 

e. Revising the second and third 

sentences of paragraph (c). 

f. Revising paragraph (d). 

g. Amending paragraph (e) by revising 

the first sentence. 

§ 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 

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 


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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 

paragraph (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. 

* * * * * 

(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, 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) * * * 

(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). 

(3) Monthly average temperature and 

pressure for each month at which flow 

is measured for landfill gas collected for 

destruction, or statement that 

temperature and/or pressure is 

incorporated into internal calculations 

run by the monitoring equipment. 

(4) An indication as to whether flow 

was measured on a wet or dry basis, an 

indication as to whether CH4

concentration was measured on a wet or 

dry basis, and if required for Equation 

HH–4, 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 

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/container 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. 

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 

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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 rolloff bin) used to convey wastes to the 

landfill, taking into account that the 

container may not be able to be 100 

percent filled and/or 100 percent 

emptied for each load. 

56. Table HH–1 to subpart HH is 

amended by: 

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 TO SUBPART HH—EMISSIONS FACTORS, OXIDATION FACTORS AND METHODS

Factor Default value Units 

Waste Model—Bulk Waste Option 

k (precipitation plus recirculated leachate a <20 inches/year) .............................. 0.02 ........................... yr¥1. 

k (precipitation plus recirculated leachate a 20–40 inches/year) .......................... 0.038 ......................... yr¥1. 

k (precipitation plus recirculated leachate a >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) ....................................................................................................... b 0.06 to 0.185 ........... yr¥1. 

k (garden) ............................................................................................................. b 0.05 to 0.10 ............. yr¥1. 

k (paper) ............................................................................................................... b 0.04 to 0.06 ............. yr¥1. 

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

k (textiles) ............................................................................................................. b 0.04 to 0.06 ............. yr¥1. 

k (diapers) ............................................................................................................. b 0.05 to 0.10 ............. yr¥1. 

k (sewage sludge) ................................................................................................ b 0.06 to 0.185 ........... yr¥1. 

k (inerts e.g. glass, plastics, metal, cement) ........................................................ b 0.00 ......................... 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 to subpart HH is 

amended by: 

a. Removing the entries for ‘‘1950’’ 

through ‘‘1959.’’ 

b. Revising the entries for ‘‘1989’’ 

through ‘‘2006.’’ 

c. Adding entries for ‘‘2007’’ through 

‘‘2009.’’ 

TABLE HH–2 TO SUBPART HH—U.S. 

PER CAPITA WASTE DISPOSAL RATES

Year Waste per capita 

ton/cap/yr 

* * * * * 

1989 0.83 

1990 0.82 

1991 0.76 

1992 0.74 

1993 0.76 

1994 0.75 

TABLE HH–2 TO SUBPART HH—U.S. 

PER CAPITA WASTE DISPOSAL

RATES—Continued 

Year Waste per capita 

ton/cap/yr 

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 to subpart HH–3 is 

amended by revising the entries for ‘‘A2: 

Area without active gas collection, 

regardless of cover type H2: Average 

depth of waste in area A2,’’ ‘‘A3: Area 

with daily soil cover and active gas 

collection H3: Average depth of waste in 

area A3,’’ ‘‘A4: Area with an 

intermediate soil cover and active gas 

collection H4: Average depth of waste in 

area A4,’’ and ‘‘A5: Area with a final soil 

and geomembrane cover system and 

active gas collection H5: Average depth 

of waste in area A5’’ to read as follows: 

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Federal Register / Vol. 75, No. 114 / Tuesday, June 15, 2010 / Proposed Rules 33979 

TABLE HH–3 TO SUBPART HH—LANDFILL GAS COLLECTION EFFICIENCIES

Description Landfill gas collection efficiency 

*******

A2: Area without active gas collection, regardless of cover type .................................................................................................... CE2: 0%. 

A3: Area with daily soil cover and active gas collection .................................................................................................................. CE3: 60%. 

A4: Area with an intermediate soil cover, or a final soil cover not meeting the criteria for A5 below, and active gas collection ... CE4: 75%. 

A5: Area with a final soil cover of 3 feet or thicker of clay and/or geomembrane cover system and active gas collection ........... CE5: 95%. 

*******

Subpart LL—[Amended] 

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. 

(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 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, 

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) * * * 

CO Feedstock EF Vol Eq 2 j jj j = ∗∗ % ( . 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. 

CO oduct EF oduct EF Vol Eq 2i ii im m = ∗ ( ) Pr − ∗∗ ( ) Pr % ( . MM-10)

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, 


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33980 Federal Register / Vol. 75, No. 114 / Tuesday, June 15, 2010 / Proposed Rules 

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. 

CO Product EF (Eq. MM-10a) 2i = ∗p i

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 petroleumbased portion of each biomass blended 

fuel ‘‘i’’ produced by the refiner (barrels). 

EFi = Petroleum product-specific CO2

emission factor (metric tons CO2 per 

barrel). 

(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. 

CO Feedstock EF Feedstock EF Vol Eq 2 j jj jm m = ∗ ( ) − ∗∗ ( ) % ( . MM-11)

Where: 

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. 

(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 noncrude 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. 

(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. 

CO i2 = ∗ ∑[ ] Blending Componenti...n i...n EF (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 noncrude feedstock using Equation MM–13 

of this section in place of Equation MM– 

2 of this section. 

CO i2 = ∗ ∑[ ] Blending Componenti...n i...n EF (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). 

EFi* * *n = CO 2 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 non-crude 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: 


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Federal Register / Vol. 75, No. 114 / Tuesday, June 15, 2010 / Proposed Rules 33981 

§ 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. 

* * * * * 

(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. Amending 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. 

* * * * * 

(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) * * * 

(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-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 MM–12 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. 

§ 98.397 [Amended] 

63. Section 98.397 is amended by 

removing paragaph (e); and by 

redesignating paragraphs (f) and (g) as 

(e) and (f), respectively. 

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). 

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) * * * 

CO CO CO 22 2 = −i m (Eq. NN-8)

* * * * * 


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33982 Federal Register / Vol. 75, No. 114 / Tuesday, June 15, 2010 / Proposed Rules 

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 

reporter-specific 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. 

* * * * * 

(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 endusers identified in § 98.406(b)(7). 

* * * * * 

68. Tables NN–1 and NN–2 to Subpart 

NN are amended to read as follows: 

TABLE NN–1 TO SUBPART NN—DEFAULT FACTORS FOR CALCULATION METHODOLOGY 1 OF THIS SUBPART

Fuel Default high heating value factor Default CO2 emission 

factor (kg CO2/MMBtu) 

Natural Gas ........................................................... 1.028 MMBtu/Mscf ........................................................................... 53.02 

Propane ................................................................. 3.822 MMBtu/bbl .............................................................................. 61.46 

Normal butane ....................................................... 4.242 MMBtu/bbl .............................................................................. 65.15 

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 

[FR Doc. 2010–13361 Filed 6–14–10; 8:45 am] 

BILLING CODE 6560–50–P 

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