Thursday, 

October 28, 2010 

Part II 

Environmental 

Protection Agency 

40 CFR Parts 86 and 98 

Mandatory Reporting of Greenhouse 

Gases; Final Rule 


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66434 Federal Register / Vol. 75, No. 208 / Thursday, October 28, 2010 / Rules and Regulations 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Parts 86 and 98 

[EPA–HQ–OAR–2010–0109; FRL–9213–5] 

RIN 2060–A079 

Mandatory Reporting of Greenhouse 

Gases 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Final rule. 

SUMMARY: EPA is amending specific 

provisions in the 2009 Final Mandatory 

Greenhouse Gas Reporting rule to 

correct certain technical and editorial 

errors that have been identified since 

promulgation and to clarify and update 

certain provisions that have been the 

subject of questions from reporting 

entities. These final changes include 

additional information to better or more 

fully understand compliance 

obligations, corrections to data reporting 

elements so they more closely conform 

to the information used to perform 

emission calculations, and other 

corrections and amendments. 

DATES: The final rule amendments are 

effective on November 29, 2010. The 

incorporation by reference of certain 

publications listed in the final rule 

amendments are approved by the 

director of the Federal Register as of 

November 29, 2010. 

ADDRESSES: EPA has established a 

docket under Docket ID No. EPA–HQ– 

OAR–2010–0109 for this action. All 

documents in the docket are listed on 

the http://www.regulations.gov index. 

Although listed in the index, some 

information is not publicly available, 

e.g., CBI or other information whose 

disclosure is restricted by statute. 

Certain other material, such as 

copyrighted material, is not placed on 

the Internet and will be publicly 

available only in hard copy form. 

Publicly available docket materials are 

available either electronically through 

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

copy at EPA’s Docket Center, Public 

Reading Room, EPA West Building, 

Room 3334, 1301 Constitution Ave., 

NW., Washington, DC. This Docket 

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

p.m., Monday through Friday, excluding 

legal holidays. The telephone number 

for the Public Reading Room is (202) 

566–1744, and the telephone number for 

the Air Docket is (202) 566–1742. 

FOR FURTHER GENERAL INFORMATION

CONTACT: Carole Cook, Climate Change 

Division, Office of Atmospheric 

Programs (MC–6207J), Environmental 

Protection Agency, 1200 Pennsylvania 

Ave., NW., Washington, DC 20460; 

telephone number: (202) 343–9263; fax 

number: (202) 343–2342; e-mail 

address: GHGReportingRule@epa.gov. 

For technical information and 

implementation materials, please go to 

the Greenhouse Gas Reporting Program 

Web site http://www.epa.gov/ 

climatechange/emissions/ 

ghgrulemaking.html. To submit a 

question, select Rule Help Center, 

followed by Contact Us. 

SUPPLEMENTARY INFORMATION: 

Regulated Entities. The Administrator 

determined that this action is subject to 

the provisions of Clean Air Act (CAA) 

section 307(d). See CAA section 

307(d)(1)(V) (the provisions of section 

307(d) apply to ‘‘such other actions as 

the Administrator may determine’’). 

These are final amendments to existing 

regulations. These amended regulations 

affect owners or operators of certain 

fossil fuel suppliers, direct emitters of 

greenhouse gases, and manufacturers of 

highway heavy-duty vehicles. Regulated 

categories and entities include those 

listed in Table 1 of this preamble: 

TABLE 1—EXAMPLES OF AFFECTED ENTITIES BY CATEGORY

Category NAICS Examples of affected facilities 

Adipic Acid Production ............................... 325199 Adipic acid manufacturing facilities. 

Cement Production .................................... 327310 Portland cement manufacturing plants. 

Ferroalloy Production ................................. 331112 Ferroalloys manufacturing facilities. 

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 Alkali 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 heavyVerDate Mar<15>2010 17:53 Oct 27, 2010 Jkt 223001 PO 00000 Frm 00002 Fmt 4701 Sfmt 4700 E:\FR\FM\28OCR2.SGM 28OCR2

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Federal Register / Vol. 75, No. 208 / Thursday, October 28, 2010 / Rules and Regulations 66435 

1Consolidated Appropriations Act, 2008, Public 

Law 110–161, 121 Stat. 1844, 2128. 

duty vehicles. If you have questions 

regarding the applicability of this action 

to a particular facility, consult the 

person listed in the preceding FOR

FURTHER GENERAL INFORMATION CONTACT

section. 

Judicial Review. Under section 

307(b)(1) of the Clean Air Act (CAA), 

judicial review of this final rule is 

available only by filing a petition for 

review in the U.S. Court of Appeals for 

the District of Columbia Circuit (the 

Court) by December 27, 2010. Under 

CAA section 307(d)(7)(B), only an 

objection to this final rule that was 

raised with reasonable specificity 

during the period for public comment 

can be raised during judicial review. 

Section 307(d)(7)(B) of the CAA also 

provides a mechanism for EPA to 

convene a proceeding for 

reconsideration, ‘‘[i]f the person raising 

an objection can demonstrate to EPA 

that it was impracticable to raise such 

objection within [the period for public 

comment] or if the grounds for such 

objection arose after the period for 

public comment (but within the time 

specified for judicial review) and if such 

objection is of central relevance to the 

outcome of the rule.’’ Any person 

seeking to make such a demonstration to 

us should submit a Petition for 

Reconsideration to the Office of the 

Administrator, Environmental 

Protection Agency, Room 3000, Ariel 

Rios Building, 1200 Pennsylvania Ave., 

NW., Washington, DC 20460, with a 

copy to the person listed in the 

preceding FOR FURTHER GENERAL

INFORMATION CONTACT section, and the 

Associate General Counsel for the Air 

and Radiation Law Office, Office of 

General Counsel (Mail Code 2344A), 

Environmental Protection Agency, 1200 

Pennsylvania Ave., NW., Washington, 

DC 20004. Note, under CAA section 

307(b)(2), the requirements established 

by this final rule may not be challenged 

separately in any civil or criminal 

proceedings brought by EPA to enforce 

these requirements. 

Acronyms and Abbreviations. The 

following acronyms and abbreviations 

are used in this document. 

AFPC Association of Fertilizer and 

Phosphate Chemists 

AOD argon-oxygen decarburization 

API American Petroleum Institute 

ASTM American Society for Testing and 

Materials 

C&D construction and demolition 

CAA Clean Air Act 

CaO calcium oxide 

CBI confidential business information 

CEMS continuous emission monitoring 

system 

CFR Code of Federal Regulations 

CH4 methane 

CKD cement kiln dust 

CO2 carbon dioxide 

DE destruction efficiency 

DOC degradable organic carbon 

EAF electric arc furnace 

EF emission factor 

EIA Energy Information Administration 

EPA U.S. Environmental Protection Agency 

FR Federal Register 

GHG greenhouse gas 

HHV higher heating value 

ID identification 

kg kilograms 

lb pound 

LNG liquefied natural gas 

LMPs lime manufacturing plants 

MCF Methane Correction Factor 

MgO magnesium oxide 

Mscf thousand standard cubic feet 

MSW municipal solid waste 

MSWLF municipal solid waste landfill 

N2O nitrous oxide 

NAICS North American Industry 

Classification System 

NGLs natural gas liquids 

NOX nitrogen oxides 

NTTAA National Technology Transfer and 

Advancement Act 

OMB Office of Management and Budget 

QA/QC quality assurance/quality control 

RCRA Resource Conservation and Recovery 

Act 

RFA Regulatory Flexibility Act 

SBREFA Small Business Regulatory 

Enforcement Fairness Act 

SWDS solid waste disposal site 

TSCA Toxic Substances Control Act (TSCA) 

U.S. United States 

UMRA Unfunded Mandates Reform Act of 

1995 

VOD vacuum oxygen decarburization 

Table of Contents 

I. Background 

A. How is this preamble organized? 

B. Background on This Action 

C. Legal Authority 

D. How will these amendments apply to 

2011 reports? 

II. Final Amendments and Responses to 

Public Comments 

A. Mobile Sources 

B. Subpart A—General Provisions 

C. Subpart E—Adipic Acid Production 

D. Subpart H—Cement Production 

E. Subpart K—Ferroalloy Production 

F. Subpart N—Glass Production 

G. Subpart O—HCFC–22 Production and 

HFC–23 Destruction 

H. Subpart P—Hydrogen Production 

I. Subpart Q—Iron and Steel Production 

J. Subpart S—Lime Manufacturing 

K. Subpart V—Nitric Acid Production 

L. Subpart Z—Phosphoric Acid Production 

M. Subpart CC—Soda Ash Manufacturing 

N. Subpart EE—Titanium Dioxide 

Production 

O. Subpart GG—Zinc Production 

P. Subpart HH—Municipal Solid Waste 

Landfills 

R. Subpart MM—Suppliers of Petroleum 

Products 

S. Subpart NN—Suppliers of Natural Gas 

and Natural Gas Liquids 

III. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act (RFA) 

D. Unfunded Mandates Reform Act 

(UMRA) 

E. Executive Order 13132: Federalism 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

H. Executive Order 13211: Actions That 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer and 

Advancement Act 

J. Executive Order 12898: Federal Actions 

To Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

K. Congressional Review Act 

I. Background 

A. How is this preamble organized? 

The first section of this preamble 

contains the basic background 

information about the origin of these 

rule amendments. This section also 

discusses EPA’s use of our legal 

authority under the CAA to collect data 

under the mandatory GHG reporting 

rule. 

The second section of this preamble 

describes in detail the rule changes that 

are being promulgated to correct 

technical errors, to provide clarification, 

and to address implementation issues 

identified by EPA and others. This 

section also presents a summary and 

EPA’s response to the major public 

comments submitted on the proposed 

rule amendments, and significant 

changes, if any, made since proposal in 

response to those comments. 

Finally, the last (third) section of the 

preamble discusses the various statutory 

and executive order requirements 

applicable to this final rulemaking. 

B. Background on This Action 

The final Mandatory Reporting of 

Greenhouse Gases Rule (40 CFR part 98 

or Part 98) was signed by EPA 

Administrator Lisa Jackson on 

September 22, 2009 and published in 

the Federal Register on October 30, 

2009 (74 FR 56260, October 30, 2009). 

Part 98, which became effective on 

December 29, 2009, included reporting 

of greenhouse gas (GHG) information 

from facilities and suppliers, consistent 

with the 2008 Consolidated 

Appropriations Act.1 These source 

categories capture approximately 85 

percent of U.S. GHG emissions through 

reporting by direct emitters as well as 

suppliers of fossil fuels and industrial 


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2Although there are exclusions in CAA section 

114(a)(1) regarding certain title II requirements 

applicable to manufacturers of new motor vehicles 

and motor vehicle engines, CAA section 208 

authorizes the gathering of information related to 

those areas. 

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

(October 30, 2009). 

4 75 FR 33952–33953 (June 15, 2010). 

gases and manufacturers of mobile 

sources. 

EPA published a notice proposing 

amendments to Part 98 to, among other 

things, correct certain technical and 

editorial errors that have been identified 

since promulgation and clarify or 

propose amendments to certain 

provisions that have been the subject of 

questions from reporting entities. The 

proposal was published on June 15, 

2010 (75 FR 33950). The public 

comment period for the proposed rule 

amendments ended on July 30, 2010. 

EPA did not receive any requests to 

hold a public hearing. 

In addition to the notice published on 

June 15, 2010 (75 FR 33950), EPA 

published a second proposal on August 

11, 2010 (75 FR 48744). The second 

notice proposed to correct certain 

technical and editorial errors in Part 98 

that were identified since promulgation 

and clarify or propose amendments to 

certain provisions that were the subject 

of questions from reporting entities, 

primarily to subparts not addressed in 

the June 15, 2010 proposal. The August 

11, 2010 proposal complements the 

proposal published on June 15, 2010. 

C. Legal Authority 

EPA is promulgating these rule 

amendments under its existing CAA 

authority, specifically authorities 

provided in CAA sections 114 and 208. 

As stated in the preamble to the final 

Part 98 (74 FR 56260), CAA sections 114 

and 208 provide EPA broad authority to 

require the information mandated by 

this rule because such data will inform 

and are relevant to EPA’s carrying out 

a wide variety of CAA provisions. As 

discussed in the preamble to the initial 

proposed Part 98 (74 FR 16448, April 

10, 2009) CAA section 114(a)(1) 

authorizes the Administrator to require 

emissions sources, persons subject to 

the CAA, manufacturers of process or 

control equipment, and persons whom 

the Administrator believes may have 

necessary information to monitor and 

report emissions and provide such other 

information the Administrator requests 

for the purposes of carrying out any 

provision of the CAA (except for a 

provision of title II with respect to 

manufacturers of new motor vehicles or 

new motor vehicle engines 2). Section 

208 of the CAA provides EPA with 

similar broad authority regarding the 

manufacturers of new motor vehicles or 

new motor vehicle engines, and other 

persons subject to the requirements of 

parts A and C of title II. For further 

information about EPA’s legal authority, 

see the preambles to the proposed and 

final Part 98.3

D. How will these amendments apply to 

2011 reports? 

With two exceptions, we have 

determined that it is feasible for 

reporters to implement these changes 

for the 2010 reporting year because the 

revisions primarily provide additional 

clarifications regarding the existing 

regulatory requirements, generally do 

not affect the type of information that 

must be collected and do not 

substantially affect how emissions are 

calculated. Our rationale for this 

determination is explained in the 

preamble to the proposed rule 

amendments.4

In summary, these amendments, with 

the two exceptions described below, do 

not require any additional monitoring or 

information collection above what was 

already included in Part 98. Therefore, 

we have determined that reporters can 

use the same information that they have 

been collecting for each subpart to 

calculate and report GHG emissions for 

2010 and submit reports in 2011 under 

the amended subparts. 

The first exception is for reporting 

CO2 emissions from certain types of 

decarburization vessels at iron and steel 

sources under subpart Q. EPA has 

determined, based on public comments, 

that it is necessary to allow a delay in 

reporting from certain decarburization 

vessels until the 2011 data collection 

year (and the subsequent annual GHG 

emissions reports submitted to EPA by 

March 31, 2012). The delay in 

implementation was determined to be 

necessary because although the 2009 

final rule was clear that emissions from 

argon oxygen-decarburization vessels 

were required to be reported, the 

inclusion of other types of 

decarburization vessels was not clear. A 

more detailed description of the affected 

decarburization vessels and our 

rationale is available in Section II.I of 

this preamble. 

The second exception is related to 

crude oil reporting requirements in 

subpart MM. We are providing reporters 

some flexibility in defining a batch of 

crude oil for purposes of reporting crude 

oil data for reporting year 2010. A more 

detailed description of the type of 

flexibility we are providing and our 

rationale is available in Section II.R of 

this preamble. EPA notes that crude oil 

data does not impact the CO2

calculations for 2010 or for any other 

reporting year. 

II. Final Amendments and Responses to 

Public Comments 

We are amending 40 CFR part 86 to 

appropriately incorporate the regulatory 

text into the regulations at 40 CFR 

86.1844–01. 

In 40 CFR Part 98, we are amending 

various subparts to correct errors in the 

regulatory language that were identified 

as a result of working with affected 

industries to implement the various 

subparts of Part 98. We are also 

amending certain rule provisions to 

provide greater clarity. The amendments 

to 40 CFR Part 98 include the following 

types of changes: 

• Changes to correct cross references 

within and between subparts. 

• Additional information to better or more 

fully understand compliance obligations in a 

specific provision, such as the reference to a 

standardized method that must be followed. 

• Amendments to certain equations to 

better reflect actual operating conditions. 

• Corrections to terms and definitions in 

certain equations. 

• Corrections to data reporting 

requirements so that they more closely 

conform to the information used to perform 

emission calculations. 

• Other amendments related to certain 

issues identified as a result of working with 

the reporters during rule implementation and 

outreach. 

The final amendments promulgated 

by this action reflect EPA’s 

consideration of the comments received 

on the proposal. The major public 

comments and EPA’s responses for each 

subpart are provided in this preamble. 

Our responses to additional significant 

public comments on the proposal are 

presented in a comment summary and 

response document available in Docket 

ID No. EPA–HQ–OAR–2010–0109. 

A. Mobile Sources 

1. Summary of Final Amendments and 

Major Changes Since Proposal 

Manufacturers of highway heavy-duty 

vehicles, as well as manufacturers of 

highway heavy-duty engines, are subject 

to GHG reporting requirements. EPA 

inadvertently omitted the regulatory text 

covering manufacturers of highway 

heavy-duty vehicles. We are amending 

40 CFR part 86 to correct that error by 

incorporating the appropriate language 

into the regulations at 40 CFR 86.1844– 

01. 

2. Summary of Comments and 

Responses 

EPA did not receive any comments on 

the proposed amendments to 40 CFR 


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5http://www.eia.doe.gov/pub/oil_gas/petroleum/ 

survey_forms/psmdefs_2010.pdf. 

part 86 and is finalizing the 

amendments as proposed. 

B. Subpart A—General Provisions 

1. Summary of Final Amendments and 

Major Changes Since Proposal 

We are adding and changing several 

definitions to subpart A to clarify terms 

used in other subparts of Part 98. 

Similarly, we are amending 40 CFR 98.7 

(incorporation by reference) to 

accommodate changes in the standard 

methods that are allowed by other 

subparts of Part 98. 

We are amending the following 

definitions in 40 CFR 98.6: 

• Carbonate-based mineral. 

• Carbonate-based mineral mass 

fraction. 

• Carbonate-based raw material. 

• Crude oil. 

• Decarburization vessel. 

• Gas collection system or landfill gas 

collection system. 

• Mscf. 

• Non-crude feedstocks. 

We are amending the definitions of 

‘‘carbonate-based mineral,’’ ‘‘carbonatebased mineral mass fraction,’’ and 

‘‘carbonate-based raw material’’ in order 

to include barium carbonate, potassium 

carbonate, lithium carbonate, and 

strontium carbonate, because these 

carbonates are consumed in the glass 

industry subject to subpart N. 

We are amending the definition of 

‘‘crude oil’’ in 40 CFR 98.6 so that it is 

consistent with the definition in the 

Energy Information Administration’s 

(EIA) Definitions of Petroleum Products 

and Other Terms (Revised January 

2010) 5, with one additional provision to 

accommodate the needs of this program 

to ensure complete reporting of 

petroleum products, including the 

unique circumstances that have been 

raised in comments. We are adding a 

crude oil reporting requirement in 

subpart MM (40 CFR 98.396 (a)(22)) to 

accommodate this provision. 

We are amending the definition of 

‘‘decarburization vessel’’ in 40 CFR 98.6 

to include vessels that are used to 

further refine molten steel with the 

primary intent of reducing the carbon 

content of the steel. 

We are amending the definition of 

‘‘gas collection system or landfill gas 

collection system,’’ in 40 CFR 98.6 to 

clarify that the passive vents/flares are 

not considered part of a landfill gas 

collection system for purposes of 

subpart HH, to state that such a system 

collects gas actively by means of a fan 

or similar mechanical draft equipment, 

versus collecting gas passively. Based 

on a comment received, we are also 

clarifying that a single landfill may have 

more than one gas collection system. 

We are also amending the definition 

of ‘‘Mscf’’ in 40 CFR 98.6 to indicate that 

‘‘Mscf’’ means thousand standard cubic 

feet. 

We are also amending the definition 

of ‘‘non-crude feedstocks’’ in 40 CFR 

98.6 to remove the phrase ‘‘as a 

feedstock’’ in order to avoid confusion 

with the definition of ‘‘feedstock.’’ 

Under subpart MM, refiners must 

calculate annual CO2 emissions that 

would result from the complete 

combustion or oxidation of each 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. By removing the 

term ‘‘as a feedstock’’ from the definition 

of ‘‘non-crude feedstocks’’ we are 

aligning the definition to the original 

intent of subpart MM. 

We are also incorporating by reference 

ASTM D6349–09, ‘‘Standard Test 

Method for Determination of Major and 

Minor Elements in Coal, Coke, and 

Solid Residues from Combustion of Coal 

and Coke by Inductively Coupled 

Plasma—Atomic Emission 

Spectrometry’’ for subpart N. 

Major changes since proposal are 

identified in the following list. The 

rationale for these and any other 

significant changes can be found in this 

preamble or the Response to Comments: 

Technical Corrections, Clarifying and 

Other Amendments (see EPA–HQ– 

OAR–2010–0109). 

• In the definitions of ‘‘carbonate-based 

mineral,’’ ‘‘carbonate-based mineral mass 

fraction,’’ and ‘‘carbonate-based raw 

material,’’ adding lithium carbonate and 

strontium carbonate, as well as the proposed 

additions of barium carbonate and potassium 

carbonate. 

• Expanding the proposed definition of 

crude oil to include petroleum products 

injected into a crude supply or reservoir. 

• Narrowing the definition of 

decarburization vessel to include only 

vessels for which the primary intent is 

reducing the carbon content of the steel. 

• Incorporating by reference ASTM 

D6349–09, ‘‘Standard Test Method for 

Determination of Major and Minor Elements 

in Coal, Coke, and Solid Residues from 

Combustion of Coal and Coke by Inductively 

Coupled Plasma—Atomic Emission 

Spectrometry’’ for subpart N. 

2. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. 

Several comments were received on this 

subpart. Responses to additional 

significant comments received can be 

found in Response to Comments: 

Technical Corrections, Clarifying and 

Other Amendments (see EPA–HQ– 

OAR–2010–0109). 

Comment: One commenter responded 

to EPA’s question regarding whether 

other carbonates not listed in the 

proposed definitions are consumed in 

glass production, and the commenter 

noted that they consume lithium 

carbonate and strontium carbonate. 

Response: EPA appreciates the 

clarification and has added these 

carbonates to the definitions of 

carbonate-based materials in 40 CFR 

98.6 and to Table N–1 to subpart N. 

Comment: EPA received several 

comments on our proposal to amend the 

definition of crude oil. Two commenters 

supported the proposed definition of 

crude oil because it is identical to the 

definition used for reporting to the 

Energy Information Administration 

(EIA) and it will be easier for reporters 

to calculate and report the same data for 

both agencies’ crude oil reporting 

requirements. One commenter suggested 

that EPA expand it even further by 

adding the word ‘‘nitrogen’’ to describe 

non-hydrocarbons, referencing 

atmospheric conditions rather than just 

atmospheric pressure, removing the 

requirement that hydrocarbon liquids 

must be comingled with a crude stream, 

and including natural gas processing 

plant liquids captured by gravity 

separation. Therefore, the commenter 

did not support using a definition of 

crude oil that is identical to the 

definition used by EIA. Two 

commenters submitted information 

about situations where a petroleum 

product is re-injected into a crude 

supply line or back into a reservoir. One 

of these two commenters reported that 

they inject a mixture of products, some 

of which meet the proposed definition 

of crude and some of which do not, and 

specifically requested clarification on 

how to treat such a mixture with respect 

to crude oil and petroleum product 

reporting. 

Response: In today’s final rule, EPA is 

retaining the amendatory text proposed 

for the definition of crude oil and 

making amendments beyond what was 

proposed to address the comments 

received and improve technical 

accuracy. 

EPA agrees with commenters that a 

definition of crude oil for Part 98 that 

is identical to the EIA definition makes 

it easier for refineries to comply with 

both agencies’ reporting requirements. 

However, EPA considered comments 

requesting amendments to the crude oil 

definition in an effort to ensure the 

definition is technically accurate and to 

allow for complete reporting. 


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EPA considered including natural gas 

processing plant liquids captured by 

gravity separation in the crude oil 

definition, but concluded that doing so 

would create ambiguity in the 

regulatory text. EPA has always required 

natural gas liquids (NGLs) received by 

the refinery to be reported as non-crude 

feedstock because the vast majority is 

being reported by fractionators as 

product supplied under subpart NN, 

and EPA does not want these volumes 

to be double counted across the 

industry. Because refiners would be 

unable to physically distinguish NGLs 

from gravity separation from NGLs 

reported as product by fractionators 

under subpart NN, EPA does not concur 

that such an edit is an improvement to 

the proposed definition and has not 

made the suggested change in the 

definition. 

EPA agrees with the comment that 

specifying atmospheric conditions 

(temperature and pressure), rather than 

just atmospheric pressure, is technically 

more accurate and has made this change 

in the final definition. This change 

allows for conditions under which 

liquids may drop out because of lower 

temperatures that may not have dropped 

out in warmer temperatures and 

atmospheric pressure. EPA has 

concluded that adding ‘‘nitrogen’’ as an 

example of non-hydrocarbons does not 

improve technical accuracy and is not 

necessary since it is clear that nitrogen 

is a non-hydrocarbon. Therefore, EPA 

has not made this change to the final 

definition. 

EPA considered removing the 

qualification that hydrocarbon liquids 

must be comingled with a crude stream 

to meet the crude oil definition and 

concluded that removing that 

qualification would create ambiguity. 

EPA determined that it may be difficult 

for refineries to distinguish between 

such hydrocarbon liquids (which 

commenters suggested should be treated 

as crude oil) and natural gas liquids or 

petroleum products (which EPA 

required be treated as non-crude 

feedstock) when received and to, 

therefore, determine how to comply 

with the rule. EPA has concluded that 

we cannot delete such text from the 

crude oil definition unless we 

specifically seek comment on the 

impact of such a revision to reporters. 

Therefore, such an amendment is 

outside of the scope of this rulemaking. 

Finally, EPA is expanding the 

proposed definition of crude oil to 

include petroleum products that are 

received or produced at a refinery and 

subsequently injected into a crude 

supply or reservoir by the same refinery 

owner or operator. EPA is making this 

addition because, in these situations, 

petroleum products will be comingled 

with crude oil to the point of being 

indistinguishable from crude oil. 

Whenever a refinery receives the 

comingled crude oil downstream they 

will report it as crude oil to EPA. 

Therefore, this addition is needed to 

prevent double-counting among 

reporters under subpart MM. EPA has 

concluded that the additions to the 

definition beyond what is used by EIA 

will only apply to a small minority of 

refineries that face the unique 

circumstances presented by commenters 

and that all other refineries will be able 

to report to EPA according to the same 

definition that they use to report to EIA. 

With this amendment in place, EPA 

will need data on the volume injected 

into a crude supply or reservoir from 

this small minority of refineries in order 

to conduct effective verification on the 

full set of data submitted under subpart 

MM. Therefore, we are making a 

harmonizing amendment to subpart MM 

to require reporting on the volume of 

any crude oil injected into a crude 

supply or reservoir under a new 

paragraph 40 CFR 98.396(a)(22). 

Comment: One commenter noted that 

the Phosphate Mining States Methods 

Used and Adopted by the Association of 

Fertilizer and Phosphate Chemists 

(AFPC) Manual 10th Edition—Version 

1.9 had been updated to the version 

1.92, which includes a protocol for 

collecting grab samples of phosphate 

rock to be tested for chemical 

composition. 

Response: EPA agrees that it is 

important to allow phosphoric acid 

facilities to follow the latest standard 

protocol for grab samples of phosphate 

rock. In light of this, EPA has finalized 

requirements to use an industry 

consensus standard or industry standard 

practice for collecting grab samples. As 

an example, the Association of Fertilizer 

and Phosphate Chemists (AFPC) Manual 

10th Edition—Version 1.92 and future 

versions of that manual would be an 

acceptable standard. 

C. Subpart E—Adipic Acid Production 

1. Summary of Final Amendments and 

Major Changes Since Proposal 

We are amending Equation E–1, 

Equation E–2 and Equation E–3 in 40 

CFR 98.53. First, we are amending these 

equations so that the calculation 

equations are internally consistent. 

Currently, the equations do not correctly 

address situations in which a facility 

has more than one production unit or 

process line with separate N2O control 

or abatement technology on the separate 

production units or process lines, and 

the technologies are not operated 100 

percent of the time. In these 

circumstances, the current equations 

will not provide an accurate calculation 

of N2O emissions. We are amending the 

equations so that emissions are 

calculated separately for each 

production unit or process line (or 

groups of units or lines) that has a 

separate control or abatement 

technology, and then the emissions for 

all such units or lines are summed to 

determine the overall N2O emissions for 

the facility. For consistency with these 

amendments, we are also amending 40 

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

monitoring and QA/QC, reporting, and 

recordkeeping, respectively. 

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

to address performance testing when a 

group of adipic acid production units 

share a common abatement technology 

or emission point. 

We are amending Equation E–3 of 

subpart E to accommodate N2O 

abatement technology located after the 

emission test (sampling) point and redesignating it as Equation E–3a of 

subpart E. There are three ways in 

which abatement technology can be 

employed. Equation E–3a of subpart E is 

for one N2O abatement technology. We 

are amending Equation E–3a of subpart 

E further so that the annual adipic acid 

produced by adipic acid unit ‘‘z’’ (Pz) is 

used rather than annual adipic acid 

produced by unit(s) for which N2O 

abatement technology ‘‘N’’ is operating 

(Pa,N). Also, the summation was 

removed. 

We are adding Equation E–3b of 

subpart E to accommodate multiple N2O 

abatement technologies in series and we 

are adding Equation E–3c of subpart E 

to accommodate multiple N2O 

abatement technologies in parallel. We 

are also adding a new Equation E–3d of 

subpart E for facilities that do not have 

any N2O abatement technology located 

after the test (sampling) point. 

We are adding Equation E–4 of 

subpart E to sum the emissions from 

Equations E–3a through E–3d of subpart 

E for each adipic acid production unit 

‘‘z’’. 

We are amending the language in 40 

CFR 98.54(a)(3) and 98.56(k) regarding 

the Administrator approved alternative 

method to clarify that this alternative 

method is for determining N2O 

emissions rather than N2O 

concentration. Also, we are amending 

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

and (f) to clarify the location of the test 

(sampling) point used for the 

performance test and to clarify that the 

performance test should be conducted 

when the process is operating normally. 

As promulgated, the language can be 


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misconstrued that EPA is requiring the 

facility to shut down any N2O 

abatement technology during the 

performance testing. This was not 

intended because many, if not all, of the 

N2O abatement technologies in use must 

be operated at all times that the adipic 

acid facility is operated to control 

emissions of NOX in order to comply 

with state and federal regulations 

limiting NOX emissions. The 

amendments clarify that testing can 

occur before or after N2O abatement 

technology as long as the destruction 

efficiency of the N2O abatement 

technology is properly accounted for 

and adipic acid production is quantified 

while abatement equipment is 

operating. Finally, we are clarifying 

under 40 CFR 98.57(f) that facilities 

should retain records of all data 

collected during performance tests, not 

just the calculated emission factor. This 

clarification is consistent with the 

general recordkeeping requirements in 

40 CFR 98.3(g)(2)(ii). 

Major changes since proposal are 

identified in the following list. The 

rationale for these and any other 

significant changes can be found in this 

preamble or the Response to Comments: 

Technical Corrections, Clarifying and 

Other Amendments (see EPA–HQ– 

OAR–2010–0109). 

• Language was added to 40 CFR 

98.53(b)(1) to address performance testing 

when multiple adipic acid production units 

exhaust to a common emission point. 

• Changed the emission factor in Equation 

E–1 of subpart E from EFN2O,N to EFN2O,z to 

eliminate confusion. 

• Changed the description of the emission 

factor, EFN2O,z from ‘‘Average facility-specific 

N2O emission factor for each adipic acid 

production unit (lb N2O generated/ton adipic 

acid produced)’’ to ‘‘Average facility-specific 

N2O emission factor for each adipic acid 

production unit ‘‘z’’ (lb N2O/ton adipic acid 

produced).’’ 

• Changed the terms ‘‘waste gas stream’’ 

and ‘‘air stream’’ to ‘‘vent stream’’ at 40 CFR 

98.53(b)(1) and 98.53(g)(1). 

• Edited Equation E–1 and Equation E–3a 

of subpart E to include changes above. 

• Added Equation E–3b, Equation E–3c, 

Equation E–3d and Equation E–4 of subpart 

E. 

2. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. 

Several comments were received on this 

subpart. Responses to additional 

significant comments received can be 

found in Response to Comments: 

Technical Corrections, Clarifying and 

Other Amendments (see EPA–HQ– 

OAR–2010–0109). 

Comment: One commenter raised the 

issue that there are situations where 

multiple adipic acid production units 

exhaust to a common abatement 

technology or emission point and 

should be addressed during the 

performance test. 

Response: EPA has added language at 

40 CFR 98.53(b)(1) to address 

performance testing for a group of 

adipic acid production units exhausting 

to a common abatement technology or 

emission point and for other possible 

situations that were not accurately 

addressed by the proposed Equation V– 

3a of subpart V (abatement technologies 

used in series and backup abatement 

technologies operated periodically. We 

are aware of at least one facility where 

multiple units exhaust through a 

common abatement technology. 

Comment: One commenter suggested 

that the subscript letter ‘‘N’’ in the term 

EFN2O,N used in Equation E–1 of subpart 

E be explained and changed to avoid 

confusion with the term ‘‘N’’ in 

Equations E–2 and E–3a. The 

commenter also suggested that the word 

‘‘generated’’ be struck from the 

definition of EF N2O,N in Equation E–1 of 

subpart E to reflect that the emission 

factor may now be determined either 

before or after abatement. If measured 

after abatement, EFN2O,N represents the 

controlled emission rate instead of the 

amount of N2O generated. The 

commenter suggested a similar change 

to Equations E–3a and E–3b of subpart 

E where the terms EFN2O,N and EFN2O

respectively, are used. 

Response: EPA agrees that the 

subscript letter ‘‘N’’ in the term EFN2O,N

used in Equation E–1 of subpart E could 

be confused with the term ‘‘N’’ used in 

Equations E–2 and E–3a of subpart E. 

Therefore, the subscript ‘‘N’’ has been 

changed to subscript ‘‘z’’ in Equation 

E–1 of subpart E. EPA also agrees that 

EFN2O,N represents the controlled 

emission rate instead of the amount of 

N2O generated, if the test point is located 

after the abatement technology. 

Therefore, the definition of EFN2O,z has 

been revised to be the average facilityspecific N2O emission factor for each 

adipic acid production unit ‘‘z’’, in units 

of lb NN2O/ton adipic acid produced. 

EPA also removed the word 

‘‘generated’’ in Equations E–3a and E–3b 

of subpart E for the definitions of the 

terms EFN2O,N and EFN2O, respectively. 

Comment: One commenter agreed 

with the proposed amendments to 

correctly calculate emissions in which 

an abatement technology is not operated 

100 percent of the time. The commenter 

requested that additional changes be 

made to Equation E–3a in 40 CFR 

98.53(g)(1). The commenter suggested 

the use of Pa (annual adipic acid 

produced for unit a) instead of PaN

(annual adipic acid produced by unit(s) 

for which N2O abatement technology ‘‘N’’ 

is operating), and noted that the 

summation over the range of 1 to N 

should include only the term (1– 

(DFN*AFN)), to accurately represent the 

effect of multiple abatement devices on 

each unit. 

Response: EPA agrees that annual 

adipic acid produced from unit ‘‘z’’ (Pz) 

should be used rather than annual 

adipic acid produced by unit(s) for 

which N2O abatement technology ‘‘N’’ is 

operating (Pa,N). These changes have 

been made in the final rule. 

D. Subpart H—Cement Production 

1. Summary of Final Amendments and 

Major Changes Since Proposal 

We are amending 40 CFR 98.84(b) to 

correct the most recent ASTM standard, 

to ASTM C114–09 rather than C114–07, 

for determining the weight fraction of 

magnesium oxide (MgO) and calcium 

oxide (CaO) in clinker. In addition we 

have learned through questions from 

reporters, that for some facilities it is 

more efficient to sample clinker for the 

weight fraction of total MgO and CaO as 

it exits the kiln rather than from bulk 

storage. Some facilities do perform this 

analysis on clinker on a daily basis. We 

are amending the rule to allow facilities 

the option to determine a monthly value 

based on the arithmetic average of the 

daily samples. 

Through reporters we have also 

learned that facilities use direct 

measurement in conjunction with other 

factors (e.g., kiln feed) to determine 

clinker production. These procedures 

are verified periodically for accuracy. 

We are amending 40 CFR 98.84(d) to 

allow facilities to use these existing 

procedures for measuring clinker 

produced and verify those on a monthly 

basis. Facilities are already required to 

measure clinker on a monthly basis. 

Concurrent with this change, we are 

amending 40 CFR 98.86(b) so that 

facilities that do not estimate combined 

process and combustion emissions 

using continuous emission monitoring 

systems (CEMS) will be required to 

report the kiln specific feed-to-kiln 

ratios used to calculate clinker 

produced for EPA verification of 

emissions associated with clinker 

production. For consistency, we are 

clarifying 40 CFR 98.84(e) to allow 

similar flexibility in determination of 

cement kiln dust produced. 

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 


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kiln feed depending on the existing 

sampling methods and raw material 

storage procedures at the facility. We are 

amending the calculation and 

monitoring procedures in 40 CFR 

98.83(d)(3) and 98.84(c) to allow 

facilities the option to use either 

sampling procedure for estimating 

carbon dioxide (CO2) emissions from 

raw materials. 

We are also correcting and clarifying 

the recordkeeping requirements under 

40 CFR 98.87(a) and (b) for facilities 

with CEMS and for facilities without 

CEMS. In Part 98, the recordkeeping 

requirements listed under 40 CFR 

98.87(a)(1) and (a)(2) should have been 

listed under 40 CFR 98.87(b). Facilities 

using CEMS to estimate combined 

process and combustion CO2 emissions 

from kilns do not need to calculate 

process emissions using the clinker 

based emissions methodology provided 

in Subpart H and, therefore, would not 

have the relevant records requested in 

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

Major changes since proposal are 

identified in the following list. The 

rationale for these and any other 

significant changes can be found in this 

preamble or the Response to Comments: 

Technical Corrections, Clarifying and 

Other Amendments document (see 

EPA–HQ–OAR–2010–0109). 

• Clarifying the cement kiln dust (CKD) 

monitoring requirements in 40 CFR 98.84(e); 

• Changing cement production reporting 

requirements under 40 CFR 98.86 to require 

annual, facility-wide cement production 

instead of monthly, kiln-specific cement 

production; and 

2. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. 

Several comments were received on this 

subpart. Responses to additional 

significant comments received can be 

found in Response to Comments: 

Technical Corrections, Clarifying and 

Other Amendments document (see 

EPA–HQ–OAR–2010–0109). 

Comment: One commenter expressed 

concern that the monthly verification of 

the feed-to-clinker ratio, required under 

40 CFR 98.94(d), is unduly burdensome. 

The commenter suggested that EPA 

change subpart H to require quarterly 

verification instead of monthly. 

Response: Because subpart H requires 

cement manufacturers to report clinker 

production on a monthly basis, we are 

requiring facilities that estimate clinker 

production using a feed-to-clinker ratio 

to verify the accuracy of that ratio also 

on a monthly basis. We provided 

cement manufacturers the option to use 

a feed-to-clinker ratio instead of direct 

clinker measurement to provide 

flexibility and consistency with current 

industry practices. We note the 

commenter’s concern regarding the 

burden of monthly verification. 

However, other industry comments 

generally support this requirement. 

Comment: One commenter stated that 

the CKD measurement requirements 

under 40 CFR 98.84(e) should be revised 

to be consistent with the clinker 

measurement requirements under 40 

CFR 98.84(d). Specifically, 40 CFR 

98.84(d) allows facilities to determine 

monthly clinker quantities by either 

reconciling weigh hopper or belt weigh 

feeder measurements against inventory 

measurements, or by direct weight 

measurement of raw feed and applying 

a feed-to-clinker ratio. Meanwhile, 40 

CFR 98.84(e) requires facilities to 

determine quarterly CKD quantities by 

direct weight measurement. The 

commenter points out that the CKD 

quantity has a lesser impact on CO2

emission calculations than the clinker 

quantity. Therefore, the rule should not 

have more stringent measurement 

requirements for CKD than for clinker. 

The commenter also states that direct 

weight measurement devices should not 

be required to be installed if they are 

currently not being utilized at the 

facility, and requests that facilities be 

permitted to use the same methods 

currently in place for accounting 

purposes to determine the quantity of 

CKD not recycled to the kiln. 

Response: The rule currently allows 

for the type of flexibility that the 

commenter is requesting. The rule lists 

direct weight measurement as an 

example technique that may be used; 

however, the examples provided in the 

rule are not an exhaustive list. Facilities 

should determine the quantity of CKD 

not recycled to the kiln for each kiln 

using the same plant techniques used 

for accounting purposes. We have 

revised the language in 40 CFR 98.84(e) 

to clarify this flexibility. 

Comment: Two commenters noted 

that reporting requirements in 40 CFR 

98.86(a)(2) and 98.86(b)(3) require 

cement manufacturers to report monthly 

cement production from each kiln at the 

facility. The commenters pointed out 

that cement kilns produce clinker—not 

cement. The clinker from each cement 

kiln is subsequently sent to a mill and 

pulverized into a fine powder, and 

mixed with other ingredients to produce 

cement. Plants that operate multiple 

kilns may combine the clinker from all 

kilns and store the combined clinker 

before feeding it to the cement mill. 

Because of the variability of the amount 

of clinker produced by different kilns, 

and the varying methods of storage, the 

commenters proposed that EPA require 

cement manufacturers to report the total 

quantity of cement produced by the 

facility on an annual rather than 

monthly, kiln-specific basis. 

Response: EPA agrees with the 

commenter that the requirements in 40 

CFR 98.86(a)(2) and 98.86(b)(3) are 

inconsistent with cement plant 

manufacturing practices, and should not 

be required on a kiln-specific basis. In 

addition, we agree that due to the 

variations in storage time between 

clinker production and cement 

production, cement production data are 

not needed on a monthly basis. This 

reporting requirement was added for 

verification of reported emissions, not 

calculating emissions. Therefore, we 

have revised the rule to require facilities 

to report cement production on an 

annual, facility-wide basis. 

E. Subpart K—Ferroalloy Production 

1. Summary of Final Amendments and 

Major Changes Since Proposal 

We are amending 40 CFR 98.112(a) to 

be consistent with the requirement 

described in 40 CFR 98.113(d) to 

calculate methane (CH4) emissions from 

an electric arc furnace (EAF) used for 

the production of all ferroalloys for 

which an applicable CH4 emission 

factor is provided in the rule. These 

alloys and the associated CH4 emission 

factors are listed in Table K–1 to subpart 

K. Subpart K in Part 98 contained 

calculation and reporting procedures for 

quantifying process CH4 emissions from 

all ferroalloys listed in Table K–1 to 

subpart K, but CH4 was inadvertently 

not included in the GHGs to Report 

section. 

We are also amending the 

introductory language for 40 CFR 98.113 

to clarify the applicability of the 

procedures for calculating CO2 and CH4

emissions in that section. Finally, we 

are amending the language in 40 CFR 

98.116 to clarify that the data reporting 

requirements in 40 CFR 98.116(b) are for 

each EAF and those in 40 CFR 

98.116(d)(1) and (e)(1) are for any 

ferroalloy product identified in 40 CFR 

98.110. We are also amending 40 CFR 

98.116(d) to correct an incorrect crossreference to 40 CFR 98.36. 

2. Summary of Comments and 

Responses 

EPA did not receive any comments on 

the proposed amendments to subpart K 

and is finalizing the amendments to this 

subpart as proposed. 


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F. Subpart N—Glass Production 

1. Summary of Final Amendments and 

Major Changes Since Proposal 

We are amending subpart N to add 

CO2 emission factors to Table N–1 to 

subpart N for barium carbonate, 

potassium carbonate, lithium carbonate, 

and strontium carbonate. These raw 

materials were not included in Part 98, 

but EPA has since learned that they are 

also used by the glass industry. EPA is 

also amending 40 CFR 98.144(b) to 

allow for an additional method for 

determining the carbonate mineral mass 

fraction of raw materials used in glass 

production. Specifically, in addition to 

ASTM D3682–01, reporters can also use 

ASTM D6349–09, ‘‘Standard Test 

Method for Determination of Major and 

Minor Elements in Coal, Coke, and 

Solid Residues from Combustion of Coal 

and Coke by Inductively Coupled 

Plasma—Atomic Emission 

Spectrometry.’’ We are also amending 

the introductory language to 40 CFR 

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

in 40 CFR 98.146(a)(2) that reporting of 

glass production is by furnace and from 

all furnaces combined, consistent with 

the calculation methods. We are 

amending 40 CFR 98.146(b)(7) and (9) to 

correct typographical errors. 

Major changes since proposal are 

identified in the following list. The 

rationale for these changes can be found 

in this preamble. 

• Added an emission factor for lithium 

carbonate. 

• Added an emission factor for strontium 

carbonate. 

• Removed the requirement for analysis by 

an ‘‘independent certified laboratory.’’ When 

the final subpart N was published on October 

30, 2009, EPA agreed with commenters that 

analyses do not have to be performed by an 

independent certified laboratory, but this 

language inadvertently remained in subpart 

N. 

2. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. One 

comment letter was received on this 

subpart. 

Comment: One commenter asked that 

emission factors for lithium carbonate 

and strontium carbonate be added to 

subpart N, in addition to those being 

added for barium carbonate and 

potassium carbonate. 

Response: EPA has added these two 

compounds to the final subpart N. EPA 

was not previously aware of use of these 

carbonates in glass production in the 

United States during the initial proposal 

of the rule. While less common, these 

carbonates are used in glass production 

to add different properties to glass 

products and EPA therefore agrees that 

these emission factors should be 

included in the final rule. 

G. Subpart O—HCFC–22 Production 

and HFC–23 Destruction 

1. Summary of Final Amendments and 

Major Changes Since Proposal 

We are amending 40 CFR 98.154(k), 

the requirement to monitor HFC–23 

emitted from process vents, to refer to 

Equation O–7 of subpart O rather than 

Equation O–6 of subpart O. In 40 CFR 

98.154(k), (l), and (o) and in 40 CFR 

98.156(b), we are amending the 

language so that the term ‘‘destruction 

device’’ is used rather than the narrower 

term ‘‘thermal oxidizer.’’ 

We are amending the reporting 

requirements in 40 CFR 98.156(c) and 

(d) to clarify that only facilities that are 

required to recalculate the destruction 

efficiency of their destruction device 

under 40 CFR 98.154(l) must report the 

flow rate of HFC–23 being fed into the 

destruction device, the flow rate at the 

outlet of the destruction device, and the 

emission rate of the device. In addition, 

such facilities will be required to report 

the newly calculated DE of the device, 

the HFC–23 concentration measurement 

used in the DE calculation, and whether 

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

the calculation. Under these two 

paragraphs, other HFC–23 destruction 

facilities will be required to report only 

the results of their annual measurement 

of the HFC–23 concentration at the 

outlet of the destruction device. 

We are amending the reporting 

requirements in 40 CFR 98.156(e) to 

clarify that the one-time report for HFC– 

23 destruction facilities is due by March 

31, 2011 or within 60 days of 

commencing HFC–23 destruction. The 

amendment was necessary because it 

was not clear when the one-time report 

must be submitted. The amendment will 

make the due date in 40 CFR 98.156(e) 

consistent with the due date for a 

similar report required in Subpart OO. 

In general, these amendments to the 

reporting requirements for HFC–23 

destruction facilities make them 

consistent with the monitoring 

requirements for these facilities. The 

due dates for the one-time report are 

consistent with those elsewhere in Part 

98 for the source categories that are 

required to begin monitoring in 2010. 

2. Summary of Comments and 

Responses 

EPA did not receive any comments on 

the proposed amendments to subpart O 

and is finalizing the amendments to this 

subpart as proposed. 

H. Subpart P—Hydrogen Production 

1. Summary of Final Amendments and 

Major Changes Since Proposal 

We are amending the definition of the 

source category in 40 CFR 98.160(c) to 

clarify that hydrogen production 

facilities located within other facilities 

are also included in the source category 

if they are not owned by, or under the 

direct control of, the other facility’s 

owner and operator. This clarification 

was necessary to correct a 

misunderstanding that the original rule 

text limited the source universe to 

hydrogen production facilities located 

within petroleum refineries. 

Broadly, we are amending subpart P 

to remove several references to 

‘‘process’’ CO2 emissions. EPA received 

information from industry indicating 

that the use of the term ‘‘process’’ in the 

context of calculating and reporting CO2

emissions resulted in confusion in 

differentiating between process and 

combustion emissions. We are clarifying 

the text in the rule by removing 

references to the term ‘‘process’’ from the 

rule language. 

We are removing the requirements in 

40 CFR 98.162(b) for owners or 

operators to report CO2, CH4 and N2O 

combustion emissions from each 

hydrogen production process unit using 

the emissions calculation methods in 

subpart C. This provision results in 

double counting of 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 will still be reported under 40 

CFR 98.162(a) using the procedures in 

40 CFR 98.163(a) or 98.163(b). 

We are also amending language 

describing the calculation of GHG 

emissions from gaseous, liquid and 

solid fuels and feedstocks in 40 CFR 

98.163. The clarified language specifies 

that each gaseous, liquid or solid fuel 

and feedstock will need to be calculated 

based on its respective equations 

detailed in the rule language. This 

removes the concern that the language 

was unclear as to which fuel and 

feedstock stream should be used to 

calculate CO2 emissions. 

Lastly, we are amending 40 CFR 

98.166(c) to strike ‘‘quarterly’’ and ‘‘kg’’ 

(kilogram). Some facilities subject to 

subpart P may also be subject to subpart 

PP—Suppliers of Carbon Dioxide. 

Quarterly reporting of CO2 quantities (in 

kilograms) was not consistent with 

subpart PP. 


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2. Summary of Comments and 

Responses 

All comments received on the 

proposed amendments to subpart P 

were supportive and EPA is finalizing 

the amendments to this subpart as 

proposed. 

I. Subpart Q—Iron and Steel Production 

1. Summary of Final Amendments and 

Major Changes Since Proposal 

We are amending the subpart Q 

requirements regarding emissions from 

flares to clarify the requirements and 

correct certain deficiencies in the rule 

pertaining to flares burning off-gases 

from argon-oxygen decarburization 

(AOD) and other decarburization 

processes. Section 98.172(b) of Part 98 

required reporting of CO2 emissions 

from flares using procedures from 

subpart Y (Petroleum Refineries), 

without distinguishing flares burning 

off-gases from AOD or other 

decarburization processes from other 

types of flares. 

The referenced equations in subpart Y 

and the further instructions in 40 CFR 

98.172(b) are applicable to estimating 

emissions from burning coke oven gas 

or blast furnace gas, but are not 

applicable for estimating emissions from 

flares burning the off-gases from AOD or 

other decarburization processes. We are, 

therefore, amending the language in 40 

CFR 98.172(b) to clarify that for subpart 

Q facilities, flare emissions must be 

estimated for flares burning blast 

furnace gas or coke oven gas. Similarly, 

we are amending the introductory text 

in 40 CFR 98.175 to specify that the 

missing data procedures in subpart Y 

(Petroleum Refineries) at 40 CFR 

98.255(b) must be followed for flares 

burning coke oven gas or blast furnace 

gas. We are also amending the 

introductory text for the data reporting 

requirements in 40 CFR 98.176 to 

include flares burning coke oven gas or 

blast furnace gas. 

Subpart Q in Part 98 also referenced 

incorrect equations from subpart Y. We 

are amending and correcting the 

references in 40 CFR 98.172(b) to the 

subpart Y flare equations. Equations Y– 

2 and Y–3 of subpart Y are the correct 

equations; the promulgated subpart Q of 

subpart Q incorrectly referenced 

Equation Y–1 of subpart Y. 

We are amending the reporting 

requirements in 40 CFR 98.176(e)(3) to 

clarify that fuel consumption needs to 

be reported separately for each type of 

fuel and other process input and output 

material. We are also adding paragraphs 

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

(g) requires facilities to report the 

annual amount of coal charged to coke 

ovens because it is used to estimate CO2

emissions from coke pushing. Paragraph 

(h) incorporates the same reporting 

requirements specified in 40 CFR 

98.256(e) of subpart Y (Petroleum 

Refineries) for flares burning coke oven 

gas or blast furnace gas. 

We are amending the recordkeeping 

requirements in 40 CFR 98.177(d) to 

clarify the units and processes for which 

annual operating hours need to be 

recorded. 

We are also amending the 

requirements in the promulgated rule to 

estimate GHG emissions from AOD 

vessels to clarify that they also apply to 

any other type of vessel used with the 

primary intent of removing carbon from 

molten steel (decarburization), such as 

vacuum oxygen decarburization. 

Because of the clarification noted above 

to include all types of decarburization 

vessels used primarily to remove 

carbon, we are replacing the term 

‘‘argon-oxygen decarburization vessels’’ 

with the term ‘‘decarburization vessels’’ 

throughout subpart Q and replacing the 

definition of ‘‘argon-oxygen 

decarburization vessels’’ with a 

definition for ‘‘decarburization vessels’’ 

in order to maintain reporting of the 

CO2 emissions from these vessels. 

In response to comments, we are 

clarifying the definition of 

‘‘decarburization vessels’’ to include 

only those decarburization vessels, such 

as AOD and vacuum oxygen 

decarburization vessels, used with the 

primary intent of removing carbon from 

the steel. We are also delaying the 

reporting of GHG emissions from 

decarburization vessels that are not 

AOD vessels until reports submitted in 

2012, instead of requiring reporting with 

the first reports submitted to EPA in 

March 2011. 

Major changes since proposal are 

identified in the following list. The 

rationale for these and any other 

significant changes can be found in this 

preamble or the Response to Comments: 

Technical Corrections, Clarifying and 

Other Amendments document (see 

EPA–HQ–OAR–2010–0109). 

• Clarifying the definition of 

‘‘decarburization vessels’’ to include only 

those decarburization vessels used with the 

primary intent of removing carbon from the 

steel. 

• Delaying the reporting of GHG emissions 

from decarburization vessels that are not 

AOD vessels until reports submitted in 2012. 

2. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. 

Several comments were received on this 

subpart. Responses to additional 

significant comments received can be 

found in Response to Comments: 

Technical Corrections, Clarifying and 

Other Amendments document (see 

EPA–HQ–OAR–2010–0109). 

Comment: We received three 

comments on our proposal to clarify the 

definition of decarburization vessels to 

include all decarburization vessels 

rather than just argon-oxygen 

decarburization (AOD). Two 

commenters noted that the proposal was 

not merely a technical correction or 

clarification, but was instead a 

substantive change to subpart Q as 

promulgated. According to the 

commenters, the new definition of 

decarburization vessel, which includes 

a list of the covered processes and the 

phrase ‘‘or other decarburization 

vessels,’’ was too broad and inclusive. 

The commenters noted that most steel 

plants, whether integrated or electric arc 

furnace producers, employ several 

different kinds of refining processes to 

improve the quality of the steel 

produced, and some of these refining 

processes, such as AODs, are primarily 

intended to reduce carbon. However, 

the commenters stated that other 

processes, such as vacuum degassing, 

electro-slag remelting, and vacuum-arc 

remelting, are primarily intended to 

reduce dissolved gases such as 

hydrogen, nitrogen, and oxygen in the 

molten steel, and carbon reduction is 

only incidental. According to the 

commenters, making these processes 

subject to subpart Q would require 

facilities to make numerous adjustments 

to their monitoring plans and conduct 

additional sampling. For these reasons, 

the commenters believe that the 

proposed amendment would add 

significant new requirements and 

represent a substantive change rather 

than being merely a clarification. One 

commenter argued that the time and 

effort to verify GHG emissions from 

vacuum degassing would be 

burdensome, estimating that it would 

increase the resources needed to comply 

with subpart Q by 50 percent. The 

commenter stated that the added burden 

of data collection, measurements, 

recordkeeping, and reporting of these 

emissions is not justified by the 

addition of vacuum degassing and other 

refining operations to the reporting 

requirements. 

Two of the commenters estimated that 

the additional processes included in the 

proposed amendment contribute 

‘‘substantially less than 1 percent’’ of the 

emissions from the sector. Another 

commenter estimated they contributed 

only 0.02 percent of the emissions. The 

same commenter argued that because 

these emissions are relatively 


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insignificant and would be extremely 

difficult to quantify for reporting 

purposes, they should continue to be 

excluded from reporting obligations. 

The commenter also rejected the 

rationale that emissions from all 

decarburization vessels should be 

reported because EPA is also proposing 

to limit reporting of emissions from 

flares to those burning coke oven gas or 

blast furnace gas only (an amendment 

that the commenter supports), which 

would obviate reporting of vacuum 

degasser flare emissions. The 

commenter estimated that the emissions 

are so low they would be difficult to 

detect, and measuring such emissions 

through either the carbon-mass balance 

approach or a site-specific emission 

factor would be burdensome and 

potentially infeasible. The commenter 

concluded that EPA has not provided a 

rational basis for inclusion of 

decarburization vessels within the GHG 

Reporting Program. 

Two commenters recommended that 

if EPA proceeds by adding a definition 

for ‘‘decarburization vessel,’’ the 

definition should be revised. One 

commenter suggested that the definition 

be clarified such that it includes only 

vessels for which the primary purpose 

is decarburization. The other 

commenter asked that it be revised to 

read ‘‘any vessel used to further refine 

molten steel with the primary intent of 

reducing carbon content of the steel that 

also requires flaring the off-gas to 

oxidize CO to CO2.’’ 

All three commenters stated that if 

EPA chooses to include all 

decarburization vessels as proposed, 

they should not be included in the 

reports submitted to EPA in 2011. Two 

commenters explained that making this 

change retroactive to data collection in 

2010 is untenable because companies 

were obligated to develop 

comprehensive GHG Monitoring Plans 

in early 2010 and to begin 

recordkeeping in January 2010 in order 

to be able to report for the entire 2010 

reporting year by March 2011. 

One commenter stated that by 

expanding the decarburization vessel 

definition in Subpart Q to include 

vacuum degassing and other refining 

operations beyond AODs, facilities with 

these operations will need to make 

adjustments to their monitoring plans, 

conduct additional sampling of inputs 

and outputs for these operations, make 

programmatic modifications to tracking 

software, and re-train employees. The 

commenter claimed that it will be 

impossible to collect the necessary 

samples of steel and dust or sludge and 

perform analyses representative of the 

months that have elapsed since the 

beginning of 2010 in order to perform a 

mass balance, and it is also unrealistic 

to expect companies to consider the 

option of establishing a site-specific 

emission factor for these units because 

of all of activities that would be 

required to perform testing. The 

commenter recommended that EPA 

follow the course set in its July 12, 2010 

final rule notice adding four new source 

categories to Part 98 (75 FR 39735). The 

commenter said that EPA recognized in 

that notice that it would be unrealistic 

to require those operations to report 

emissions for 2010 and made these new 

rules effective with the data collection 

in 2011. 

Two commenters recommended that 

if EPA proceeds with the proposed 

changes, those requirements should be 

effective no sooner than 2011 and 

should be reportable in March 2012. 

One commenter argued that by 

amending a rule to include data 

acquisition and management after a 

reporting period has already begun is 

arbitrary and capricious and will 

significantly add to the burden the 

regulated community faces when 

attempting to collect meaningful data. 

The commenter stated that any such 

amendment should be prospective in 

nature and not impact calculations and 

sampling already underway. 

Response: After consideration of these 

comments, we agree that the proposed 

new definition of ‘‘decarburization 

vessels’’ was too broad and would 

include certain steel refining processes 

that were not intended (i.e., those whose 

primary purpose is not removal of 

carbon). Some of the additional 

processes cited by the commenters have 

a primary purpose to remove dissolved 

gases, and although some carbon may be 

incidentally removed, the CO2

emissions from these processes are a 

small percent of total GHG emissions 

from iron and steel making. Because the 

change in carbon content of the steel is 

so small, it is difficult to accurately 

quantify the emissions by a carbon 

balance, and it is problematic to 

measure them because of the sampling 

and other difficulties mentioned by the 

commenters. Consequently, we are 

revising the definition of 

‘‘decarburization vessels’’ to include 

those for which the primary purpose is 

removal of carbon, including but not 

limited to AOD and vacuum oxygen 

decarburization (VOD). We are not 

adding the suggested revision that the 

definition should include only those 

decarburization vessels equipped with 

flares because not all AOD and VOD 

vessels are equipped with flares. The 

revised definition makes the 

amendment a technical clarification that 

is more consistent with the final rule as 

originally promulgated. 

We also agree that additional time 

would be required to gather the data to 

report emissions from decarburization 

vessels other than AOD vessels, and we 

are amending the reporting 

requirements so that these emissions are 

reported beginning in March 2012 for 

the year 2011. However, the final 

amendments will not require a delay in 

the reporting period for AOD vessels 

because facilities with AOD vessels 

have known since the original 

promulgation of subpart Q that these 

decarburization vessels would be 

included in the reporting for 2010. 

J. Subpart S—Lime Manufacturing 

1. Summary of Final Amendments and 

Major Changes Since Proposal 

We are amending the cross reference 

to 40 CFR 98.193(b)(1) in the 

introductory language to 40 CFR 98.195; 

it incorrectly referenced 40 CFR 

98.193(b)(2). 

We are also amending the terminology 

used throughout subpart S to clarify 

whether the calculation and reporting 

requirements are referring to calcined 

byproducts and waste materials by 

adding the word ‘‘calcined’’ to the lime 

byproduct and waste terminology, as 

needed. We are also amending the 

terminology in the subpart to clarify 

when the calculation and reporting 

requirements apply to lime products 

that are produced at the facility. 

2. Summary of Comments and 

Responses 

EPA did not receive any comments on 

the proposed amendments to subpart S 

and is finalizing the amendments to this 

subpart as proposed. 

K. Subpart V—Nitric Acid Production 

1. Summary of Final Amendments and 

Major Changes Since Proposal 

We are amending 40 CFR 98.223 and 

98.224 to clarify how N2O emissions are 

to be measured if a facility has an N2O 

abatement device. The first amendment 

clarifies the location of the test 

(sampling) point used for the 

performance test in several paragraphs 

in 40 CFR 98.223. As promulgated, the 

language could be misconstrued to 

require the nitric acid facility to shut 

down any N2O abatement technology 

during the performance testing. This 

was not the intention as many, if not all, 

of the N2O abatement technologies in 

use must be operated at all times that 

the nitric acid facility is operated to 

control emissions of NOX in order to 

comply with state and federal 

regulations limiting NOX emissions. The 


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amendments will clarify that testing can 

occur before or after N2O abatement 

technology as long as the testing 

properly accounts for destruction 

efficiency. 

We are amending Equation V–3 of 

subpart V to accommodate N2O 

abatement technology located after the 

emission test (sampling) point, and redesignating it as Equation V–3a of 

subpart V. Equation V–3a is also 

corrected so that the term on the lefthand side of the equation is changed 

from EFN2Ot to EN2Ot. 

There are three ways in which 

abatement technology can be employed. 

Equation V–3a of subpart V is for one 

N2O abatement technology. We are 

adding Equation V–3b of subpart V to 

accommodate multiple N2O abatement 

technologies in series and we are adding 

Equation V–3c of subpart V to 

accommodate multiple N2O abatement 

technologies in parallel. 

We are also including a new Equation 

V–3d of subpart V for facilities that do 

not have N2O abatement technology 

located after the test (sampling) point. 

In addition, we are clarifying in 40 

CFR 98.223 that the annual performance 

test must be conducted for each nitric 

acid train, consistent with the equations 

in 40 CFR 98.223. Additional changes 

were made to the monitoring 

requirements in 40 CFR 98.224 to 

conform to the changes in the 

calculation methods in 40 CFR 98.223. 

We are amending 40 CFR 98.224(a)(1) to 

clarify when during a nitric acid 

production campaign facilities must 

conduct the performance test. 

We are also amending the language 

concerning the Administrator-approved 

alternative method for determining N2O 

emissions in 40 CFR 98.223(a)(2)(ii), 

98.224(a)(3), and 98.226(n). The 

alternative method is for determining 

N2O emissions rather than N2O 

concentration or an N2O emission 

factor. The language has been changed 

to correct this point. 

We are amending the data reporting 

requirements in 40 CFR 98.226(g) and 

(m) to be consistent with the calculation 

methods which are for each nitric acid 

train, not the facility. 

Major changes since proposal are 

identified in the following list. The 

rationale for these and any other 

significant changes can be found in this 

preamble or the Response to Comments: 

Technical Corrections, Clarifying and 

Other Amendments document (see 

EPA–HQ–OAR–2010–0109). 

• Changed the description of the emission 

factor, EFN2Ot from ‘‘lb N2O generated/ton 

nitric acid produced, 100 percent acid basis’’ 

to ‘‘lb N2O/ton nitric acid produced, 100 

percent acid basis.’’ 

• Changed the term ‘‘air stream’’ to ‘‘vent 

stream’’ at 40 CFR 98.223(g)(1). 

• Added Equations E–3b and E–3c of 

subpart E. 

2. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. Two 

sets of comments were received on this 

subpart. Responses to additional 

significant comments received can be 

found in Response to Comments: 

Technical Corrections, Clarifying and 

Other Amendments document (see 

EPA–HQ–OAR–2010–0109). 

Comment: One commenter noted that 

the regulation for Adipic Acid is similar 

to the regulation for Nitric Acid and 

asked that EPA compare the 

clarifications made to each of these 

subparts for consistency. 

Response: EPA agrees that there are 

similarities between the two subparts. 

Although the commenter did not 

provide specific examples for subpart V, 

EPA reviewed the commenter’s 

suggested clarifications for subpart E 

and made the following comparable 

changes to subpart V: 

EPA agrees with the change to the 

term ‘‘air stream.’’ The term has been 

changed to ‘‘vent stream’’ in 40 CFR 

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

with terminology used to identify 

testing locations at current facilities. 

EPA agrees that there could be 

situations at nitric acid facilities where 

multiple trains exhaust to a common 

abatement technology. Language has 

been added to 98.223(b)(1) to add 

flexibility for facilities that have a group 

of trains that exhaust to the same 

abatement equipment. Further, the 

equations do not correctly address 

situations in which a facility has 

separate N2O control or abatement 

technology on the separate train or 

process lines, back-up controls in 

parallel on a single train, and these 

technologies are not operated 100 

percent of the time (i.e., operated during 

maintenance operations on primary 

controls). We have learned that some 

facilities could have existing controls 

(e.g., NSCR) and may apply additional 

controls during the production process 

(e.g secondary catalysts in oxidation 

reactor) in the future. 

In these circumstances, the current 

equations will not provide an accurate 

calculation of N2O emissions. To 

address the three ways in which 

abatement technology can be employed 

EPA has revised 40 CRR 98.223 to 

include calculation methods to 

accurately account for these possible 

abatement applications. The current 

Equation V–3a of subpart V is for one 

N2O abatement technology. EPA has 

added Equation V–3b and V–3c to 

accommodate situations where multiple 

N2O abatement technologies operate in 

series and or multiple abatement 

technologies in parallel, respectively. 

Equation V–3d of subpart V addresses 

the situation when facilities that do not 

have N2O abatement technology. 

Comment: According to one 

commenter, facilities do not have 

information to determine a point during 

the campaign which is representative of 

the average emissions over the entire 

campaign. The commenter requested 

that 40 CFR 98.224(a)(1) be modified to 

ensure that performance tests are 

conducted during representative 

operations while enabling operating 

facilities to document and demonstrate 

compliance with this objective. 

Response: The purpose of this 

language was to capture emissions data 

when the process was operating 

normally. This requirement is to ensure 

that the emission factor developed 

through this performance test is an 

accurate depiction of the quantity of 

N2O emitted per quantity of nitric acid 

produced over the course of an entire 

year. A campaign was used as a 

reference due to concerns that N2O rates 

from nitric acid plants are somewhat 

below average at the beginning of a 

campaign and above average at the end 

of a campaign. Testing during either of 

those times could result in an emission 

factor developed during nonrepresentative conditions. For example, 

at the end of a campaign, the age of the 

catalyst may influence emissions. As 

long as the choice of the timing of the 

testing is documented and the methods 

used to determine the timing are 

documented, this requirement is met. 

EPA has clarified ‘‘average emissions 

over the entire campaign’’ to ‘‘average 

emissions rate from nitric acid 

campaigns’’ as it is the emissions rate 

that is obtained during the performance 

test and a facility may run more than 

one production campaign over a 

reporting year. EPA does not agree that 

the additional changes recommended 

are needed. 

The rule offers flexibility in 

determining the timing of the 

performance testing. Facilities may refer 

to literature and continuous monitoring 

data from similar facilities in other 

countries. This literature and data could 

be used to determine an appropriate test 

point from a representative or typical 

nitric acid campaign. The rule provides 

facilities flexibility on methods to 

determine this testing point. Further, 

facilities can also apply to EPA to use 

alternative methods for determining 

N2O emissions. 


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L. Subpart Z—Phosphoric Acid 

Production 

1. Summary of Final Amendments and 

Major Changes Since Proposal 

We are renumbering Equation Z–1 as 

Z–1a of subpart Z and adding a new 

Equation Z–1b of subpart Z. Equation 

Z–1b will be used to calculate CO2

emissions when the method used to 

analyze phosphate rock provides a 

direct estimate of CO2 emissions instead 

of just inorganic carbon content. 

We have learned from facilities that 

the ‘‘Phosphate Mining States Methods 

Used and Adopted by the Association of 

Fertilizer and Phosphate Chemists 

AFPC Manual 10th Edition—Version 

1.9’’ (AFPC manual) does not currently 

contain a procedure for obtaining a 

representative grab sample of rock for 

testing. A recently updated version of 

the AFPC manual, Version 1.92, does 

contain the appropriate sampling 

procedures. To add flexibility to the 

rule, we are amending 40 CFR 98.264(a) 

to allow facilities to use the appropriate 

industry consensus standards or 

industry standard practices currently 

available. We are also amending 40 CFR 

98.264(a) to clarify that the grab sample 

must be collected prior to entering the 

mill for accurate analysis of inorganic 

carbon contents. 

We are amending 40 CFR 98.266 to 

correct a cross reference in the 

introductory text of that section, and to 

revise paragraph (c) to clarify that the 

annual arithmetic average percent 

inorganic carbon in phosphate rock is to 

be reported as the percent by weight, 

expressed as a decimal fraction. We are 

also adding a new paragraph (f)(9) to 40 

CFR 98.266 to specify that facilities 

need to report the total annual process 

CO2 emissions from the phosphoric acid 

production facility, in metric tons. 

Facilities must calculate these emissions 

already in 40 CFR 98.263(b)(2) using 

Equation Z–2 of subpart Z. 

Major changes since proposal are 

identified in the following list. The 

rationale for these and any other 

significant changes can be found in this 

preamble or the Response to Comments: 

Technical Corrections, Clarifying and 

Other Amendments document (see 

EPA–HQ–OAR–2010–0109). 

• Renumbered Equation Z–1 as Equation 

Z–1a of subpart Z. 

• Added a new Equation Z–1b of subpart 

Z. 

• Revised 98.364(a) and (b) to allow 

facilities to use the appropriate industry 

consensus standard or industry standard 

practice. 

2. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. 

Several comments were received on this 

subpart. Responses to additional 

significant comments received can be 

found in Response to Comments: 

Technical Corrections, Clarifying and 

Other Amendments document (see 

EPA–HQ–OAR–2010–0109). 

Comment: One commenter requested 

that Equation Z–1 be revised to 

accurately reflect the output of the 

AFPC Manual’s method for the analysis 

of phosphate rock. Regarding the 

inorganic carbon determinations, the 

equation assumes that the AFPC 

Manual’s test is for inorganic carbon 

and the equation provides for 

calculation of CO2 emissions using 

inorganic carbon content as an input. 

However, the AFPC Manual’s test is for 

CO2 directly, making Equation Z–1 of 

subpart Z inapplicable as written to the 

AFPC Manual’s test output. The 

commenter suggested a technical 

amendment to correct this minor 

misalignment by removing the factor to 

convert inorganic carbon to CO2 from 

Equation Z–1. 

Response: EPA agrees that this change 

is warranted. However, EPA has 

decided not to replace Equation Z–1 but 

to renumber Equation Z–1 as Equation 

Z–1a and to add the revised equation as 

Equation Z–1b. This subpart would still 

allow facilities to use other methods 

(e.g., sampling inorganic carbon 

content) to determine carbon content in 

addition to using analytic methods to 

directly measure CO2 emissions. 

Therefore, EPA is maintaining this 

flexibility by retaining the previous 

equation and adding a new one that can 

be used with the AFPC Manual. 

M. Subpart CC—Soda Ash 

Manufacturing 

1. Summary of Final Amendments and 

Major Changes Since Proposal 

We are amending the data reporting 

requirements in 40 CFR 98.296(b)(3) to 

clarify that the annual soda ash 

production is reported for each line, and 

to make the reporting requirements 

consistent with the calculation 

requirements in 40 CFR 98.293(b)(1) 

through (b)(3). The units in 40 CFR 

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

corrected from metric tons to short tons 

for consistency with other similar data 

reporting requirements. This change is 

also consistent with how facilities 

collect these data. 

We are also amending 40 CFR 

98.296(b)(10) to clarify that the 

information in that paragraph is 

reported for each manufacturing line or 

stack, when using a site specific 

emission factor, and to clarify that the 

elements required by 40 CFR 

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

periods during the performance test. We 

are also deleting 40 CFR 

98.296(b)(11)(iv), (v), and (vi) because 

those paragraphs describe missing data 

procedures for elements during the sitespecific emission factor performance 

test which are not allowed to be missing 

per 40 CFR 98.296(c). 

2. Summary of Comments and 

Responses 

EPA did not receive any comments on 

the proposed amendments to subpart CC 

and is finalizing the amendments to this 

subpart as proposed. 

N. Subpart EE—Titanium Dioxide 

Production 

1. Summary of Final Amendments and 

Major Changes Since Proposal 

We are amending the monitoring and 

QA/QC reporting requirements in 40 

CFR 98.314(e) to clarify that the 

quantity of carbon-containing waste 

generated from each titanium dioxide 

production line is determined on a 

monthly basis, consistent with the 

calculation procedures in 40 CFR 

98.313(b)(3). In addition, we are 

amending the data reporting 

requirements under 40 CFR 98.316(b)(9) 

to be consistent with the calculation and 

monitoring alternative requirements of 

40 CFR 98.313(b)(2) and 40 CFR 

98.314(c) by removing the restriction 

that the carbon content factor for 

petroleum coke can only be from the 

supplier. We are also amending the data 

reporting requirements under 40 CFR 

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

to each process line, consistent with the 

calculation and monitoring alternative 

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

40 CFR 98.314(f). 

2. Summary of Comments and 

Responses 

EPA did not receive any comments on 

the proposed amendments to subpart EE 

and is finalizing the amendments to this 

subpart as proposed. 

O. Subpart GG—Zinc Production 

1. Summary of Final Amendments and 

Major Changes Since Proposal 

We are amending the definitions of 

the terms for (Electrode)k and (CElectrode)k

in Equation GG–1 of subpart GG to 

remove the references to kilns because 

electrodes are only used in 

electrothermic furnaces and are not 

used in Waelz kilns. We are also 

amending 40 CFR 98.336(a) to correct a 


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cross reference to subpart C, and to 

amend 40 CFR 98.336(b)(1) to clarify 

that identification numbers need to be 

reported for both Waelz kilns and 

electrothermic furnaces. 

We are amending the data reporting 

requirements in 40 CFR 98.336(b)(7) and 

(10) to clarify that the carbon content of 

each input to a kiln or furnace should 

be reported as a calculation parameter 

regardless of whether the data are 

collected from the supplier or by self 

measurement. In 40 CFR 98.336, 

paragraphs (b)(8) and (11) already 

require facilities to report whether 

carbon contents were determined 

through self measurement or based on 

reports from the supplier. 

2. Summary of Comments and 

Responses 

EPA did not receive any comments on 

the proposed amendments to subpart 

GG and is finalizing the amendments to 

this subpart as proposed. 

P. Subpart HH—Municipal Solid Waste 

Landfills 

1. Summary of Final Amendments and 

Major Changes Since Proposal 

We are making numerous clarifying 

amendments and technical corrections 

to subpart HH to address questions EPA 

has received about the rule’s 

requirements and to correct known 

errors. Amendments to the rule are also 

being made to address some of the more 

significant questions that were the result 

of the level of detail provided in the 

2009 final rule. 

Source Category Definition. We are 

amending 40 CFR 98.340(b) to read, 

‘‘This source category does not include 

Resource Conservation and Recovery 

Act (RCRA) Subtitle C or Toxic 

Substances Control Act (TSCA) 

hazardous waste landfills, construction 

and demolition waste landfills, or 

industrial waste landfills.’’ We are 

adding definitions within 40 CFR 

98.348 for the terms ‘‘construction and 

demolition waste landfills’’ and 

‘‘industrial waste landfills.’’ 

Equation HH–1. We are making the 

following technical amendments to 

Equation HH–1 in 40 CFR 98.343: 

• Replace the term L0 (CH4 generating 

potential) with the terms, 

‘‘MCF×DOC×DOCF×F×16/12,’’ (where MCF is 

the CH4 correction factor; DOC is the 

degradable organic content; DOCF is the 

fraction of DOC dissimilated; and F is the 

fraction by volume of CH4 in landfill gas) and 

remove the definition of the term L0 from the 

definitions for Equation HH–1 of subpart HH. 

• Revise the definition of ‘‘S’’ to read, ‘‘Start 

year of calculation. Use the year 1960 or the 

opening year of the landfill, whichever is 

more recent.’’ 

• Revise the definition of Wx to include 

‘‘measurement data’’ as follows: ‘‘Quantity of 

waste disposed of in the landfill in year x 

from measurement data, tipping fee receipts, 

or other company records (metric tons, as 

received (wet weight).’’ 

• Revise the definition of ‘‘MCF’’ to read 

‘‘Methane correction factor (fraction). Use the 

default value of 1 unless there is active 

aeration of waste within the landfill during 

the reporting year. If there is active aeration 

of waste within the landfill during the 

reporting year, either use the default value of 

1 or select an alternative value no less than 

0.5 based on site-specific aeration 

parameters.’’ 

• Revise the definition of ‘‘DOCf’’ to read, 

‘‘Fraction of DOC dissimilated (fraction). Use 

the default value of 0.5.’’ 

• Revise the definition of ‘‘F’’ as follows: 

‘‘Fraction by volume of CH4 in landfill gas 

from measurement data on a dry basis, if 

available (fraction); default is 0.5.’’ 

• Revise the definition of ‘‘k’’ to read, ‘‘Rate 

constant from Table HH–1 to subpart HH (yr1). Select the most applicable k value for the 

majority of the past 10 years (or operating 

life, whichever is shorter).’’ 

We are also amending 40 CFR 

98.343(a)(2) to replace ‘‘use the bulk 

waste parameter values for k and L0 in 

Table HH–1 to subpart HH’’ with ‘‘use 

the bulk waste parameter values for k 

and DOC in Table HH–1 to subpart 

HH.’’. 

Measuring Waste Quantity. We are 

amending 40 CFR 98.343(a) by adding a 

new paragraph (a)(3) to provide the 

necessary detail and clarification on the 

requirements for measuring the quantity 

of waste disposed in the landfill 

beginning with the first reporting year, 

and re-designating the existing 40 CFR 

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

waste measurement requirements for the 

reporting years require the use of scales 

when scales are in-place for all vehicles 

or containers delivering waste, except 

passenger vehicles and light duty pickup trucks or waste loads that cannot be 

measured using the scales due to 

physical limitations (load cannot 

physically access or fit on the scale) 

and/or operational limitations of the 

scale (load exceeds the limits or 

sensitivity range of the scale). 

When scales are present at the MSW 

landfill, they must be used, (except for 

passenger vehicles and light duty pickup trucks or waste loads that cannot be 

measured using scales due to physical 

and/or operational limitations). Two 

options for the use of scales are 

included in the amendments. One 

option is to directly weigh each vehicle/ 

container load as it enters the landfill 

and weigh each vehicle/container after 

the waste has been off-loaded, and 

calculate the mass of waste disposed as 

the difference in the two measurements. 

The second option requires the landfill 

owner or operator to determine tare 

weights (empty vehicle weights) for 

representative vehicle types. In this 

option, the landfill owner or operator 

must weigh the incoming vehicles and 

containers and calculate the mass of 

waste disposed based on the difference 

of the incoming vehicle weight and the 

tare weight of that vehicle type. 

When scales are not in place, the 

working capacity or the mass of waste 

per type of vehicle or container must be 

determined. These measurements may 

include determining the volumetric 

capacity of representative containers 

and the average density of the waste as 

received. Wheel-load scales or portable 

axle-load scales may be used for these 

density determinations or measures of 

the mass of waste received by type of 

load. The landfill owner or operator 

must record the number and type of 

vehicles that haul waste to the landfill 

and use the working capacity of the 

containers to calculate the quantity of 

waste landfilled. 

In addition to redesignating paragraph 

(a)(3) of 40 CFR 98.343 to (a)(4), we are 

amending that paragraph and the subparagraphs to clarify that measurement 

data can be used for historical years 

when the data are available. We are 

clarifying that the ‘‘Historical waste 

disposal quantities should only be 

determined once, as part of the first 

annual report, and the same values 

should be used for all subsequent 

annual reports, supplemented by the 

next year’s data on new waste disposal.’’ 

We are also amending 40 CFR 

98.343(a)(4)(i) to read, ‘‘Assume all prior 

year’s waste disposal quantities are the 

same as the waste quantity in the first 

year for which waste quantities are 

available.’’ We are amending 40 CFR 

98.343(a)(4)(iii) by revising the phrase, 

‘‘i.e., from first accepting waste * * *’’ 

with ‘‘i.e., from the first year accepting 

waste * * *’’ 

In related amendments, we are also 

amending 40 CFR 98.344(a) to state that 

‘‘Mass measurement equipment used to 

determine the quantity of waste 

landfilled on or after January 1, 2010 

must meet the requirements for 

weighing equipment as described in 

‘‘Specifications, Tolerances, and Other 

Technical Requirements For Weighing 

and Measuring Devices,’’ NIST 

Handbook 44 (2009) (incorporated by 

reference, see 40 CFR 98.7).’’ We are also 

amending 40 CFR 98.346(a) to require 

reporting of ‘‘ * * an indication of 

whether scales are present at the 

landfill,’’ and to amend 40 CFR 

98.346(b) to require reporting of the 

waste quantities that were determined 

using scales according to the 

requirements in 40 CFR 98.343(a)(3)(i) 


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and the waste quantities determined 

using vehicle counts and load 

capacities. We are also amending 40 

CFR 98.347 to specifically require that 

records be maintained of all 

measurements used to determine 

vehicle tare weights or working 

capacities. 

Equations HH–2, HH–3, and HH–4. 

We are making the following technical 

amendments to Equation HH–2 in 40 

CFR 98.343: 

• Replace the term ‘‘WGRX’’ with ‘‘WDRX’’ 

and remove the term ‘‘%SWDS.’’ 

• Replace the definition of the term 

‘‘WGRX’’ with ‘‘WDRX = Average per capita 

waste disposal rate for year x from Table HH– 

2 to this subpart (metric tons per capita per 

year, wet basis; tons/cap/yr).’’ 

• Delete the definition of the term 

‘‘%SWDS.’’ 

• Delete the word ‘‘of’’ from the definition 

of ‘‘POPX.’’ 

We are making the following 

technical amendments to Equation HH– 

3 in 40 CFR 98.343: 

• Replace the term ‘‘WDRX’’ with ‘‘WX.’’ 

• Replace the definition of the term 

‘‘WDRX’’ with ‘‘WX’’ = quantity of waste place 

in the landfill in year x (metric tons/wet 

basis).’’ 

• Replace the definition of LFC with 

‘‘Landfill capacity or, for operating landfills, 

capacity of the landfill used (or the total 

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

year prior to the year when waste disposal 

data are available from design drawings or 

engineering estimates (metric tons).’’ 

We are making the following 

technical amendments to Equation HH– 

4 and the related 40 CFR 98.343(b): 

• Amend Equation HH–4 of subpart HH 

and the terms in that equation to allow for 

daily averages (365 or 366 per year) from a 

continuous CH4 monitoring system, or from 

weekly sampling (with 52 measurement 

periods). 

• Amend the definitions of the terms (T)n

and (P)n in Equation HH–4 to allow for 

averaging of measurements. 

• In 40 CFR 98.343(b)(2), delete ‘‘* * * at 

least weekly * * *’’ 

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

(iii)(B), replace ‘‘no less than weekly’’ with ‘‘at 

least once each calendar week; if only one 

measurement is made each calendar week, 

there must be at least three days between 

measurements.’’ 

• In 40 CFR 98.343(c), replace ‘‘Calculate 

***’’ with ‘‘For all landfills, calculate 

***’’ 

Moisture Content Measurement. In 

addition to the other amendments to 

Equation HH–4 of subpart HH discussed 

above, we revised the definition of (V)n

to be the cumulative volume for the 

measurement period (rather than the 

volumetric flow rate), eliminated the 

1,440 conversion factor for minutes per 

day, and revised the reference to ‘‘day’’ 

in the definition of equation terms with 

‘‘measurement period.’’ We are also 

amending Equation HH–4 to replace the 

moisture correction term, [1¥(fH2O)n], 

with a moisture correction factor, KMC. 

KMC is defined as ‘‘Moisture correction 

term for the measurement period, 

volumetric basis,’’ for three different 

measurement scenarios: 

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

on a dry basis or if both are measured on a 

wet basis. 

KMC = 1¥(fH2O)n if (V)n is measured on a 

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

KMC = 1/[1¥(fH2On] if (V)n is measured on 

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

basis. 

We are similarly amending 40 CFR 

98.343(b)(2)(iii)(B) to indicate that 

moisture content is needed ‘‘[i]f the CH4

concentration is determined on a dry 

basis and flow is determined on a wet 

basis or CH4 concentration is 

determined on a wet basis and flow is 

determined on a dry basis, * * *’’. 

We are amending 40 CFR 98.344(d) 

and (e) to include reference to moisture 

content monitors. Specifically, we are 

amending 40 CFR 98.344(d) to read: ‘‘All 

temperature, pressure, and if necessary, 

moisture content monitors must be 

calibrated using the procedures and 

frequencies specified by the 

manufacturer.’’ We are also amending 

the first sentence in 40 CFR 98.343(d) to 

read, ‘‘The owner or operator shall 

document the procedures used to ensure 

the accuracy of the estimates of disposal 

quantities and, if applicable, gas flow 

rate, gas composition, temperature, 

pressure, and moisture content 

measurements.’’ We are amending 40 

CFR 98.346(i)(3) to require reporting of 

both temperature and pressure (not just 

temperature) and to amend 40 CFR 

98.346(i)(4) to require reporting of the 

moisture content measurements. 

‘‘Active’’ and ‘‘Passive’’ Gas Collection 

Systems. We are amending the 

definition of ‘‘gas collection system’’ in 

40 CFR 98.6 as described in Section II.B 

of this preamble and we are adding a 

reporting requirement in 40 CFR 

98.346(h) and (i)(7) for reporters to 

provide ‘‘an indication of whether 

passive vents and/or passive flares 

(vents or flares that are not considered 

part of the gas collection system as 

defined in 40 CFR 98.6) are present at 

this landfill.’’ 

Other Technical Corrections. We are 

making other technical corrections for 

subpart HH to correct typographical 

errors, to correct equations, and to 

provide minor clarifications. 

We are making the following 

technical corrections to 40 CFR 

98.344(b): 

• Delete the word ‘‘install.’’ 

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

routine sampling location.’’ 

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

‘‘Take a minimum of three grab samples of 

the landfill gas with a minimum of 20 

minutes between samples and determine the 

methane composition of the landfill gas using 

one of the methods specified in paragraphs 

(b)(1) through (b)(5) of this section.’’ 

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

collected and routed to a destruction device 

(before and treatment equipment).’’ 

• In 40 CFR 98.344(b)(6)(ii)(B), add ‘‘for 

use in Equation HH–4 of this subpart’’ to the 

definition of the term CH4 as follows 

‘‘Methane concentration in the landfill gas 

(volume %) for use in Equation HH–4 of this 

subpart.’’ 

In 40 CFR 98.344(c), we are revising 

the language to read, ‘‘Each gas flow 

meter shall be recalibrated either 

biennially (every 2 years) or at the 

minimum frequency specified by the 

manufacturer. Except as provided in 40 

CFR 98.343(b)(2)(i), each gas flow meter 

must be capable of correcting for the 

temperature and pressure and, if 

necessary, moisture content.’’ We are 

making the following technical 

corrections to 40 CFR 98.346: 

• Revise the language in 40 CFR 98.346(a) 

regarding leachate recirculation to read ‘‘an 

indication of whether leachate recirculation 

is used during the reporting year and its 

typical frequency of use over the past 10 

years (e.g., used several times a year for the 

past 10 years, used at least once a year for 

the past 10 years, used occasionally but not 

every year over the past 10 years, not used).’’ 

• Revise 40 CFR 98.346(c) to read ‘‘Waste 

composition for each year required for 

Equation HH–1 of this subpart, in percentage 

by weight, for each waste category listed in 

Table HH–1 to this subpart that is used in 

Equation HH–1 of this subpart to calculate 

the annual modeled CH4 generation.’’ 

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

‘‘Degradable organic carbon (DOC) value used 

in the calculations,’’ with ‘‘Degradable 

organic carbon (DOC), methane correction 

factor (MCF), and fraction of DOC 

dissimilated (DOCF) values used in the 

calculations.’’ 

• In 40 CFR 98.346(d)(1) add ‘‘If an MCF 

value other than the default of 1 is used, 

provide an indication of whether active 

aeration of the waste in the landfill was 

conducted during the reporting year, a 

description of the aeration system, including 

aeration blower capacity, the fraction of the 

landfill containing waste affected by the 

aeration, the total number of hours during the 

year the aeration blower was operated, and 

other factors used as a basis for the selected 

MCF value.’’ 

• Revise 40 CFR 98.346(f) to read, ‘‘The 

surface area of the landfill containing waste 

(in square meters), identification of the type 

of cover material used (as either organic 

cover, clay cover, sand cover, or other soil 

mixtures). If multiple cover types are used, 

the surface area associated with each cover 

type.’’ 

• Add ‘‘for the reporting year’’ to 40 CFR 

98.346(i)(1) as follows: ‘‘Total volumetric 


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flow of landfill gas collected for destruction 

for the reporting year (cubic feet at 520°R or 

60°F and 1 atm).’’ 

• Add ‘‘Annual average’’ to 40 CFR 

98.346(i)(2)as follows: ‘‘Annual average CH4

concentration of landfill gas collected for 

destruction (percent by volume).’’ 

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

parenthetical ‘‘(manufacture, capacity, 

number of wells, etc.)’’ with ‘‘(manufacturer, 

capacity, and number of wells).’’ 

We are also adding the following 

definitions within 40 CFR 98.348 of 

subpart HH: ‘‘destruction device’’; ‘‘solid 

waste’’; and ‘‘working capacity.’’ 

We are amending Table HH–1 to 

subpart HH to delete the default value 

for Lo, to provide additional DOC and kvalues including those for inerts, e.g., 

glass, plastics, metal, concrete, and to 

provide additional DOC and k-values to 

provide additional options for 

categorizing waste when applying 

Equation HH–1 in 40 CFR 98.343(a). We 

are also amending Table HH–1 to 

subpart HH to provide a more reasoned 

approach for determining the decay rate 

constant, k, when only a small quantity 

of leachate is recirculated and/or when 

leachate recirculation is used rarely (not 

every year). The leachate recirculation 

rate will be calculated as the total 

volume of leachate recirculated during 

the year divided by the area of the 

portion of the landfill containing waste. 

No direct measurement of volume of 

leachate recirculated is required; 

engineering estimates may be used. This 

leachate recirculation rate (in inches/ 

year) is added to the precipitation rate 

and the sum used to determine what 

decay rate constant is appropriate. 

Alternatively, landfills that use leachate 

recirculation can elect to use the higher 

k value rather than calculating the 

recirculated leachate rate. The footnotes 

for Table HH–1 to subpart HH have been 

revised accordingly. 

We are amending Table HH–2 to 

subpart HH to provide directly the 

waste disposal factors rather than the 

waste generation rates and percent 

disposed of in solid waste disposal sites 

(% to SWDS) and correcting an error in 

the waste generation rates included in 

Table HH–2 to subpart HH from 1989 to 

2006. We are also adding waste disposal 

rates for 2007, 2008, and 2009. 

We are amending Table HH–3 to 

subpart HH to delete the references to 

the average depth of waste within an 

area (H2, H3, H4, and H5). We are also 

amending Table HH–3 to subpart HH to 

clarify what is considered a ‘‘final soil 

cover.’’ The description for A5 is revised 

to read, ‘‘Area with a final soil cover of 

3 feet or thicker of clay and/or 

geomembrane cover system and active 

gas collection.’’ The description for A4 

is revised to read, ‘‘Area with an 

intermediate soil cover, or a final soil 

cover not meeting the criteria for A5 

below, and active gas collection.’’ 

Major changes since proposal are 

identified in the following list. The 

rationale for these and any other 

significant changes can be found in this 

preamble or the Response to Comments: 

Technical Corrections, Clarifying and 

Other Amendments (see EPA–HQ– 

OAR–2010–0109). 

• Deleted the word ‘‘dedicated’’ from the 

phrase ‘‘dedicated construction and 

demolition waste landfill’’ in 40 CFR 

98.340(b) and replaced the proposed 

definition of ‘‘dedicated construction and 

demolition waste landfill’’ with a definition 

of ‘‘construction and demolition waste 

landfill’’ taken from 40 CFR part 257.2. 

• Revised the definition of MCF term in 

Equation HH–1 to allow landfills with active 

aeration to select an MCF value less than 1, 

but no lower than 0.5 and added reporting 

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

facilities using an MCF value other than 1. 

• Revised Table HH–1 to subpart HH to 

include DOC and k values for additional 

waste categories to provide an additional 

option for characterizing waste materials 

when applying Equation HH–1 of subpart 

HH. 

• Revised the footnotes to Table HH–1 to 

subpart HH to allow the use of the greater k 

value in a given range when recirculation is 

used without the need to calculate the 

recirculated leachate quantity in inches per 

year. 

• Revised 40 CFR 98.343(a)(3) to account 

for those loads that cannot be measured using 

scales due to their physical and/or 

operational limitations. 

2. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. 

Several comments were received on this 

subpart. Responses to additional 

significant comments received can be 

found in Response to Comments: 

Technical Corrections, Clarifying and 

Other Amendments (see EPA–HQ– 

OAR–2010–0109). 

Comment: Several commenters stated 

that the new definition of ‘‘dedicated 

construction and demolition (C&D) 

waste landfills’’ is problematic and 

inappropriate because it is inconsistent 

with the C&D landfill definition already 

long-established in 40 CFR 257.2, 

‘‘Criteria for the Classification of Solid 

Waste Disposal Facilities and Practices,’’ 

it represents a significant material 

change to the subpart HH applicability 

requirements, and it changes the data 

collection requirements for landfills 

retroactively. The RCRA Subtitle D 

definition 40 CFR 257.2 is: 

‘‘Construction and demolition (C&D) 

landfill means a solid waste disposal facility 

subject to the requirements of subparts A or 

B of this part that receives construction and 

demolition waste and does not receive 

hazardous waste (defined in § 261.3 of this 

chapter) or industrial solid waste (defined in 

§ 258.2 of this chapter). Only a C&D landfill 

that meets the requirements of subpart B of 

this part may receive conditionally exempt 

small quantity generator waste (defined in 

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

typically receives any one or more of the 

following types of solid wastes: Roadwork 

material, excavated material, demolition 

waste, construction/renovation waste, and 

site clearance waste.’’ 

According to the commenters, a 

dedicated C&D landfill, as defined in 

the proposal, rarely exists and most 

states allow C&D landfills to accept yard 

waste and other forms of household 

trash, pointing to the use of the word 

‘‘typically’’ with regard to the types of 

wastes received, and suggesting that site 

clearance waste includes yard waste 

among other materials. The commenters 

urged EPA to delete the new C&D 

landfill definition in 40 CFR 98.348 and 

replace it with the definition found in 

40 CFR 257.2. On the other hand, one 

commenter expressed concern with 

excluding ‘‘dedicated C&D waste 

landfills’’ even with the proposed 

definition and requested EPA to 

quantify the methane emissions from 

these C&D landfills. 

Response: We generally agree with 

commenters that the RCRA Subtitle D 

definition in 40 CFR 257.2 is 

appropriate and should be used in 

preference to the proposed definition of 

‘‘dedicated C&D waste landfills.’’ 

However, we are concerned with some 

of the assertions made by the 

commenters that a ‘‘C&D waste landfill’’ 

could accept some yard wastes and 

possibly other household wastes. Yard 

waste and household solid wastes are 

clearly included in the definition of 

‘‘municipal solid waste or MSW’’ in 40 

CFR 98.6. The definition of ‘‘MSW 

landfill’’ in 40 CFR 98.6 ‘‘means an 

entire disposal facility * * * where 

household waste is placed in or on 

land.’’ It is our interpretation and intent 

that any landfill in which household 

wastes, including household yard 

wastes or other MSW materials, are 

placed is a MSW landfill and is subject 

to the reporting requirements of subpart 

HH. As we did not change or alter the 

definition of MSW or MSW landfill, we 

do not agree with commenters that 

interpret the RCRA Subtitle D definition 

of C&D landfills in 40 CFR 257.2 to 

somehow supersede the definitions and 

intent of subpart HH. Furthermore, the 

definition of MSW landfill (MSWLF) 

unit in 40 CFR 257.2 specifies that ‘‘a 

C&D waste landfill that receives 

residential lead-based paint waste and 


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does not receive any other household 

waste is not a MSWLF unit.’’ The 

converse of the statement clearly 

suggests that a C&D waste landfill that 

receives any household waste other than 

residential lead-based paint waste is a 

MSWLF unit. Thus, while we are 

revising the definition of C&D landfill to 

more closely follow the definition at 40 

CFR 257.2, we do not agree that we 

materially altered the rule by providing 

a definition of dedicated C&D waste 

landfill and strongly object to the 

supposition that landfills that receive 

even small quantities of household 

wastes (other than residential leadbased paint wastes) are anything other 

than MSW landfills. Therefore, to clarify 

our intent, we have revised slightly the 

language adapted from the RCRA 

definition to specifically state that a 

C&D waste landfill does not receive 

MSW. We also deleted the sentence 

regarding conditionally exempt waste as 

superfluous to the requirements of this 

definition in subpart HH. The final 

definition reads ‘‘Construction and 

demolition (C&D) waste landfill means a 

solid waste disposal facility subject to 

the requirements of subparts A or B of 

part 257 of this chapter that receives 

construction and demolition waste and 

does not receive hazardous waste 

(defined in 40 CFR 261.3 of this chapter) 

or industrial solid waste (defined in 40 

CFR 258.2 of this chapter) or municipal 

solid waste (defined in 40 CFR 98.6) 

other than residential lead-based paint 

waste. A C&D waste landfill typically 

receives any one or more of the 

following types of solid wastes: 

roadwork material, excavated material, 

demolition waste, construction/ 

renovation waste, and site clearance 

waste.’’ 

While we have adopted, for the most 

part, the RCRA subtitle D definition for 

C&D waste landfills, we maintain that 

the inclusion of a definition of C&D 

waste landfills is not a material change 

in the rule because it does not alter the 

definition of MSW landfill or the 

applicability of the rule to MSW 

landfills. As the final definition of C&D 

waste landfills expressly includes site 

clearance wastes, which could include 

trees and other materials that have 

significant organic content, we agree 

that additional evaluation is needed to 

assess the methane generation potential 

of C&D waste landfills. Consequently, 

we are taking this comment under 

advisement; we will determine whether 

or not reporting requirements should be 

proposed for C&D waste landfills at a 

future time based on the results of the 

additional evaluations of C&D waste 

materials and their methane generation 

potential. 

Comment: Several commenters 

expressed support for the amended 

definition of ‘‘gas collection systems or 

landfill gas collection systems,’’ 

intended to clarify that passive vents/ 

flares are not considered part of a 

landfill gas collection system for 

purposes of subpart HH. However, these 

commenters opposed the proposed 

reporting requirement to provide an 

indication of whether passive vents 

and/or passive flares that are not 

considered part of the gas collection 

system as defined in 40 CFR 98.6 are 

present at the landfill. The commenters 

argued that this represents a new data 

element that would require significant 

additional burden to contact landfill 

engineers to collect this new 

information. The commenters 

recommended that EPA finalize this 

data element, but delay its collection to 

January 1, 2011, and delay its reporting 

to March 31, 2012 and thereafter. On the 

other hand, one commenter expressed 

concerned that EPA’s decision to 

exempt ‘‘passive’’ gas collection systems 

from flow meter reporting may 

inadvertently exempt substantial 

emissions sources. The commenter 

noted that the number of landfills with 

passive vent controls is uncertain and 

argued that the cumulative emissions 

from these passive collection systems 

could be significant. The commenter 

requested EPA include any data on this 

point in the record for the final 

rulemaking and include passive gas 

collection systems fully in the rule if 

warranted. 

Response: The monitoring 

requirements for gas collection systems 

within the final rule were developed 

considering forced ventilation systems 

and those monitoring requirements are 

inappropriate for passive gas collection 

systems. However, we agree with the 

commenter who suggested that EPA 

must obtain more data on the 

prevalence of these systems in order to 

properly understand and account for the 

impact these systems may have on the 

GHG emissions from MSW landfills. We 

find that ‘‘an indication’’ (essentially 

answering a yes/no question to indicate 

whether or not a passive gas collection 

system is present) is not a significant 

additional reporting burden. As this 

reporting requirement requires no 

monitoring or other activities that might 

be considered a retroactive requirement, 

we conclude that this reporting 

requirement is appropriate and 

necessary for the 2010 reporting year. 

Comment: A few commenters 

indicated that the requirement to use a 

methane correction factor (MCF) of 1 

will overestimate methane generation 

from landfills that are actively aerated 

and recommended that facilities be 

allowed to use alternative MCF values 

based on site-specific conditions (e.g., 

the use of in-situ aeration). 

Response: To the extent some MSW 

landfills actively aerate the waste within 

the landfill, we agree that alternative 

MCF values should be allowed for 

actively aerated landfills. Supplying air 

to the waste within the landfill will 

reduce the fraction of carbon that is 

degraded anaerobically, which is 

represented by the MCF value. 

However, additional reporting 

requirements are needed to verify the 

MCF value selected. These include the 

basis of the alternative value, such as an 

indication of whether active aeration is 

used, a description of the aeration 

system, including aeration blower 

capacity, the fraction of the landfill 

containing waste affected by the 

aeration, the total number of hours 

during the year the aeration blower was 

operated, and other factors used as a 

basis for the selected MCF value. Based 

on other comments received (e.g., 

comments described above on reporting 

of the presence of passive gas collection 

systems), the inclusion of these 

additional reporting requirements 

would likely be objectionable. However, 

we have conditioned these additional 

reporting requirements to be applicable 

only for facilities electing not to use an 

MCF value of 1. As the reporting 

requirements for facilities that use an 

MCF value of 1 have not changed, and 

because all facilities can choose to use 

the default value of 1 (including the 

relatively few landfills that use active 

aeration), we find that we have not 

significantly altered the reporting 

requirements of the final rule. Facilities 

electing to use an MCF other than 1 

must have active aeration and must 

provide information regarding the 

aeration system to justify the lower MCF 

value. 

Comment: One commenter noted that 

the new defaults for inert wastes in 

Table HH–1 to subpart HH are 

designated for use only by those 

landfills capable of segregating and 

measuring the waste they accept by 

composition using EPA’s prescribed 

waste categories, which include: food 

waste, garden, paper, wood and straw, 

textiles, diapers, sewage sludge and, 

now, inerts. According to commenters, 

U.S. MSW landfills do not use these 

categories to categorize waste receipts, 

and few if any MSW landfills will be 

able to adjust for large quantities of 

inerts that may be disposed of at a 

specific landfill. The commenter noted 

that the MSW landfill sector in the U.S. 


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typically records waste type receipts 

using the broad categories of MSW bulk 

waste, construction and demolition 

(C&D) bulk waste, inert waste, sewage 

sludge, and yard and garden waste. The 

commenter recommended that the inert 

defaults be included in Table HH–1 to 

subpart HH for the ‘‘Bulk Waste Option’’ 

to allow landfills to take large 

shipments of bulk inert wastes into 

account in their landfill gas generation 

models. 

Response: The bulk DOC and k values 

were determined based on monitored 

landfill gas generation rates and the 

total quantity of waste disposed (annual 

average waste acceptance rates). We 

reviewed the C&D waste acceptance 

policies of these landfills, as C&D waste 

can largely be comprised of inert 

materials, and determined that each 

landfill accepted C&D wastes. While we 

do not have a breakdown of the relative 

quantities of different categories of 

wastes in these landfills, we maintain 

that the default ‘‘bulk waste’’ DOC and 

k values are representative of typical or 

average MSW landfill operations in the 

U.S. However, we also acknowledge that 

there is significant variability in the 

methane generation rates (per ton of 

waste disposed) at individual landfills. 

We provided the waste composition 

option to account for this variability, but 

this option needs a default value for 

inert materials in order to be more 

comprehensive and therefore reflective 

of waste composition at U.S. landfills. 

With regard to the bulk waste option, 

which is applicable when a landfill 

cannot breakdown their waste quantities 

at all, it is not appropriate to allow the 

use of inert default parameters, because 

values provided for this option already 

consider that there will be some amount 

of inerts in the overall waste quantity. 

Therefore, this option remains as it 

appeared in the October 2009 Final rule. 

However, we consider it reasonable to 

provide an alternative bulk MSW option 

that allows landfills to characterize their 

waste quantities into categories that the 

MSW landfill industry more typically 

monitors and records. We reviewed 

available MSW waste characterization 

data to develop default bulk MSW 

model parameters excluding inerts and 

C&D wastes, and determined that an 

appropriate DOC value for this waste 

category is 0.31 with a k value similar 

to that for bulk waste. Therefore, we 

have included in the final rule an 

additional option for characterizing 

waste materials. In this ‘‘bulk MSW’’ 

option, there are three waste categories: 

bulk MSW excluding inerts and C&D 

wastes; inert wastes; and C&D wastes. 

This new option provides a means for 

individual landfills to better estimate 

the methane generation rates to account 

for significant quantities of inert 

materials or C&D wastes without 

needing to classify the wastes into the 

detailed categories of the waste 

composition option. For more 

information on the bulk MSW option, 

please see ‘‘Modified Bulk MSW 

Option’’ in docket EPA–HQ–OAR– 

2010–0109. 

Given these amendments to Table 

HH–1 to subpart HH, we are also 

revising the reporting requirements in 

40 CFR 98.346(c) to clarify that the 

waste compositions should be reported 

only for the waste categories in Table 

HH–1 to subpart HH that are used in the 

calculation of methane generation using 

Equation HH–1 of subpart H. This 

amendment is needed to avoid 

confusion with the ‘‘municipal’’ category 

currently listed in 40 CFR 98.346(c) and 

the bulk waste and bulk MSW 

categories. 

Comment: A few commenters 

indicated that the amendment to the 

Table HH–1 to subpart HH regarding 

leachate recirculation imposes 

substantial new data collection 

requirements that would require 

significant operational changes to 

implement. According to the 

commenters, most landfills that 

recirculate leachate do not measure and 

track the volume that is recirculated 

during each event and would not be 

able to provide these data for the 2010 

calendar year. Furthermore, the 

commenter suggested that landfills 

would incur significant expense to 

install appropriate leachate 

measurement devices and ancillary 

equipment for a nominal impact on 

landfill GHG emissions calculation 

accuracy. 

Response: We proposed the 

modifications to Table HH–1 to subpart 

HH to address questions that arose 

concerning the use of the highest k 

value in the range when leachate 

recirculation was used sporadically or 

only in limited amounts. We did not 

specify any monitoring requirements for 

the quantity of leachate recirculated; we 

anticipated that most landfills would 

use company records or engineering 

estimates to determine the quantity of 

leachate recirculated. We have revised 

the first footnote to Table HH–1 to 

subpart HH to clarify this point. 

Additionally, we have revised the 

footnotes to allow facilities to use the 

highest k value in the range when 

leachate recirculation is used. As such, 

the final amendments are effectively 

equivalent to those proposed, but give 

reporters some flexibility to use highrange default k values if leachate 

recirculation is used, but leachate 

recirculation rates are unknown or 

otherwise not estimated. The use of the 

higher k values may overestimate 

methane generation, but it will not 

result in any additional monitoring or 

reporting burden for reporters. Further, 

not all landfills use leachate 

recirculation and we expect that some of 

the landfills that do use leachate 

recirculation will have records that 

document the amount of leachate that is 

recirculated. Therefore, we expect that 

only a small subset of landfills would 

default to the higher k-value when a 

lower k-value might be more 

appropriate and that there will not be a 

significant bias in overall emissions 

from landfills. 

Comment: Several commenters 

discussed the amendments in 40 CFR 

98.343(a)(3) requiring landfills to use 

scales when scales are in-place for all 

vehicles or containers delivering waste, 

except passenger vehicles and light-duty 

pick-up truck. The commenters stated 

that this requirement is problematic 

because it is not possible to physically 

weigh all loads entering the landfill 

because their weight may exceed the 

scales’ capability or the dimensions of 

the waste may not allow the waste load 

to pass through the physical constraints 

of the scale and scale-house. Some 

commenters noted that state and local 

requirements may require accounting of 

certain waste types on a volumetric 

basis despite the landfill having scales. 

The commenters suggested that having 

to maintain two sets of records in order 

to comply with all established 

regulatory requirements is an 

unnecessary burden and contrary to 

acceptable accounting practices. One 

commenter suggested that the 

clarification to require all waste loads to 

be weighed via a scale to be a 

substantial material change because the 

final MMR could be interpreted to allow 

tipping fee receipts or company years 

for 2010 and beyond and not just direct 

measurement. The commenters 

generally recommended that 40 CFR 

98.343(a)(3) be revised so that waste 

loads can be measured by using either 

methodologies as appropriate for the 

waste type disposed even though scales 

are present at the landfill. Some of the 

commenters suggested EPA allow 

facilities to estimate the weight/volume 

of the delivered waste material using 

methods and factors allowed or required 

by state or local agencies or other 

methods documented in the relevant 

facility’s GHG Monitoring Plan. 

Response: We originally intended that 

scales be installed and direct mass 

measurements be used for the year 2010 

and beyond; the allowance of tipping 


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6The EIA crude stream code is the numeric code 

used to identify the type of domestic crude oil in 

Form EIA–182 (Domestic Crude Oil First Purchase 

Report) and the alpha numeric code used to identify 

the type of foreign crude oil in Form EIA–856 

(Monthly Foreign Crude Oil Acquisition Report). 

7EIA country code means the two-letter code 

identifying the country associated with the alpha 

numeric crude stream codes used to identify the 

type of foreign crude oil in Form EIA–856 and is 

traditionally found in Appendix A of the form. The 

EIA state and production area code is the two-letter 

code used to identify the source of domestic crude 

oil in Form EIA–182 is traditionally found in 

Appendix A of the instructions. 

fee receipts or other company records 

was intended for years prior to the first 

emissions reporting year. While states 

and local jurisdictions may require 

measurement by volume, Equation HH– 

1 of subpart HH, which is the 

foundation for determining methane 

generation from the landfill, requires the 

waste quantity in units of mass. Section 

98.343(a)(2) of subpart HH specifically 

requires these waste quantities [in units 

of mass] to be determined daily, and 40 

CFR 98.344(a) states that ‘‘[t]he quantity 

of waste landfilled must be determined 

using mass measurement equipment 

***’’ EPA answered numerous 

questions regarding this requirement 

and communicated the above 

interpretation to the industry in 

webinars and other outreach materials. 

Consequently, we do not consider the 

proposed amendments in 40 CFR 

98.343(a)(3) to be a substantial material 

change in the requirements of the rule 

published on October 30, 2009. 

However, we recognize that some 

reporters did not believe that the rule 

language was explicit with respect to 

these requirements. Additionally, we 

reconsidered our original position that 

scales must be installed. The proposed 

amendments addressed both of these 

issues. 

We had not considered that there 

would be physical limitations to 

accessing the scale. We also anticipated 

that the scales would cover the range of 

sizes and weights received at the site. 

As we no longer require the installation 

of permanent scales at a facility, we 

certainly do not intend to require 

facilities to have to replace existing 

scales to accommodate unusually sized 

or heavy loads. As such, we conclude 

that it is reasonable to allow facilities to 

use the methods in 40 CFR 

98.343(a)(3)(ii) for certain waste loads 

even though scales are present at the 

facility. However, because the mass of 

waste is a critical input to Equation HH– 

1 and we desire accurate measurements 

of this waste, the methods outlined in 

40 CFR 98.343(a)(3)(ii) are limited to 

waste loads that cannot be measured 

using the scales due to physical and 

operational limitations of the scale. 

Physical limitations refers to the shape 

or size of the load so that it cannot 

access the scale or does not fit on the 

scale. Operational limitations refers to 

the weight of the load exceeding the 

limits or sensitivity range of the scale. 

Operational limitations are not intended 

to consider waiting times to access the 

scale. For all other types of waste loads 

(other than passenger vehicles or light 

duty trucks), the direct mass 

measurement methods in 40 CFR 

98.343(a)(3)(i) must be used. 

Q. Subpart LL—Suppliers of Coal-Based 

Liquid Fuels 

1. Summary of Final Amendments and 

Major Changes Since Proposal 

First, we are amending 40 CFR 

98.386(a)(5) and (6) to clarify that fossilfuel products that enter the facility will 

not be reported when exiting the facility 

if they are not further refined or 

otherwise used on site (e.g. products 

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

that such products be reported. 

Second, we are amending 40 CFR 

98.386(a)(3), (a)(7), (b)(3), and (c)(3) to 

harmonize the reporting requirements 

with the amendments in 40 CFR 98.393 

of today’s rule to account for denaturant 

in ethanol. Third, we are replacing a 

comma with the words ‘‘that were’’ in 40 

CFR 98.386(a)(16) and (a)(17) and 

adding a paragraph at 40 CFR 98.386(d) 

to harmonize the reporting requirements 

with the amendment in 40 CFR 

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

optional method for calculating GHG 

emissions from blended feedstock and 

products. Since subpart LL reporters 

follow subpart MM methodologies for 

calculating GHG emissions, these 

amendments are necessary to ensure 

complete reporting of subpart LL data. 

2. Summary of Comments and 

Responses 

EPA did not receive any comments on 

the proposed amendments to subpart LL 

and is finalizing the amendments to this 

subpart as proposed. 

R. Subpart MM—Suppliers of Petroleum 

Products 

1. Summary of Final Amendments and 

Major Changes Since Proposal 

We are adding a definition of ‘‘batch’’ 

in 40 CFR 98.398 to clarify the crude oil 

reporting requirements in 40 CFR 

98.396(a)(20) and to minimize 

administrative burden. Under this final 

rule, a batch of crude oil means either 

a volume that enters a refinery or a 

component of such volume (e.g., the 

volumes of different crude streams that 

are blended together and then delivered 

to a refinery). The batch volume is 

dependent upon what a refiner knows 

about the crude oil it receives and is the 

first appropriate tier in the following 

list: 

(1) Up to an annual volume of a type 

of crude oil identified by an EIA crude 

stream code,6 if the EIA crude stream 

code is known. 

(2) Up to an annual volume of a type 

of crude oil identified by a generic name 

for the crude stream and an appropriate 

EIA two-letter country or state and 

production area code 7 if the generic 

name and EIA two-letter code are 

known but no appropriate EIA crude 

stream code exists. 

(3) Up to a calendar month volume 

from a single known foreign country of 

origin if the crude stream name is 

unknown. 

(4) Up to a calendar month volume 

from the United States if the crude 

stream name and production area are 

unknown. 

(5) Up to a calendar month volume if 

the country of origin is unknown. 

For example, if refiners know the EIA 

crude stream code of a volume of crude 

oil that they receive, they must report 

the API gravity and sulfur content of up 

to an annual volume of this type of 

crude oil. If refiners only know the 

country of origin of a volume of foreign 

crude oil (but not the crude stream 

name), they must report the API gravity 

and sulfur content of up to a calendar 

month volume from that country. 

For data collection in 2010 only, a 

refiner that knows the information that 

we require them to report under a 

specific tier of the batch definition, but 

does not have the necessary data 

collection and management in place to 

readily report this information, can use 

the next most appropriate tier of the 

batch definition for reporting batch 

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

With this definition of ‘‘batch’’, we are 

requiring refiners to report on crude oil 

volumes in 40 CFR 98.396(a)(20) using 

the best data they are collecting as part 

of normal business practices. For 

example, refiners must use data on the 

American Petroleum Institute (API) 

gravity and sulfur content of crude oil 

that they, or a third party, currently 

collect as part of normal business 

practices, including data refiners use to 

report monthly weighted average API 

gravity and sulfur content to EIA. As 

another example, refiners must use data 

that they currently collect on the EIA 

crude stream code or country of origin 

for the components of a blended crude 

oil. 


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We are making harmonizing 

amendments to 40 CFR 98.396(a)(20) to 

allow refiners to report the country of 

origin, EIA crude stream code and 

name, or the generic name of the crude 

stream and associated production area 

code for a given batch as appropriate, if 

known. 

To better align the API gravity and 

sulfur content reporting requirements 

with normal business practices, we are 

also amending the recordkeeping 

requirements in 40 CFR 98.397 so that 

refiners will no longer be required to 

maintain laboratory reports, calculations 

and worksheets used in the 

measurement of API gravity and sulfur 

content of crude oil. Instead, refiners 

must maintain sufficient records to 

support the information they report to 

EPA (as required by 40 CFR 98.397(a) 

and (b)). 

We are also amending 40 CFR 

98.394(d) and 40 CFR 98.396(a)(20) to 

clarify that we are seeking the weighted 

average API gravity and sulfur content 

from representative samples of each 

batch. 

To ensure that refiners can report 

readily available data in 40 CFR 

98.386(a)(20) on the volume and 

associated characteristics of components 

of a blended crude oil, we are amending 

the requirements for determining 

quantity of crude oil in 40 CFR 

98.394(a)(1) so that they only apply to 

volumes of crude oil that refiners 

measure on site (e.g., the total volume 

rather than the components of such 

volume). Refiners may now use an 

industry standard practice to determine 

volumes of crude oil that are not 

measured on site, even if an appropriate 

standard method published by a 

consensus-based standards organization 

exists, as specified in a new paragraph, 

40 CFR 98.394(a)(3). We are also 

amending the recordkeeping 

requirements associated with quantity 

determination in 40 CFR 98.397(b) so 

that refiners will not be required to 

maintain metering and gauging records 

for quantities of crude oil that they do 

not measure on site, including the date 

of initial calibration and frequency of 

recalibration for associated 

measurement equipment. We are also 

amending 98.394(d) to give refiners the 

option of following an industry standard 

practice to measure API gravity and 

sulfur content of crude oil. 

We are amending the definition of 

Producti (annual volume of product ‘‘i’’ 

produced, imported, or exported) in 

Equation MM–1 in 40 CFR 98.393(a)(1) 

and (2) to make it clear that GHG 

emissions should not be calculated for 

products leaving the refinery if those 

products had entered the refinery but 

were not further refined or otherwise 

used on site (e.g., products stored in a 

tank). As a harmonizing change, we are 

amending 40 CFR 98.396(a)(5) and (6) to 

clarify that these products are not 

reported. 

We are amending the procedure in 40 

CFR 98.393(f)(1) for calculating 

emission factors for solid products 

when using Calculation Method 1. The 

amendments will clarify that reporters 

should multiply the default carbon 

share factor in column B of Table MM– 

1 to subpart MM by 44/12 (the ratio of 

the molecular weight of CO2 to the 

atomic weight of carbon) to convert the 

amount of carbon in the product to CO2. 

Due to an oversight, 44/12 was not 

included in the original formula. This 

amendment is necessary because 

otherwise reporters would calculate the 

emissions of carbon instead of carbon 

dioxide. 

We are amending Equation MM–9 in 

40 CFR 98.393(h)(2) to correct a 

typographical error. The correct 

emission factor (EF) term in the 

equation is EFj not EFi. 

We are adding an optional method for 

reporters in 40 CFR 98.393(i) to 

calculate CO2 emissions that would 

result from the complete oxidation or 

combustion of a blended product or 

blended non-crude feedstock. The 

procedures in the existing rule require 

reporters to calculate CO2 emissions for 

blended products either by selecting the 

default emission factor for the product 

listed in Table MM–1 to subpart MM 

that resembles most closely the blended 

product (Calculation Method 1) or by 

sampling and testing the blended 

product (Calculation Method 2). If a 

reporter applies the former method, the 

CO2 emissions calculation for the 

blended product will likely reflect the 

CO2 content of only one blend 

component. In such a case, the CO2 from 

the blended product will not be as 

accurately accounted for in Equation 

MM–4 of subpart MM. The optional 

method we are adding allows reporters 

to account for the CO2 emissions of a 

blended product or blended non-crude 

feedstock in the summary calculation of 

total facility CO2 by calculating the 

emissions of the blend’s individual 

components using appropriate default 

factors listed in Table MM–1 to subpart 

MM. This increases flexibility for 

facilities that receive and supply blends. 

This also improves accuracy of the 

summary calculation of total refinery 

CO2 because it ensures that the same 

quantities and emission factors are used 

for blend components coming in to the 

refinery as for blended products going 

out. 

The optional method is not available 

for a product that is biomass-based 

because such biomass-based products 

are subject to paragraph (h) of 40 CFR 

98.393. 

To align the existing regulatory text 

with the optional method for blends, we 

are amending paragraphs (a)(1) and 

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

(a)(16) and (a)(17) of 40 CFR 98.396. We 

are also adding paragraph (d) of 40 CFR 

98.396 to create new data reporting 

requirements for blends. 

We are amending the calculation 

procedures in 40 CFR 98.393(h) for 

blended biomass-based fuels. Part 98 (as 

finalized in 70 CFR 56260, October 30, 

2009) directed refineries that supply a 

petroleum product that was produced 

by blending a petroleum-based product 

with denatured ethanol to report 

emissions from the denaturant leaving 

the refinery but not the denaturant in 

the ethanol that enters the refinery as a 

feedstock. This resulted in overreporting of GHG emissions across 

subpart MM reporters because the 

blending refinery accounted for the CO2

from denaturant in its GHG emissions 

calculation even though the original 

refinery that produced the denaturant 

ex-refinery gate already accounted for 

the CO2 in its GHG emission 

calculation. To address the overreporting for refineries using 

Calculation Method 1 for petroleum 

products or non-crude petroleum 

feedstocks that contain denatured 

ethanol, we are amending Equations 

MM–8 and MM–9 of subpart MM to 

exclude denaturant from the term 

‘‘%vol’’, respectively. 

To address this over-reporting for 

refineries using Calculation Method 2 

for petroleum products that were 

produced by blending a petroleumbased product with denatured ethanol 

on site, we are adding a new Equation 

MM–10a of subpart MM. Equation MM– 

10a requires 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. This new equation is 

necessary and Equation MM–10 is 

incorrect for such situations because the 

term for the biomass default emission 

factor in Equation MM–10 is applied to 

the whole volume of biomass received 

for blending (which for ethanol includes 

denaturant), even though the default 

factor for ethanol does not account for 

denaturant. We are splitting 40 CFR 

98.393(h)(3) into paragraphs (i) and (ii) 

so that Equation MM–10 remains in (i) 

for petroleum products blended with 


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biomass other than denatured ethanol 

while Equation MM–10a appears in (ii) 

for petroleum products blended with 

denatured ethanol. We are amending 

Equation MM–10 to exclude denaturant 

from the term ‘‘%vol.’’ 

Together, these amendments ensure 

that the denaturant present in ethanol is 

not accounted for in the calculation of 

CO2 that would result from the complete 

combustion or oxidation of the 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 we would expect any 

denaturant in ethanol that enters the 

refinery in a feedstock to leave the 

refinery in a product and therefore the 

CO2 emissions from the denaturant 

would be a net of zero. 

We cannot identify a situation, nor 

did any commenters, in which a 

refinery would want to use Calculation 

Method 2 for a non-crude feedstock that 

contains denatured ethanol or an 

importer or exporter would want to use 

Calculation Method 2 for products 

containing denatured ethanol. 

Therefore, we are splitting 40 CFR 

98.393(h)(4) into paragraphs (i) and (ii) 

so that Equation MM–11 of subpart MM 

remains in (i) for non-crude feedstocks 

blended with biomass other than 

denatured ethanol while directions to 

use Calculation Method 1 appear in (ii) 

for non-crude feedstocks blended with 

denatured ethanol by refineries. We are 

also adding directions in 40 CFR 

98.393(h)(3)(ii) for importers and 

exporters of petroleum products 

blended with denatured ethanol to use 

Calculation Method 1. We are amending 

Equation MM–11 to exclude denaturant 

from the term ‘‘%vol.’’ 

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

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

reporting requirements with the 

amendments to account for denaturant 

in ethanol. 

Major changes since the proposal are 

identified in the following list. The 

rationale for these and any other 

significant changes can be found in 

Response to Comments: Technical 

Corrections, Clarifying and Other 

Amendments (see EPA–HQ–OAR– 

2010–0109). 

• We expanded on the proposed definition 

of ‘‘batch’’ to require refiners to report up to 

an annual volume of a type of crude oil 

identified by an EIA crude stream code (or 

the generic crude stream name and 

production area code if no appropriate EIA 

crude stream code exists) if refiners know 

this information. If refiners do not know this 

information, refiners must report according 

to the proposed definition of batch (e.g., up 

to a calendar month volume from a single 

country of origin or, if refiners do not know 

the country of origin, up to a total calendar 

month volume). 

• We clarified that ‘‘batch’’ can mean either 

the volume that enters a refinery or the 

components of such volume. We amended 40 

CFR 98.394(a) to allow refiners to use 

industry standard practices to determine 

crude oil volumes that they do not measure 

on site, rather than standard methods 

published by a consensus-based standard, if 

desired. We also amended the recordkeeping 

requirements associated with quantity 

determination in 40 CFR 98.397(b) so that 

refiners are not required to maintain metering 

and gauging records for quantities of crude 

oil that they do not measure on site. 

• We amended 40 CFR 98.394(d) to allow 

refiners to use industry standard practices to 

measure API gravity and sulfur content of 

crude oil, rather than standard methods 

published by a consensus-based standards 

organization, if desired. 

• For reporting year 2010 only, we are 

providing reporters some flexibility in 

defining a batch of crude oil. A refiner that 

knows the information under a specific tier 

of the batch definition, but does not have the 

necessary data collection and management in 

place to readily report this information, can 

use the next most appropriate tier of the 

batch definition for reporting batch 

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

• As a harmonizing amendment with the 

final definition of crude oil (as discussed in 

Section II.B, Subpart A—General Provisions, 

of this preamble), we added a reporting 

requirements for refineries in 40 CFR 

98.396(a). Refiners are now required to report 

on the volume of crude oil that they inject 

into a crude supply or reservoir under a new 

paragraph (22). 

2. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. 

Several comments were received on this 

subpart. Responses to additional 

significant comments received can be 

found in Response to Comments: 

Technical Corrections, Clarifying and 

Other Amendments (see EPA–HQ– 

OAR–2010–0109). 

Comment: We received three 

comments related to our proposed 

amendments regarding the treatment of 

denatured ethanol. Two comments 

supported the proposed change. The 

third commented that reporting of 

gasoline-ethanol blends (i.e., a 

petroleum product that contains 

denatured ethanol and is a blended 

biomass-based fuel) was burdensome 

and suggested that only the petroleum 

portion of these blends should be 

reported. That commenter stated that 

the blending of ethanol with gasoline 

should not be considered ‘‘to be further 

refined or otherwise used on site’’ (40 

CFR 98.396(a)(1)) and that therefore, 

ethanol should not have to be reported. 

Response: We are finalizing our 

proposed amendments related to 

denaturant in ethanol in today’s rule. 

When finalizing subpart MM, (74 FR 

56260, October 30, 2009), EPA 

concluded that reporting the total 

volume of gasoline-ethanol blends ex 

refinery gate as well as the percentage 

of that volume that is petroleum-based 

is not unnecessarily burdensome to 

reporters. The changes to 40 CFR Part 

98.396(a) that would be necessary to 

remove biomass reporting as suggested 

by the commenter are outside the scope 

of the specific amendments proposed 

for public comment in the Federal 

Register notice of June 15, 2010. The 

proposed changes to 40 CFR 98.396(a) 

only addressed how the denaturant in 

ethanol should be treated, and EPA did 

not seek comment on removing 

reporting on biomass entirely. 

As a result of the comments we 

received, we have concluded that there 

has been confusion regarding how 

ethanol should be reported when it 

leaves the facility. When ethanol leaves 

a facility covered by subpart MM, it is 

generally being blended with finished 

gasoline as it is being loaded into a 

truck. We are clarifying here that EPA 

considers the ethanol and the gasoline 

to be leaving the facility separately if 

they are leaving through different 

‘‘spigots’’ and being blended in the truck. 

Under these circumstances, there is no 

gasoline-ethanol blend on site at the 

facility. The gasoline is the petroleum 

product that must be reported as leaving 

the facility. The denatured ethanol is 

not part of a petroleum product leaving 

the facility and, as a result of the 

technical correction being made in this 

rule for how to treat the denaturant in 

ethanol, need not be reported as 

entering or leaving the facility under 

these circumstances. 

The phrase ‘‘to be further refined or 

otherwise used on site’’ only applies to 

petroleum products, including blended 

biomass-based fuels, and natural gas 

liquids. EPA has clarified through 

guidance that a petroleum product or 

natural gas liquid that stays in the same 

container or vessel while on site and 

that is not blended with any other 

product is not ‘‘otherwise used on site’’ 

and that blending is considered 

‘‘otherwise used on site’’. If refiners 

blend ethanol with a petroleum product 

on site—for example, a refiner blends 

gasoline and ethanol on site and stores 

the blend in a tank before it leaves the 

facility—then the total volume of the 

ethanol-gasoline blend as well as the 

percentage of that volume that is 

petroleum-based must be reported when 

the blend leaves the facility. The 


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volume of ethanol entering the facility 

need not be reported. 

Comment: In the proposal, we sought 

comment on defining a ‘‘batch’’ to help 

clarify crude oil reporting requirements 

in 40 CFR 98.396(a)(20) and reduce 

administrative burden, while continuing 

to collect adequate crude oil data to 

support the purposes of subpart MM. 

We received several comments on our 

proposed definition of batch and 

potential alternatives. One commenter 

supported defining a batch as the 

annual volume of a type of crude oil 

characterized by an EIA crude stream 

code (rather than monthly volumes) if 

EPA maintains the requirement to report 

API gravity, sulfur content, and country 

of origin of crude oil. One commenter 

expressed support for the proposed 

definition of batch but cautioned that it 

would limit refiners to report the 

country of origin as ‘‘unknown’’ when 

the crude oil batch is a blend of crude 

oil from several known countries. The 

commenter therefore advised EPA to 

allow refiners to report on the 

components in a crude oil blend and to 

amend the quantity determination 

requirements so that refiners can use 

information obtained from normal 

business practices on blend component 

volumes. The commenter further opined 

that, similar to the problem of reporting 

a single country of origin, refiners 

receiving a crude oil blend would be 

unable to report a single EIA crude 

stream code. Therefore the commenter 

recommended that EPA include annual 

crude volumes by EIA crude stream 

codes in the definition of batch only if 

it is presented as one of multiple 

options. Two commenters advocated 

that EPA limit the definition of batch to 

the annual volume of each EIA crude 

stream code category and remove the 

requirement to report API gravity, sulfur 

content, and country of origin for every 

batch. One commenter expressed 

concern about limiting the definition of 

batch to the annual volume of each EIA 

crude stream code category if it means 

losing data on API gravity. That 

commenter urged EPA to require 

refiners to report the sample data they 

already collect for EIA reporting. The 

commenter also asked that EPA define 

‘‘batch’’ in a way that captures the 

differences in crude oil originating from 

the same country since different crude 

streams from the same country can have 

different API gravity and sulfur 

contents. 

Response: In today’s rule we are 

finalizing a definition of ‘‘batch’’ that 

builds on our proposed definition by 

adding two additional features. First, we 

are requiring refiners to define a batch 

as up to an annual volume of a type of 

crude oil identified by an EIA crude 

stream code (or a generic crude stream 

name and production area code) if 

refiners know this information. Second, 

we are defining batch as either the total 

volume of crude oil that enters a 

refinery or the components of such 

volume so that refiners will be able to 

report representative data they currently 

collect on all three crude parameters— 

(1) API gravity, (2) sulfur content, and 

(3) country of origin or crude stream 

name and production area—for the 

components in a blended crude volume 

instead of having to report the third 

parameter as unknown. These 

amendments were generally supported 

by commenters and we concluded that 

they would result in better data and be 

less burdensome than the proposed 

definition. 

With regard to comments on defining 

a batch as a monthly versus annual 

volume of crude, we determined that 

API gravity and sulfur content of 

specific crude streams do not vary 

enough to warrant requiring batch to be 

defined as only up to a monthly volume. 

On the other hand, API gravity and 

sulfur content can vary significantly 

between different crude streams coming 

from the same country of origin (or 

multiple countries of origin). Therefore, 

we determined that monthly reporting 

outlined in the proposed definition of 

‘‘batch’’ would be necessary in those 

cases where refiners only know the 

country of origin of their crude volume 

(rather than the crude stream name and 

production area) or when they do not 

know the country of origin. We did not 

conclude that reporting batches more 

frequently than a monthly basis would 

be necessary in any situation. 

We considered eliminating the 

requirement that refiners report API 

gravity and sulfur content if they report 

the EIA crude stream code associated 

with the batch, but we determined that 

there were too many EIA crude stream 

codes without corresponding API 

gravity and sulfur content values and 

that even when present these values, 

while illustrative, were based on limited 

information and would not always be 

representative of the characteristics of 

the crude oil used at a refinery. 

Furthermore, refiners already collect 

data on the API gravity and sulfur 

content of their crude oil in order to 

report this information to EIA on a 

monthly basis, and it is our 

understanding, based on an industry 

comment, that refiners also track this 

information to determine how well the 

physical characteristics of the crude oil 

align with the processing capability of 

their refineries. 

Comment: In the proposal, we sought 

comment on other technical 

amendments (besides defining ‘‘batch’’) 

that would help clarify crude oil 

reporting requirements in 40 CFR 

98.396(a)(20) and reduce administrative 

burden. In particular, we sought 

comment on ways to better align the 

provisions related to crude oil reporting 

with normal business practices. 

We received two comments with 

input on ways to better align the 

monitoring and QA/QC provisions 

related to crude oil reporting with 

normal business practices. According to 

the two commenters, it is normal 

business practice for refiners to 

maintain data on crude batch volumes 

and other parameters required in 40 

CFR 98.396(a)(20). They described a 

number of different sources they use to 

identify the sulfur content and API 

gravity of crude oil batches (including 

components of blended crude oil 

volumes) such as grab samples, contract 

laboratory records, crude assay reports, 

invoices, and pipeline receipt tickets. 

They explained that the data contained 

in these sources are often collected 

outside of the refinery under normal 

business practices, which may be 

inconsistent with the current 

requirements in the rule to use standard 

methods to measure these data 

(resulting in the need to collect the data 

again inside the refinery). In addition, 

one of the two commenters explained 

that they maintain data on the 

components of blended crude volumes 

but they may not be able to determine 

the volume of the components of 

blended crude according to the quantity 

determination requirements in 40 CFR 

98.394(a)(1) since the components arrive 

at the refinery already blended. 

Therefore, they will be forced to report 

the total volume of the blended crude 

oil and the country of origin (or EIA 

crude stream code) as ‘‘unknown’’ even 

though they know information about the 

volume components. 

We also received two comments in 

support of the proposed elimination of 

recordkeeping requirements in 40 CFR 

98.397 related to the measurement of 

API gravity and sulfur content of crude 

oil because it would support the use of 

data collected in normal business 

records. We received one comment that 

objected to EPA’s deletion of specific 

recordkeeping requirements for API 

gravity and sulfur content 

measurements on the basis that these 

records were important verification 

tools. 

Response: In response to comments, 

we are retaining our proposed 

amendment to eliminate the 

recordkeeping requirements in 40 CFR 


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98.397 related to the measurement of 

API gravity and sulfur content of crude 

oil. We are also making several 

additional amendments to improve the 

flexibility of the QA/QC and 

recordkeeping requirements in the rule 

to facilitate the reporting of similar and, 

in many cases, better quality data on 

API gravity, sulfur content, and 

geographic origin of crude oil batches 

while reducing administrative burden. 

We are amending 40 CFR 98.394(d) to 

allow refiners to use industry standard 

practices to determine the API gravity 

and sulfur content of crude oil. We are 

amending the quantity determination 

monitoring and QA/QC requirements in 

40 CFR 98.394(a) so that refiners can use 

industry standard practices to determine 

the volume of components of a blended 

crude batch (which are never directly 

measured on site at a refinery). 

Therefore, refiners will be able to report 

representative data they currently 

collect on all three crude parameters— 

(1) API gravity, (2) sulfur content, and 

(3) country of origin or crude stream 

name and production area—of the 

components in a blended crude volume 

instead of having to report the third 

parameter as unknown. We are also 

making a harmonizing amendment to 40 

CFR 98.397(b) to eliminate the 

requirement that refiners maintain 

metering and gauging records for crude 

oil batch volumes that they do not 

measure on site. Together, these 

amendments will allow refiners to 

report crude characteristics contained in 

crude assay reports, third party 

laboratory reports, or pipeline receipt 

tickets if the characteristics are 

representative of the crude oil used at 

the refinery and it is an industry 

standard practice to use these sources. 

We have determined that these 

amendments will still ensure that the 

data refiners report is adequately 

representative of the crude oil they 

receive at the refinery and that the 

records they keep will be sufficient to 

support EPA verification of the data. We 

made this determination in light of the 

fact that crude oil data is not used to 

calculate the CO2 emissions reported 

under subpart MM. 

Comment: We sought comment on our 

proposed timeline of implementing the 

technical amendments to subpart MM 

for the 2010 reporting year and whether 

this timeline was appropriate 

considering the nature of the proposed 

changes and/or the way in which data 

have been collected thus far in 2010. We 

received one comment indicating that 

defining ‘‘batch’’ in a manner that would 

require monthly reporting of crude oil 

volumes may necessitate modifications 

to current refinery sampling and 

monitoring practices and that refiners 

may not be able to provide this 

information by the March 31, 2011 

reporting deadline for 2010 data. 

Response: While data collection 

methods may vary by refinery, we have 

determined that refiners currently 

collect data as part of normal business 

practices on the API gravity and sulfur 

content for at least one of the five tiers 

described in the definition of ‘‘batch’’ in 

today’s rule and should therefore be 

able to meet the crude oil reporting 

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

a timely manner. However, since we did 

not include a definition of ‘‘batch’’ in the 

final rule (74 FR 56260), refiners may 

not have established data collection and 

management systems in 2010 to link the 

information they collect on API gravity, 

sulfur content, and volumes of crude 

batches to an EIA crude stream code or 

generic crude stream name and 

production area code (i.e., tiers 1 and 2 

of the ‘‘batch’’ definition). Likewise, 

refiners may not have had adequate time 

to link data they collect on API gravity 

and sulfur content from crude coming 

from a single country of origin to ‘‘up to 

a calendar month volume’’ (i.e., tiers 3 

and 4 of the ‘‘batch’’ definition). We are 

therefore providing refiners the 

flexibility to report at a lower tier for 

reporting year 2010 if they do not have 

appropriate data collection and 

management systems in place to readily 

report the information in the higher tier. 

S. Subpart NN—Suppliers of Natural 

Gas and Natural Gas Liquids 

1. Summary of Final Amendments and 

Major Changes Since Proposal 

We are amending the definition of the 

term ‘‘Fuelh’’ in Equation NN–1 of 

subpart NN to clarify that the 

abbreviation ‘‘Mscf’’ refers to ‘‘thousand 

standard cubic feet’’ in order to avoid 

confusion on if this abbreviation means 

‘‘million standard cubic feet’’. We are 

also adding the subscript ‘‘h’’ to the 

terms for Fuel and HHV in Equation 

NN–1. 

We are amending the definition of the 

term ‘‘EF’’ in Equation NN–7 of subpart 

NN to clarify that the emission factor is 

for each natural gas liquid (NGL) 

product ‘‘g’’ and to add the subscript ‘‘g’’ 

to the term ‘‘EF.’’ 

We are amending Equation NN–8 of 

subpart NN to correct the term for 

‘‘Annual CO2 mass emissions that would 

result from the combustion or oxidation 

of fractionated NGLs received from 

other fractionators’’ from ‘‘CO2j’’ to 

‘‘CO2m’’. We are also amending Equation 

NN–8 to remove the summation signs 

that were unnecessary from this 

equation for clarification purposes. We 

are also amending the definition of the 

term CO2i to clarify that this term 

includes NGLs delivered to customers 

or, on behalf of, customers, recognizing 

that some customers may not receive the 

NGLs directly. 

We are amending 40 CFR 98.406(a)(6) 

to correct two cross references. The 

incorrect references referred the reader 

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

they were supposed to refer to 40 CFR 

98.406(a)(1) and (a)(2). Similarly, we are 

amending an incorrect reference in 40 

CFR 98.407(d) to refer the reader to 40 

CFR 98.406(b)(7) instead of 40 CFR 

98.406(b)(6). 

We are amending 40 CFR 98.406(a)(9) 

to correct the abbreviation of NGL (from 

LNG) and to specify that reporting 

under that paragraph is for each product 

type. 

We are amending 40 CFR 98.407(a) to 

remove the word ‘‘daily’’ because daily 

meter readings are not specifically 

required under this subpart. 

Finally, we are updating the high heat 

values (HHVs) and default CO2 emission 

factors in Tables NN–1 and NN–2 to 

subpart NN to be consistent with the 

emission factors in Tables C–1 to 

subpart C and MM–1 to subpart MM. 

2. Summary of Comments and 

Responses 

There were no major comments 

received on the proposed amendments 

to this section. A few comments seeking 

minor technical clarification or 

correction were received on this 

subpart. Responses to these comments 

can be found in Response to Comments: 

Technical Corrections, Clarifying and 

Other Amendments document (see 

EPA–HQ–OAR–2010–0109). 

III. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review 

This action is not a ‘‘significant 

regulatory action’’ under the terms of 

Executive Order 12866 (58 FR 51735, 

October 4, 1993) and is therefore not 

subject to review under the executive 

order. 

B. Paperwork Reduction Act 

This action does not impose any new 

information collection burden. These 

amendments do not make any 

substantive changes to the reporting 

requirements in any of the subparts for 

which amendments are being made. In 

many cases, the amendments to the 

reporting requirements reduce the 

reporting burden by making the 

reporting requirements conform more 


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closely to current industry practices. 

However, the Office of Management and 

Budget (OMB) has previously approved 

the information collection requirements 

contained in the regulations 

promulgated on October 30, 2009, under 

40 CFR Part 98 under the provisions of 

the Paperwork Reduction Act, 44 U.S.C. 

3501 et seq. and has assigned OMB 

control number 2060–0629. Burden is 

defined at 5 CFR 1320.3(b). An agency 

may not conduct or sponsor, and a 

person is not required to respond to, a 

collection of information unless it 

displays a currently valid OMB control 

number. The OMB control numbers for 

EPA’s regulations in 40 CFR are listed 

in 40 CFR part 9. 

Further information on EPA’s 

assessment on the impact on burden can 

be found in the Technical Corrections 

and Amendments Cost Memo (EPA– 

HQ–OAR–2010–0109). 

C. Regulatory Flexibility Act (RFA) 

The RFA generally requires an agency 

to prepare a regulatory flexibility 

analysis of any rule subject to notice 

and comment rulemaking requirements 

under the Administrative Procedure Act 

or any other statute unless the agency 

certifies that the rule will not have a 

significant economic impact on a 

substantial number of small entities. 

Small entities include small businesses, 

small organizations, and small 

governmental jurisdictions. 

For purposes of assessing the impacts 

of these amendments on small entities, 

small entity is defined as: (1) A small 

business as defined by the Small 

Business Administration’s regulations at 

13 CFR 121.201; (2) a small 

governmental jurisdiction that is a 

government of a city, county, town, 

school district or special district with a 

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

a small organization that is any not-forprofit enterprise which is independently 

owned and operated and is not 

dominant in its field. 

After considering the economic 

impacts of these rule amendments on 

small entities, I certify that this action 

will not have a significant economic 

impact on a substantial number of small 

entities. The rule amendments will not 

impose any new requirement on small 

entities that are not currently required 

by Part 98 promulgated on October 30, 

2009 (i.e., calculating and reporting 

annual GHG emissions). 

EPA took several steps to reduce the 

impact on small entities. For example, 

EPA determined appropriate thresholds 

that reduced the number of small 

businesses reporting. In addition, EPA 

did not require facilities to install CEMS 

if they did not already have them. 

Facilities without CEMS can calculate 

emissions using readily available data or 

data that are less expensive to collect 

such as process data or material 

consumption data. For some source 

categories, EPA developed tiered 

methods that are simpler and less 

burdensome. Also, EPA required annual 

instead of more frequent reporting. 

Finally, EPA continues to conduct 

significant outreach on the mandatory 

GHG reporting rule and maintains an 

‘‘open door’’ policy for stakeholders to 

help inform EPA’s understanding of key 

issues for the industries. 

D. Unfunded Mandates Reform Act 

(UMRA) 

This action contains no Federal 

mandates under the provisions of Title 

II of the Unfunded Mandates Reform 

Act of 1995 (UMRA), 2 U.S.C. 1531– 

1538 for State, local, or tribal 

governments or the private sector. The 

action imposes no enforceable duty on 

any State, local or tribal governments or 

the private sector. In addition, EPA 

determined that the rule amendments 

contain no regulatory requirements that 

might significantly or uniquely affect 

small governments because the 

amendments will not impose any new 

requirements that are not currently 

required by Part 98 promulgated on 

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

reporting annual GHG emissions), and 

the rule amendments will not unfairly 

apply to small governments. Therefore, 

this action is not subject to the 

requirements of CAA section 203 of the 

UMRA. 

E. Executive Order 13132: Federalism 

This action does not have federalism 

implications. It will not have substantial 

direct effects on the States, on the 

relationship between the national 

government and the States, or on the 

distribution of power and 

responsibilities among the various 

levels of government, as specified in 

Executive Order 13132. However, for a 

more detailed discussion about how 

these rule amendments will relate to 

existing State programs, please see 

Section II of the proposal preamble for 

the Mandatory GHG Reporting Rule (74 

FR 16457–16461, April 10, 2009). 

These amendments apply directly to 

facilities that supply fuel that when 

used emit greenhouse gases or facilities 

that directly emit greenhouses gases. 

They do not apply to governmental 

entities unless the government entity 

owns a facility that directly emits 

greenhouse gases above threshold levels 

(such as a landfill), so relatively few 

government facilities will be affected. 

This regulation also does not limit the 

power of States or localities to collect 

GHG data and/or regulate GHG 

emissions. Thus, Executive Order 13132 

does not apply to this action. 

Although section 6 of Executive Order 

13132 does not apply to this action, EPA 

did consult with State and local officials 

or representatives of State and local 

governments in developing Part 98. A 

summary of EPA’s consultations with 

State and local governments is provided 

in Section VIII.E of the preamble to Part 

98 (74 FR 56260, October 30, 2009). 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

This action does not have tribal 

implications, as specified in Executive 

Order 13175 (65 FR 67249, November 9, 

2000). The rule amendments will not 

result in any changes to the 

requirements of Part 98. Thus, Executive 

Order 13175 does not apply to this 

action. 

Although Executive Order 13175 does 

not apply to this action, EPA sought 

opportunities to provide information to 

Tribal governments and representatives 

during the development of the rules 

promulgated on October 30, 2009. A 

summary of the EPA’s consultations 

with Tribal officials is provided 

Sections VIII.E and VIII.F of the 

preamble to the 2009 Final Mandatory 

GHG Reporting Rule (74 FR 56260, 

October 30, 2009). 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

EPA interprets Executive Order 13045 

(62 FR 19885, April 23, 1997) as 

applying only to those regulatory 

actions that concern health or safety 

risks, such that the analysis required 

under section 5–501 of the executive 

order has the potential to influence the 

regulation. This action is not subject to 

Executive Order 13045 because it does 

not establish an environmental standard 

intended to mitigate health or safety 

risks. 

H. Executive Order 13211: Actions That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This action is not subject to Executive 

Order 13211 (66 FR 28355, May 22, 

2001), because it is not a significant 

regulatory action under Executive Order 

12866. 

I. National Technology Transfer and 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (NTTAA), Public Law 104– 

113 (15 U.S.C. 272 note) directs EPA to 


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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 rulemaking involves the use of 

one new voluntary consensus standard 

from ASTM. Specifically, EPA will 

allow facilities in the glass industry to 

use ASTM D6349–09 Standard Test 

Method for Determination of Major and 

Minor Elements in Coal, Coke, and 

Solid Residues from Combustion of Coal 

and Coke by Inductively Coupled 

Plasma—Atomic Emission Spectrometry 

in addition to the methods incorporated 

by reference in Part 98. This additional 

voluntary consensus standard will 

provide an alternative method that 

owners or operators in the glass 

industry can use to monitor GHG 

emissions. No new test methods were 

developed for this action. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order 12898 (59 FR 7629, 

February 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 Part 98 does 

not have disproportionately high and 

adverse human health or environmental 

effects on minority or low-income 

populations because it does not affect 

the level of protection provided to 

human health or the environment 

because it is a rule addressing 

information collection and reporting 

procedures. 

K. Congressional Review Act 

The Congressional Review Act, 5 

U.S.C. 801 et seq., as added by the Small 

Business Regulatory Enforcement 

Fairness Act of 1996 (SBREFA), 

generally provides that before a rule 

may take effect, the agency 

promulgating the rule must submit a 

rule report, which includes a copy of 

the rule, to each House of the Congress 

and to the Comptroller General of the 

United States. EPA will submit a report 

containing this rule and other required 

information to the U.S. Senate, the U.S. 

House of Representatives, and the 

Comptroller General of the U.S. prior to 

publication of the rule in the Federal 

Register. A major rule cannot take effect 

until 60 days after it is published in the 

Federal Register. This action is not a 

‘‘major rule’’ as defined by 5 U.S.C. 

804(2). This rule will be effective on 

November 29, 2010. 

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: October 7, 2010. 

Lisa P. Jackson, 

Administrator. 

■ For the reasons set out in the 

preamble, title 40, Chapter I, of the Code 

of Federal Regulations is amended as 

follows: 

PART 86—[AMENDED] 

■ 1. The authority citation for part 86 

continues to read as follows: 

Authority: 42 U.S.C. 7401–7671q. 

■ 2. Section 86.1844–01 is amended by 

adding paragraph (j) to read as follows: 

§ 86.1844–01 Information requirements: 

Application for certification and submittal of 

information upon request. 

* * * * * 

(j) For complete heavy-duty vehicles 

only, measure CO2, N2O, and CH4 as 

described in this paragraph (j) with each 

certification test on an emission data 

vehicle. Do not apply deterioration 

factors to the results. Use the analytical 

equipment and procedures specified in 

40 CFR part 1065 as needed to measure 

N2O and CH4. Report these values in 

your application for certification. The 

requirements of this paragraph (j) apply 

starting with model year 2011 for CO2

and 2012 for CH4. The requirements of 

this paragraph (j) related to N2O 

emissions apply for test groups that 

depend on NOX after-treatment to meet 

emission standards starting with model 

year 2013. 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.’’ 

The addition and revisions read as 

follows: 

§ 98.6 Definitions. 

* * * * * 

Carbonate-based mineral means any 

of the following minerals used in the 

manufacture of glass: Calcium carbonate 

(CaCO3), calcium magnesium carbonate 

(CaMg(CO3)2), sodium carbonate 

(Na2CO3), barium carbonate (BaCO3), 

potassium carbonate (K2CO3), lithium 

carbonate (Li2CO3), and strontium 

carbonate (SrCO3). 

Carbonate-based mineral mass 

fraction means the following: For 

limestone, the mass fraction of calcium 

carbonate (CaCO3) in the limestone; for 

dolomite, the mass fraction of calcium 

magnesium carbonate (CaMg(CO3)2) in 

the dolomite; for soda ash, the mass 

fraction of sodium carbonate (Na2CO3) 

in the soda ash; for barium carbonate, 

the mass fraction of barium carbonate 

(BaCO3) in the barium carbonate; for 

potassium carbonate, the mass fraction 

of potassium carbonate (K2CO3) in the 

potassium carbonate; for lithium 

carbonate, the mass fraction of lithium 

carbonate (Li2CO3); and for strontium 


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66458 Federal Register / Vol. 75, No. 208 / Thursday, October 28, 2010 / Rules and Regulations 

carbonate, the mass fraction of 

strontium carbonate (SrCO3). 

Carbonate-based raw material means 

any of the following materials used in 

the manufacture of glass: Limestone, 

dolomite, soda ash, barium carbonate, 

potassium carbonate, lithium carbonate, 

and strontium carbonate. 

* * * * * 

Crude oil means a mixture of 

hydrocarbons that exists in liquid phase 

in natural underground reservoirs and 

remains liquid at atmospheric pressure 

after passing through surface separating 

facilities. (1) Depending upon the 

characteristics of the crude stream, it 

may also include any of the following: 

(i) Small amounts of hydrocarbons 

that exist in gaseous phase in natural 

underground reservoirs but are liquid at 

atmospheric conditions (temperature 

and pressure) after being recovered from 

oil well (casing-head) gas in lease 

separators and are subsequently 

commingled with the crude stream 

without being separately measured. 

Lease condensate recovered as a liquid 

from natural gas wells in lease or field 

separation facilities and later mixed into 

the crude stream is also included. 

(ii) Small amounts of nonhydrocarbons, such as sulfur and 

various metals. 

(iii) Drip gases, and liquid 

hydrocarbons produced from tar sands, 

oil sands, gilsonite, and oil shale. 

(iv) Petroleum products that are 

received or produced at a refinery and 

subsequently injected into a crude 

supply or reservoir by the same refinery 

owner or operator. 

(2) Liquids produced at natural gas 

processing plants are excluded. Crude 

oil is refined to produce a wide array of 

petroleum products, including heating 

oils; gasoline, diesel and jet fuels; 

lubricants; asphalt; ethane, propane, 

and butane; and many other products 

used for their energy or chemical 

content. 

* * * * * 

Decarburization vessel means any 

vessel used to further refine molten steel 

with the primary intent of reducing the 

carbon content of the steel, including 

but not limited to vessels used for 

argon-oxygen decarburization and 

vacuum oxygen decarburization. 

* * * * * 

Gas collection system or landfill gas 

collection system means a system of 

pipes used to collect landfill gas from 

different locations in the landfill by 

means of a fan or similar mechanical 

draft equipment to a single location for 

treatment (thermal destruction) or use. 

Landfill gas collection systems may also 

include knock-out or separator drums 

and/or a compressor. A single landfill 

may have multiple gas collection 

systems. Landfill gas collection systems 

do not include ‘‘passive’’ systems, 

whereby landfill gas flows naturally to 

the surface of the landfill where an 

opening or pipe (vent) is installed to 

allow for natural gas flow. 

* * * * * 

Mscf means thousand standard cubic 

feet. 

* * * * * 

Non-crude feedstocks means any 

petroleum product or natural gas liquid 

that enters the refinery to be further 

refined or otherwise used on site. 

* * * * * 

5. Section 98.7 is amended by 

removing and reserving paragraph (a), 

and adding paragraph (e)(45). 

§ 98.7 What standardized methods are 

incorporated by reference into this part? 

* * * * * 

(e) * * * 

(45) ASTM D6349–09 Standard Test 

Method for Determination of Major and 

Minor Elements in Coal, Coke, and 

Solid Residues from Combustion of Coal 

and Coke by Inductively Coupled 

Plasma—Atomic Emission 

Spectrometry, IBR approved for 

§ 98.144(b). 

* * * * * 

Subpart E—[Amended] 

■ 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 (2) of 

this section. 

(1) Use a site-specific emission factor 

and production data according to 

paragraphs (b) through (i) of this 

section. 

(2) Request Administrator approval 

for an alternative method of determining 

N2O emissions according to paragraphs 

(a)(2)(i) and (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 (3) of this 

section. 

(1) You must conduct the test on the 

vent stream from the nitric acid 

oxidation step of the process, referred to 

as the test point, according to the 

methods specified in § 98.54(b) through 

(f). If multiple adipic acid production 

units exhaust to a common abatement 

technology and/or emission point, you 

must sample each process in the ducts 

before the emissions are combined, 

sample each process when only one 

process is operating, or sample the 

combined emissions when multiple 

processes are operating and base the 

site-specific emission factor on the 

combined production rate of the 

multiple adipic acid production units. 

(2) You must conduct the 

performance test under normal process 

operating conditions. 

(3) You must measure the adipic acid 

production rate during the test and 

calculate the production rate for the test 

period in metric tons per hour. 

(c) Using the results of the 

performance test in paragraph (b) of this 

section, you must calculate an emission 

factor for each adipic acid unit 

according to Equation E–1 of this 

section: 

EF

C Q

P

n N O,z

N O n

2

2

7

1

1 14 10

=

∗× ∗ −

∑ . 

(Eq. E-1)

Where: 

EFN2O,z = Average facility-specific N2O 

emission factor for each adipic acid 

production unit ‘‘z’’ (lb N2O/ton adipic 

acid produced). 

CN2O = N2O concentration per test run during 

the performance test (ppm N2O). 

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

N2O). 


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Federal Register / Vol. 75, No. 208 / Thursday, October 28, 2010 / Rules and Regulations 66459 

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), (2), or (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 vent stream 

following the N2O abatement 

technology. 

(e) If any N2O abatement technology 

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

must determine the annual amount of 

adipic acid produced while N2O 

abatement technology ‘‘N’’ is operating 

according to § 98.54(f). Then you must 

calculate the abatement factor for N2O 

abatement technology ‘‘N’’ according to 

Equation E–2 of this section. 

AF =

P N

a,N

z

P

(Eq. E-2)

Where: 

AFN = Abatement utilization factor of N2O 

abatement technology ‘‘N’’ (fraction of 

annual production that abatement 

technology is operating). 

Pz,N = Annual adipic acid production during 

which N2O abatement technology ‘‘N’’ 

was used on unit ‘‘z’’ (ton adipic acid 

produced). 

Pz = Total annual adipic acid production 

from unit ‘‘z’’ (ton acid produced). 

(f) You must determine the annual 

amount of adipic acid produced 

according to § 98.54(f). 

(g) You must calculate N2O emissions 

according to paragraph (g)(1), (2), (3), or 

(4) of this section for each adipic acid 

production unit. 

(1) If one N2O abatement technology 

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

must use the emissions factor 

(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: 

E

EF P

a,z DF AF N z = ∗ ∗− ∗ ( ) ( ) 20

2205

1 ,z (Eq. E-3a)

Where: 

Ea,z = Annual N2O mass emissions from 

adipic acid production unit ‘‘z’’ 

according to this Equation E–3a (metric 

tons). 

EFN2Oz = N2O emissions factor for unit ‘‘z’’ (lb 

N2O/ton adipic acid produced). 

Pz = Annual adipic acid produced from unit 

‘‘z’’ (tons). 

DF = Destruction efficiency of N2O abatement 

technology ‘‘N’’ (percent of N2O removed 

from vent stream). 

AF = Abatement utilization factor of N2O 

abatement technology ‘‘N’’ (percent of 

time that the abatement technology is 

operating). 

2205 = Conversion factor (lb/metric ton). 

(2) If multiple N2O abatement 

technologies are located in series after 

your test point, you must use the 

emissions factor (determined in 

Equation E–1 of this section), the 

destruction efficiency (determined in 

paragraph (d) of this section), the annual 

adipic acid production (determined in 

paragraph (f) of this section), and the 

abatement utilization factor (determined 

in paragraph (e) of this section), 

according to Equation E–3b of this 

section: 

E

EF P

b,z DF AF DF AF DF N z = ∗ ∗− ∗ ( ) ( ) ∗− ∗ ( ) ( ) ∗ ∗− ∗ 20

11 2 2 2205

11 1 , ... z ( ) ( ) N AFN (Eq. E-3b)

Where: 

Eb,z = Annual N2O mass emissions from 

adipic acid production unit ‘‘z’’ 

according to this Equation E–3b (metric 

tons). 

EFN2O,z = N2O emissions factor for unit ‘‘z’’ (lb 

N2O/ton adipic acid produced). 

Pz = Annual adipic acid produced from unit 

‘‘z’’ (tons). 

DF1 = Destruction efficiency of N2O 

abatement technology 1 (percent of N2O 

removed from vent stream). 

AF1 = Abatement utilization factor of N2O 

abatement technology 1 (percent of time 

that abatement technology 1 is 

operating). 

DF2 = Destruction efficiency of N2O 

abatement technology 2 (percent of N2O 

removed from vent stream). 

AF2 = Abatement utilization factor of N2O 

abatement technology 2 (percent of time 

that abatement technology 2 is 

operating). 

DFN = Destruction efficiency of N2O 

abatement technology N (percent of N2O 

removed from vent stream). 

AFN = Abatement utilization factor of N2O 

abatement technology N (percent of time 

that abatement technology N is 

operating). 

2205 = Conversion factor (lb/metric ton). 

N = Number of different N2O abatement 

technologies. 

(3) If multiple N2O abatement 

technologies are located in parallel after 

your test point, you must use the 

emissions factor (determined in 

Equation E–1 of this section), the 

destruction efficiency (determined in 

paragraph (d) of this section), the annual 

adipic acid production (determined in 

paragraph (f) of this section), and the 

abatement utilization factor (determined 

in paragraph (e) of this section), 

according to Equation E–3c of this 

section: 

E

EF P

c,z DF AF FC N z

N

= ∗ ∗−∗ ∑( ) ( ) ( ) ∗ 20

1 2205

1 ,z

NN N (Eq. E-3c)


srobinson on DSKHWCL6B1PROD with RULES2ER28OC10.019</MATH> ER28OC10.020</MATH> ER28OC10.021</MATH> ER28OC10.022</MATH>
66460 Federal Register / Vol. 75, No. 208 / Thursday, October 28, 2010 / Rules and Regulations 

Where: 

Ec,z = Annual N2O mass emissions from 

adipic acid production unit ‘‘z’’ 

according to this Equation E–3c (metric 

tons). 

EFN2O,z = N2O emissions factor for unit ‘‘z’’ (lb 

N2O/ton adipic acid produced). 

Pz = Annual adipic acid produced from unit 

‘‘z’’ (tons). 

DFN = Destruction efficiency of N2O 

abatement technology ‘‘N’’ (percent of 

N2O removed from vent stream). 

AFN = Abatement utilization factor of N2O 

abatement technology ‘‘N’’ (percent of 

time that the abatement technology is 

operating). 

FCN = Fraction control factor of N2O 

abatement technology ‘‘N’’ (percent of 

total emissions from unit ‘‘z’’ that are sent 

to abatement technology ‘‘N’’). 

2205 = Conversion factor (lb/metric ton). 

N = Number of different N2O abatement 

technologies with a fraction control 

factor. 

(4) If no N2O abatement technologies 

are located after your test point, you 

must use the emissions factor 

(determined using Equation E–1 of this 

section) and the annual adipic acid 

production (determined in paragraph (f) 

of this section) according to Equation 

E–3d of this section for each adipic acid 

production unit. 

E

EF P

d,z

N z = ∗ 20

2205 (Eq. E-3d)

Where: 

Ed,z = Annual N2O mass emissions from 

adipic acid production for unit ‘‘z’’ 

according to this Equation E–3d (metric 

tons). 

EFN2O = N2O emissions factor for unit ‘‘z’’ (lb 

N2O/ton adipic acid produced). 

PZ = Annual adipic acid produced from unit 

‘‘z’’ (tons). 

2205 = Conversion factor (lb/metric ton). 

(h) You must determine the emissions 

for the facility by summing the unit 

level emissions according to Equation 

E–4 of this section. 

NO E E E E a,z b,z c,z d,z

z

M

2

1

= +++

=

∑ (Eq. E-4)

Where: 

Ea,z = Annual N2O mass emissions from 

adipic acid production unit ‘‘z’’ 

according to Equation E–3a of this 

section (metric tons). 

Eb,z = Annual N2O mass emissions from 

adipic acid production unit ‘‘z’’ 

according to Equation E–3b of this 

section (metric tons). 

Ec,z = Annual N2O mass emissions from 

adipic acid production unit ‘‘z’’ 

according to Equation E–3c of this 

section (metric tons). 

Ed,z = Annual N2O mass emissions from 

adipic acid production unit ‘‘z’’ 

according to Equation E–3d of this 

section (metric tons). 

M = Total number of adipic acid production 

units. 

(i) You must determine the amount of 

process N2O emissions that is sold or 

transferred off site (if applicable). You 

can determine the amount using 

existing process flow meters and N2O 

analyzers. 

■ 7. Section 98.54 is amended by: 

■ a. Revising paragraph (a) introductory 

text. 

■ b. Adding second and third sentences 

to the end of paragraph (a)(1). 

■ c. Revising paragraph (a)(3). 

■ d. Revising paragraph (c) introductory 

text. 

■ e. Revising the first sentence of 

paragraph (d) introductory text. 

■ f. Revising paragraphs (e) and (f). 

The revisions and additions read as 

follows: 

§ 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 (3) of this section. 

(1) * * * The test must be conducted 

at a point during production that is 

representative of the average emissions 

rate from your process. You must 

document the methods used to 

determine the representative point. 

* * * * * 

(3) If you requested Administrator 

approval for an alternative method of 

determining N2O emissions under 

§ 98.53(a)(2), you must conduct the 

performance test if your request has not 

been approved by the Administrator 

within 150 days of the end of the 

reporting year in which it was 

submitted. 

* * * * * 

(c) You must determine the adipic 

acid production rate during the 

performance test according to paragraph 

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

* * * * * 

(d) You must determine the 

volumetric flow rate during the 

performance test in conjunction with 

the applicable EPA methods in 40 CFR 

part 60, appendices A–1 through A–4. 

* * * 

* * * * * 

(e) You must determine the monthly 

amount of adipic acid produced. You 

must also determine the monthly 

amount of adipic acid produced during 

which N2O abatement technology, 

located after the test point, is operating. 

These monthly amounts are determined 

according to the methods in paragraphs 

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

(f) You must determine the annual 

amount of adipic acid produced. You 

must also determine the annual amount 

of adipic acid produced during which 

N2O abatement technology located after 

the test point is operating. These are 

determined by summing the respective 

monthly adipic acid production 

quantities determined in paragraph (e) 

of this section. 

■ 8. Section 98.56 is amended by: 

■ a. Revising the introductory text. 

■ b. Revising paragraph (c). 

■ c. Revising paragraph (j) introductory 

text. 

■ d. Revising paragraph (j)(1). 

■ e. Revising paragraph (k) introductory 

text. 

■ f. Adding paragraph (l). 

The revisions and addition read as 

follows: 

§ 98.56 Data reporting requirements. 

In addition to the information 

required by § 98.3(c), each annual report 

must contain the information specified 

in paragraphs (a) through (l) of this 

section at the facility level. 

* * * * * 

(c) Annual adipic acid production 

during which N2O abatement 

technology (located after the test point) 

is operating (tons). 

* * * * * 

(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 (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 (4) of this 


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Federal Register / Vol. 75, No. 208 / Thursday, October 28, 2010 / Rules and Regulations 66461 

section for each adipic acid production 

facility. 

* * * * * 

(l) Fraction control factor for each 

abatement technology (percent of total 

emissions from the production unit that 

are sent to the abatement technology) if 

equation E–3c is used. 

■ 9. Section 98.57 is amended by 

revising paragraphs (c) and (f) to read as 

follows: 

§ 98.57 Records that must be retained. 

* * * * * 

(c) Number of facility and unit 

operating hours in calendar year. 

* * * * * 

(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) through (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 

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. 

(e) The quantity of CKD not recycled 

to the kiln generated by each kiln must 

be determined quarterly using the same 

plant techniques used for accounting 

purposes, such as direct weight 

measurement using weigh hoppers, 

truck weigh scales, or belt weigh 

feeders. 

(f) The annual quantity of raw kiln 

feed or annual quantity of each category 

of raw materials consumed by the 

facility (e.g., limestone, sand, shale, iron 

oxide, and alumina) must be determined 

monthly by direct weight measurement 

using the same plant instruments used 

for accounting purposes, such as weigh 

hoppers, truck weigh scales, or belt 

weigh feeders. 

* * * * * 

■ 12. Section 98.86 is amended by: 

■ a. Revising paragraph (b)(3). 

■ b. Revising paragraph (b)(4). 

■ c. Revising paragraph (b)(12). 

■ d. Revising paragraph (b)(13). 

■ e. Adding paragraph (b)(15). 

The revisions and addition read as 

follows: 

§ 98.86 Data reporting requirements. 

* * * * * 

(b) * * * 

(3) Annual cement production at the 

facility. 

(4) Number of kilns and number of 

operating kilns. 

* * * * * 

(12) Annual organic carbon content of 

raw kiln feed or annual organic carbon 

content of each raw material (wtfraction, dry basis). 

(13) Annual consumption of raw kiln 

feed or annual consumption of each raw 

material (dry basis). 

* * * * * 

(15) Method used to determine the 

monthly clinker production from each 

kiln reported under (b)(2) of this 

section, including monthly kiln-specific 

clinker factors, if used. 

13. Section 98.87 is revised to read as 

follows: 

§ 98.87 Records that must be retained. 

(a) If a CEMS is used to measure CO2

emissions, then in addition to the 

records required by § 98.3(g), you must 

retain under this subpart the records 

required for the Tier 4 Calculation 

Methodology in § 98.37. 

(b) If a CEMS is not used to measure 

CO2 emissions, then in addition to the 

records required by § 98.3(g), you must 

retain the records specified in this 

paragraph (b) for each portland cement 

manufacturing facility. 

(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 to subpart K. 

* * * * * 

■ 15. Section 98.113 is amended by 

revising the introductory text to read as 

follows: 

§ 98.113 Calculating GHG emissions. 

You must calculate and report the 

annual process CO2 emissions from each 


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66462 Federal Register / Vol. 75, No. 208 / Thursday, October 28, 2010 / Rules and Regulations 

EAF not subject to paragraph (c) of this 

section using the procedures in either 

paragraph (a) or (b) of this section. For 

each EAF also subject to annual process 

CH4 emissions reporting, you must also 

calculate and report the annual process 

CH4 emissions from the EAF using the 

procedures in paragraph (d) of this 

section. 

* * * * * 

■ 16. Section 98.116 is amended by: 

■ a. Revising paragraph (b). 

■ b. Revising paragraph (c). 

■ c. Revising paragraph (d) introductory 

text. 

■ d. Revising paragraph (d)(1). 

■ e. Revising paragraph (e)(1). 

The revisions 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 using ASTM D3682–01 

(Reapproved 2006) Standard Test 

Method for Major and Minor Elements 

in Combustion Residues from Coal 

Utilization Processes (incorporated by 

reference, see § 98.7) or ASTM D6349– 

09 Standard Test Method for 

Determination of Major and Minor 

Elements in Coal, Coke, and Solid 

Residues from Combustion of Coal and 

Coke by Inductively Coupled Plasma— 

Atomic Emission Spectrometry 

(incorporated by reference, see § 98.7). 

* * * * * 

■ 18. Section 98.146 is amended by: 

■ a. Revising paragraph (a) introductory 

text. 

■ b. Revising paragraph (a)(2). 

■ c. Revising paragraph (b)(7). 

■ d. Revising paragraph (b)(9). 

The revisions 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 (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. In the Table to Subpart N of Part 

98, Table N–1 to subpart N is amended 

by adding entries for ‘‘Barium 

carbonate,’’ ‘‘Potassium carbonate,’’ 

‘‘Lithium carbonate,’’ and ‘‘Strontium 

carbonate’’ to the end of the table to read 

as follows: 

Table to Subpart N of Part 98 

TABLE N–1 TO SUBPART N—CO2 EMISSION FACTORS FOR CARBONATE-BASED RAW MATERIALS

Carbonate-based raw material—mineral CO2 emission 

factor a

*******

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

Potassium carbonate—K2CO3 ............................................................................................................................................................. 0.318 

Lithium carbonate (Li2CO3) .................................................................................................................................................................. 0.596 

Strontium carbonate (SrCO3) .............................................................................................................................................................. 0.298 

aEmission factors in units of metric tons of CO2 emitted per metric ton of carbonate-based raw material charged to the furnace. 

Subpart O—[Amended] 

■ 20. Section 98.154 is amended by: 

■ a. Revising the first and second 

sentences of paragraph (k). 

■ b. Revising the second sentence of 

paragraph (l) introductory text. 

■ c. Revising paragraph (o). 

The revisions 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 


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and/or destruction device manufacturer 

specifications. 

* * * * * 

■ 21. Section 98.156 is amended by: 

■ a. Revising paragraph (b)(1). 

■ b. Revising paragraph (b)(3). 

■ c. Revising paragraph (c). 

■ d. Revising paragraph (d). 

■ e. Revising paragraph (e) introductory 

text. 

The revisions 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 removing and 

reserving paragraph (b). 

The revision reads 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). 

■ c. Revising paragraph (b) introductory 

text. 

■ d. In paragraph (b)(1), revising the 

introductory text and revising the 

definition of ‘‘CO2’’ in Equation P–1. 

■ e. Revising paragraphs (b)(2) 

introductory text and (b)(3) introductory 

text. 

The revisions read as follows: 

§ 98.163 Calculating GHG emissions. 

You must calculate and report the 

annual CO2 emissions from each 

hydrogen production process unit using 

the procedures specified in either 

paragraph (a) or (b) of this section. 

(a) Continuous Emissions Monitoring 

Systems (CEMS). Calculate and report 

under this subpart the CO2 emissions by 

operating and maintaining CEMS 

according to the Tier 4 Calculation 

Methodology specified in § 98.33(a)(4) 

and all associated requirements for Tier 

4 in subpart C of this part (General 

Stationary Fuel Combustion Sources). 

(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 

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

as appropriate, and paragraphs (c) and 

(d) of this section: 

(a) * * * 

(1) Unit identification number and 

annual CO2 emissions. 

* * * * * 

(b) * * * 

(1) Unit identification number and 

annual CO2 emissions. 

* * * * * 

(c) Quantity of CO2 collected and 

transferred off site in either gas, liquid, 

or solid forms, following the 

requirements of subpart PP of this part. 

* * * * * 

Subpart Q—[Amended] 

■ 27. Section 98.172 is amended by 

revising paragraphs (b) and (c) to read 

as follows: 

§ 98.172 GHGs to report. 

* * * * * 

(b) You must report CO2 emissions 

from flares that burn blast furnace gas or 

coke oven gas according to the 

procedures in § 98.253(b)(1) of subpart 

Y (Petroleum Refineries) of this part. 

When using the alternatives set forth in 

§ 98.253(b)(1)(ii)(B) and 

§ 98.253(b)(1)(iii)(C), you must use the 

default CO2 emission factors for coke 

oven gas and blast furnace gas from 

Table C–1 to subpart C in Equations Y– 

2 and Y–3 of subpart Y. You must report 

CH4 and N2O emissions from flares 

according to the requirements in 

§ 98.33(c)(2) using the emission factors 

for coke oven gas and blast furnace gas 

in Table C–2 to subpart C of this part. 

(c) You must report process CO2

emissions from each taconite indurating 


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66464 Federal Register / Vol. 75, No. 208 / Thursday, October 28, 2010 / Rules and Regulations 

furnace; basic oxygen furnace; nonrecovery coke oven battery combustion 

stack; coke pushing process; sinter 

process; EAF; decarburization vessel; 

and direct reduction furnace by 

following the procedures in this 

subpart. 

■ 28. Section 98.173 is amended by: 

■ a. Revising the first sentence of the 

introductory text. 

■ b. In paragraph (b)(1)(vi), revising the 

introductory text and the definition of 

‘‘CO2’’ in Equation Q–6 of subpart Q. 

■ c. Revising the first sentence of 

paragraph (d). 

The revisions read as follows: 

§ 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 the first sentence of paragraph 

(c)(2) and revising paragraph (c)(7) to 

read as follows: 

§ 98.174 Monitoring and QA/QC 

requirements. 

* * * * * 

(c) * * * 

(2) For the furnace exhaust from basic 

oxygen furnaces, EAFs, decarburization 

vessels, and direct reduction furnaces, 

sample the furnace exhaust for at least 

three complete production cycles that 

start when the furnace is being charged 

and end after steel or iron and slag have 

been tapped. * * * 

* * * * * 

(7) If your EAF and decarburization 

vessel exhaust to a common emission 

control device and stack, you must 

sample each process in the ducts before 

the emissions are combined, sample 

each process when only one process is 

operating, or sample the combined 

emissions when both processes are 

operating and base the site-specific 

emission factor on the steel production 

rate of the EAF. 

* * * * * 

■ 30. Section 98.175 is amended by 

revising the introductory text to read as 

follows: 

§ 98.175 Procedures for estimating 

missing data. 

A complete record of all measured 

parameters used in the GHG emissions 

calculations in § 98.173 is required. 

Therefore, whenever a quality-assured 

value of a required parameter is 

unavailable, a substitute data value for 

the missing parameter shall be used in 

the calculations as specified in the 

paragraphs (a) and (b) of this section. 

You must follow the missing data 

procedures in § 98.255(b) of subpart Y 

(Petroleum Refineries) of this part for 

flares burning coke oven gas or blast 

furnace gas. You must document and 

keep records of the procedures used for 

all such estimates. 

* * * * * 

■ 31. Section 98.176 is amended by: 

■ a. Revising the introductory text. 

■ b. Revising paragraph (c). 

■ c. Revising paragraph (e)(3). 

■ d. Adding paragraphs (g) and (h). 

The revisions and additions 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. For reporting year 

2010, the information required in 

paragraphs (a) through (h) of this section 

is not required for decarburization 

vessels that are not argon-oxygen 

decarburization vessels. For reporting 

year 2011 and each subsequent 

reporting year, the information in 

paragraphs (a) through (h) of this section 

must be reported for all decarburization 

vessels. 

* * * * * 

(c) If a CEMS is used to measure CO2

emissions, then you must report the 

relevant information required under 

§ 98.36 for the Tier 4 Calculation 

Methodology. 

* * * * * 

(e) * * * 

(3) The annual volume of each type of 

gaseous fuel (reported separately for 

each type in standard cubic feet), the 

annual volume of each type of liquid 

fuel (reported separately for each type in 

gallons), and the annual mass (in metric 

tons) of each other process inputs and 

outputs used to determine CO2

emissions. 

* * * * * 

(g) The annual amount of coal charged 

to the coke ovens (in metric tons). 

(h) For flares burning coke oven gas 

or blast furnace gas, the information 

specified in § 98.256(e) of subpart Y 

(Petroleum Refineries) of this part. 

■ 32. Section 98.177 is amended by 

revising paragraph (d) to read as 

follows: 

§ 98.177 Records that must be retained. 

* * * * * 

(d) Annual operating hours for each 

taconite indurating furnace, basic 

oxygen furnace, non-recovery coke oven 

battery, sinter process, electric arc 

furnace, decarburization vessel, and 

direct reduction furnace. 

* * * * * 

Subpart S—[Amended] 

■ 33. Section 98.190 is amended by 

revising paragraph (a) to read as follows: 

§ 98.190 Definition of the source category. 

(a) Lime manufacturing plants (LMPs) 

engage in the manufacture of a lime 

product (e.g., calcium oxide, highcalcium quicklime, calcium hydroxide, 

hydrated lime, dolomitic quicklime, 

dolomitic hydrate, or other lime 

products) by calcination of limestone, 

dolomite, shells or other calcareous 

substances as defined in 40 CFR 

63.7081(a)(1). 

* * * * * 

■ 34. Section 98.193 is amended by: 

■ a. In paragraph (b)(2)(i), revising the 

second sentence of the introductory text 

and the definition of ‘‘2000/2205’’ in 

Equation S–1. 

■ b. In paragraph (b)(2)(ii), revising the 

introductory text 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 

introductory text and the definitions of 


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‘‘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. 

The revisions read as follows: 

§ 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). 

The revisions read as follows: 

§ 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 (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 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 (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). 

(b) If a CEMS is not used to measure 

CO2 emissions, then you must report the 

information listed in paragraphs (b)(1) 

through (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. 


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66466 Federal Register / Vol. 75, No. 208 / Thursday, October 28, 2010 / Rules and Regulations 

(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 (ii) of this section. 

(i) The annual amount of CO2

captured for use in the on-site process. 

(ii) The method used to determine the 

amount of CO2 captured. 

Subpart V—[Amended] 

■ 38. Section 98.223 is amended by: 

■ a. Revising paragraphs (a)(1) and 

(a)(2)(ii). 

■ b. Revising paragraph (b) introductory 

text. 

■ c. Revising paragraphs (b)(1) and 

(b)(2). 

■ d. Revising paragraph (c). 

■ e. Revising paragraph (d) introductory 

text. 

■ f. Revising paragraph (e). 

■ g. Removing and reserving paragraph 

(f). 

■ h. Revising paragraph (g). 

■ i. Adding paragraph (i). 

The revisions and addition read as 

follows: 

§ 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 (3) of this section. 

(1) You must conduct the 

performance test at the absorber tail gas 

vent, referred to as the test point, for 

each nitric acid train according to 

§ 98.224(b) through (f). If multiple nitric 

acid production units exhaust to a 

common abatement technology and/or 

emission point, you must sample each 

process in the ducts before the 

emissions are combined, sample each 

process when only one process is 

operating, or sample the combined 

emissions when multiple processes are 

operating and base the site-specific 

emission factor on the combined 

production rate of the multiple nitric 

acid production units. 

(2) You must conduct the 

performance test under normal process 

operating conditions. 

* * * * * 

(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/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

t,N

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). 

Pt = Total annual nitric acid production from 

nitric acid train ‘‘t’’ (ton acid produced, 

100 percent acid basis). 

Pa,t,N = Annual nitric acid production from 

nitric acid train ‘‘t’’ during which N2O 

abatement technology ‘‘N’’ was 

operational (ton acid produced, 100 

percent acid basis). 

* * * * * 

(g) You must calculate N2O emissions 

for each nitric acid train ‘‘t’’ according to 

paragraph (g)(1), (g)(2), (g)(3), or (g)(4) of 

this section. 

(1) If nitric acid train ‘‘t’’ exhausts to 

one N2O abatement technology ‘‘N’’ after 

the test point, you must use the 

emissions factor (determined in 

Equation V–1 of this section), the 

destruction efficiency (determined in 

paragraph (d) of this section), the annual 

nitric acid 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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Federal Register / Vol. 75, No. 208 / Thursday, October 28, 2010 / Rules and Regulations 66467 

E

EF P

N Ot DF AF Nt t2

20

2205 = 1 ∗ ∗− ∗ ( ) ( ) (Eq. V-3a)

Where: 

EN2Ot = Annual N2O mass emissions from 

nitric acid production unit ‘‘t’’ according 

to this Equation V–3a (metric tons). 

EFN2Ot = Average site-specific N2O emissions 

factor for nitric acid train ’’t’’ (lb N2O/ton 

acid produced, 100 percent acid basis). 

Pt = Annual nitric acid production from the 

train ‘‘t’’ (ton acid produced, 100 percent 

acid basis). 

DF = Destruction efficiency of N2O abatement 

technology N that is used on nitric acid 

train ‘‘t’’ (percent of N2O removed from 

vent stream). 

AF = Abatement utilization factor of N2O 

abatement technology ‘‘N’’ for nitric acid 

train ‘‘t’’ (percent of time that the 

abatement technology is operating). 

2205 = Conversion factor (lb/metric ton). 

(2) If multiple N2O abatement 

technologies are located in series after 

your test point, you must use the 

emissions factor (determined in 

Equation V–1 of this section), the 

destruction efficiency (determined in 

paragraph (d) of this section), the annual 

nitric acid production (determined in 

paragraph (f) of this section), and the 

abatement utilization factor (determined 

in paragraph (e) of this section), 

according to Equation V–3b of this 

section: 

E

EF P

N Ot DF AF DF AF DF Nt t2

20

11 2 2 2205 = 11 1 ∗ ∗− ∗ ( ) ( ) ∗− ∗ ( ) ( ) ∗ ∗− , ... ( ) ( ) N ∗ AFN (Eq. V-3b)

Where: 

EN2Ot = Annual N2O mass emissions from 

nitric acid production unit ‘‘t’’ according 

to this Equation V–3b (metric tons). 

EFN2O,t = N2O emissions factor for unit ‘‘t’’ (lb 

N2O/ton nitric acid produced). 

Pt = Annual nitric acid produced from unit 

‘‘t’’ (ton acid produced, 100 percent acid 

basis). 

DF1 = Destruction efficiency of N2O 

abatement technology 1 (percent of N2O 

removed from vent stream). 

AF1 = Abatement utilization factor of N2O 

abatement technology 1 (percent of time 

that abatement technology 1 is 

operating). 

DF2 = Destruction efficiency of N2O 

abatement technology 2 (percent of N2O 

removed from vent stream). 

AF2 = Abatement utilization factor of N2O 

abatement technology 2 (percent of time 

that abatement technology 2 is 

operating). 

DFN = Destruction efficiency of N2O 

abatement technology N (percent of N2O 

removed from vent stream). 

AFN = Abatement utilization factor of N2O 

abatement technology N (percent of time 

that abatement technology N is 

operating). 

2205 = Conversion factor (lb/metric ton). 

N = Number of different N2O abatement 

technologies. 

(3) If multiple N2O abatement 

technologies are located in parallel after 

your test point, you must use the 

emissions factor (determined in 

Equation V–1 of this section), the 

destruction efficiency (determined in 

paragraph (d) of this section), the annual 

nitric acid production (determined in 

paragraph (f) of this section), and the 

abatement utilization factor (determined 

in paragraph (e) of this section), 

according to Equation V–3c of this 

section: 

E

EF P

N Ot DF AF FC Nt t

N

2

20

1 2205 = 1 ∗ ∗−∗ ∑( ) ( ) ( ) ∗ ,

NN N (Eq. V-3c)

Where: 

EN2Ot = Annual N2O mass emissions from 

nitric acid production unit ‘‘t’’ according 

to this Equation V–3c (metric tons). 

EFN2O,t = N2O emissions factor for unit ‘‘t’’ (lb 

N2O/ton nitric acid produced). 

Pt = Annual nitric acid produced from unit 

‘‘t’’ (ton acid produced, 100 percent acid 

basis). 

DFN = Destruction efficiency of N2O 

abatement technology ‘‘N’’ (percent of 

N2O removed from vent stream). 

AFN = Abatement utilization factor of N2O 

abatement technology ‘‘N’’ (percent of 

time that abatement technology ‘‘N’’ is 

operating). 

FCN = Fraction control factor of N2O 

abatement technology ‘‘N’’ (percent of 

total emissions from unit ‘‘t’’ that are sent 

to abatement technology ‘‘N’’). 

2205 = Conversion factor (lb/metric ton). 

N = Number of different N2O abatement 

technologies with a fraction control 

factor. 

(4) If nitric acid train ‘‘t’’ does not 

exhaust to any N2O abatement 

technology after the test point, you must 

use the emissions factor (determined in 

Equation V–1 of this section), and the 

annual nitric acid production 

(determined in paragraph (i) of this 

section) according to Equation V–3b of 

this section: 

E

EF P

N Ot

Nt t

2

20

2205 = ∗ (Eq. V-3d)

Where: 

EN2Ot = Annual N2O mass emissions from 

nitric acid production unit ‘‘t’’ according 

to this Equation V–3d (metric tons). 

EFN2Ot = Average site-specific N2O emissions 

factor for nitric acid train ’’t’’ (lb N2O/ton 

acid produced, 100 percent acid basis). 

Pt = Annual nitric acid production from 

nitric acid train ‘‘t’’ (ton acid produced, 

100 percent acid basis). 

2205 = Conversion factor (lb/metric ton). 

* * * * * 

(i) You must determine the total 

annual amount of nitric acid produced 

on nitric acid train ‘‘t’’ for each nitric 

acid train (tons acid produced, 100 

percent acid basis), according to 

§ 98.224(f). 

■ 39. Section 98.224 is amended by: 

■ a. Revising paragraph (a). 

■ b. Revising the first sentence in 

paragraph (d) introductory text. 

■ c. Revising paragraphs (e) and (f). 

The revisions read as follows: 

§ 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 

(3) of this section. 

(1) Conduct the performance test 

annually. The test should be conducted 

at a point during the campaign which is 

representative of the average emissions 

rate from the nitric acid campaigns. 

Facilities must document the methods 

used to determine the representative 


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66468 Federal Register / Vol. 75, No. 208 / Thursday, October 28, 2010 / Rules and Regulations 

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. You must also determine the 

monthly amount of nitric acid produced 

while N2O abatement technology 

(located after the test point) is operating 

from each nitric acid train. These 

monthly amounts are determined 

according to the methods in paragraphs 

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

(f) You must determine the annual 

amount of nitric acid produced. You 

must also determine the annual amount 

of nitric acid produced while N2O 

abatement technology (located after the 

test point) is operating for each train. 

These annual amounts are determined 

by summing the respective monthly 

nitric acid quantities determined in 

paragraph (e) of this section. 

■ 40. Section 98.226 is amended by: 

■ a. Revising the introductory text. 

■ b. Revising paragraph (g). 

■ c. Revising paragraph (m) 

introductory text. 

■ d. Revising paragraph (n) introductory 

text. 

■ e. Adding paragraph (p). 

The revisions and addition 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 (p) 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 (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 (4) of this 

section. 

* * * * * 

(p) Fraction control factor for each 

abatement technology (percent of total 

emissions from the production unit that 

are sent to the abatement technology) if 

equation V–3c is used. 

Subpart Z—[Amended] 

■ 41. Section 98.263 is amended by 

revising paragraph (b)(1) to read as 

follows: 

§ 98.263 Calculating GHG emissions. 

* * * * * 

(b) * * * 

(1) Calculate the annual CO2 mass 

emissions from each wet-process 

phosphoric acid process line using the 

methods in paragraphs (b)(1)(i) or (ii) of 

this section, as applicable. 

(i) If your process measurement 

provides the inorganic carbon content of 

phosphate rock as an output, calculate 

and report the process CO2 emissions 

from each wet-process phosphoric acid 

process line using Equation Z–1a of this 

section: 

E IC P m n,i n,i

n

z

i

b

= ∗ ( ) ∗ ∗

==

∑∑ 2000

2205 (Eq. Z-1a) 44

12 11

Where: 

Em = Annual CO2 mass emissions from a wetprocess phosphoric acid process line m 

according to this Equation Z–1a (metric 

tons). 

ICn,i = Inorganic carbon content of a grab 

sample batch of phosphate rock by origin 

i obtained during month n, from the 

carbon analysis results (percent by 

weight, expressed as a decimal fraction). 

Pn,i = Mass of phosphate rock by origin i 

consumed in month n by wet-process 

phosphoric acid process line m (tons). 

z = Number of months during which the 

process line m operates. 

b = Number of different types of phosphate 

rock in month, by origin. If the grab 

sample is a composite sample of rock 

from more than one origin, b = 1. 

2000/2205 = Conversion factor to convert 

tons to metric tons. 

44/12 = Ratio of molecular weights, CO2 to 

carbon. 

(ii) If your process measurement 

provides the CO2 emissions directly as 

an output, calculate and report the 

process CO2 emissions from each wetprocess phosphoric acid process line 

using Equation Z–1b of this section: 

E CO P m n,i

n

z

i

b

n,i = ∗ ( ) ∗

==

∑∑ 2

11

2000

2205 (Eq. Z-1b)

Where: 

Em = Annual CO2 mass emissions from a wetprocess phosphoric acid process line m 

according to this Equation Z–1b (metric 

tons). 

CO2n,i = Carbon dioxide emissions of a grab 

sample batch of phosphate rock by origin 

i obtained during month n (percent by 

weight, expressed as a decimal fraction). 

Pn,i = Mass of phosphate rock by origin i 

consumed in month n by wet-process 

phosphoric acid process line m (tons). 

z = Number of months during which the 

process line m operates. 

b = Number of different types of phosphate 

rock in month, by origin. If the grab 

sample is a composite sample of rock 

from more than one origin, b=1. 

2000/2205 = Conversion factor to convert 

tons to metric tons. 

* * * * * 

■ 42. Section 98.264 is amended by 

revising paragraphs (a) and (b) to read 

as follows: 


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Federal Register / Vol. 75, No. 208 / Thursday, October 28, 2010 / Rules and Regulations 66469 

§ 98.264 Monitoring and QA/QC 

requirements. 

(a) You must obtain a monthly grab 

sample of phosphate rock directly from 

the rock being fed to the process line 

before it enters the mill using one of the 

following methods. You may conduct 

the representative bulk sampling using 

a method published by a consensus 

standards organization, or you may use 

industry consensus standard practice 

methods, including but not limited to 

the Phosphate Mining States Methods 

Used and Adopted by the Association of 

Fertilizer and Phosphate Chemists 

(AFPC) (P.O. Box 1645, Bartow, Florida 

33831, (863) 534–9755, http://afpc.net, 

paul.mcafee@mosaicco.com). If 

phosphate rock is obtained from more 

than one origin in a month, you must 

obtain a sample from each origin of rock 

or obtain a composite representative 

sample. 

(b) You must determine the carbon 

dioxide or inorganic carbon content of 

each monthly grab sample of phosphate 

rock (consumed in the production of 

phosphoric acid). You may use a 

method published by a consensus 

standards organization, or you may use 

industry consensus standard practice 

methods, including but not limited to 

the Phosphate Mining States Methods 

Used and Adopted by AFPC (P.O. Box 

1645, Bartow, Florida 33831, (863) 534– 

9755, http://afpc.net, 

paul.mcafee@mosaicco.com). 

* * * * * 

■ 43. Section 98.265 is amended by 

revising the first and second sentences 

of paragraph (a) to read as follows: 

§ 98.265 Procedures for estimating 

missing data. 

* * * * * 

(a) For each missing value of the 

inorganic carbon content of phosphate 

rock or carbon dioxide (by origin), you 

must use the appropriate default factor 

provided in Table Z–1 this subpart. 

Alternatively, you must determine a 

substitute data value by calculating the 

arithmetic average of the quality-assured 

values of inorganic carbon contents of 

phosphate rock of origin i from samples 

immediately preceding and immediately 

following the missing data incident. 

* * * 

* * * * * 

■ 44. Section 98.266 is amended by: 

■ a. Revising the introductory text. 

■ b. Revising paragraph (c). 

■ c. Revising paragraph (f) introductory 

text. 

■ d. Revising paragraph (f)(2). 

■ e. Revising paragraph (f)(4). 

■ f. Revising paragraph (f)(5). 

■ g. Adding paragraph (f)(9). 

The revisions and addition 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 or carbon dioxide in 

phosphate rock from monthly records 

(percent by weight, expressed as a 

decimal fraction). 

* * * * * 

(f) If you do not use a CEMS to 

measure emissions, then you must 

report the information in paragraphs 

(f)(1) through (9) of this section. 

* * * * * 

(2) Annual CO2 emissions from each 

wet-process phosphoric acid process 

line (metric tons) as calculated by either 

Equation Z–1a or Equation Z–1b of this 

subpart. 

* * * * * 

(4) Method used to estimate any 

missing values of inorganic carbon 

content or carbon dioxide content of 

phosphate rock for each wet-process 

phosphoric acid process line. 

(5) Monthly inorganic carbon content 

of phosphate rock for each wet-process 

phosphoric acid process line for which 

Equation Z–1a is used (percent by 

weight, expressed as a decimal fraction), 

or CO2 (percent by weight, expressed as 

a decimal fraction) for which Equation 

Z–1b is used. 

* * * * * 

(9) Annual process CO2 emissions 

from phosphoric acid production 

facility (metric tons). 

Subpart CC—[Amended] 

■ 45. Section 98.294 is amended by 

revising the third sentence of paragraph 

(a)(1) to read as follows: 

§ 98.294 Monitoring and QA/QC 

requirements. 

* * * * * 

(a) * * * 

(1) * * * The modified method 

referred to above adjusts the regular 

ASTM method to express the results in 

terms of trona.* * * 

* * * * * 

■ 46. Section 98.296 is amended by: 

■ a. Revising paragraph (a)(1). 

■ b. Revising paragraph (b)(3). 

■ c. Revising paragraph (b)(6). 

■ d. Revising paragraph (b)(10). 

■ e. Removing paragraphs (b)(11)(iv) 

through (vi). 

The revisions 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] 

■ 47. Section 98.314 is amended by 

revising paragraph (e) to read as follows: 

§ 98.314 Monitoring and QA/QC 

requirements. 

* * * * * 

(e) You must determine the quantity 

of 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. 

* * * * * 

■ 48. Section 98.316 is amended by 

revising paragraphs (b)(9) and (b)(11) to 

read as follows: 

§ 98.316 Data reporting requirements. 

* * * * * 

(b) * * * 

(9) Monthly carbon content factor of 

petroleum coke (percent by weight 

expressed as a decimal fraction). 

* * * * * 

(11) Carbon content for carboncontaining waste for each process line 

(percent by weight expressed as a 

decimal fraction). 

* * * * * 


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Subpart GG—[Amended] 

■ 49. Section 98.333 is amended by 

revising the definitions of ‘‘(Electrode)k’’ 

and ‘‘(CElectrode)k’’ in Equation GG–1 of 

paragraph (b)(1) to read as follows: 

§ 98.333 Calculating GHG emissions. 

* * * * * 

(b) * * * 

(1) * * * * * 

(Electrode)k = Annual mass of carbon 

electrode consumed in furnace ‘‘k’’ (tons). 

(CElectrode)k = Carbon content of the carbon 

electrode consumed in furnace ‘‘k’’, from 

the annual carbon analysis (percent by 

weight, expressed as a decimal fraction). 

* * * * * 

■ 50. Section 98.336 is amended by 

revising paragraph (a) introductory text; 

and by revising paragraphs (b)(1), (b)(7), 

and (b)(10) to read as follows: 

§ 98.336 Data reporting requirements. 

* * * * * 

(a) If a CEMS is used to measure CO2

emissions, then you must report under 

this subpart the relevant information 

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] 

■ 51. 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, construction 

and demolition waste landfills, or 

industrial waste landfills. 

* * * * * 

■ 52. Section 98.343 is amended by: 

■ a. In paragraph (a)(1), revising 

Equation HH–1 and the definitions of 

‘‘x,’’ ‘‘S,’’ ‘‘Wx,’’ ‘‘MCF,’’ ‘‘DOCF,’’ ‘‘F,’’ and 

‘‘k’’ in Equation HH–1; and removing the 

definition of ‘‘L0’’ in Equation HH–1. 

■ b. Revising the last sentence of 

paragraph (a)(2). 

■ c. Redesignating paragraph (a)(3) as 

(a)(4) and revising new paragraph (a)(4). 

■ d. Adding a new paragraph (a)(3). 

■ e. Revising paragraph (b)(1), and 

revising paragraph (b)(2) introductory 

text. 

■ f. Revising paragraphs (b)(2)(ii), 

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

■ g. Revising paragraph (c) introductory 

text. 

The revisions and additions read as 

follows: 

§ 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 × from measurement 

data, tipping fee receipts, or other 

company records (metric tons, as 

received (wet weight)). 

MCF = Methane correction factor (fraction). 

Use the default value of 1 unless there 

is active aeration of waste within the 

landfill during the reporting year. If there 

is active aeration of waste within the 

landfill during the reporting year, use 

either the default value of 1 or select an 

alternative value no less than 0.5 based 

on site-specific aeration parameters. 

* * * * * 

DOCF = Fraction of DOC dissimilated 

(fraction). Use the default value of 0.5. 

F = Fraction by volume of CH4 in landfill gas 

from measurement data on a dry basis, 

if available (fraction); default is 0.5. 

k = Rate constant from Table HH–1 to this 

subpart (yr¥1). Select the most 

applicable k value for the majority of the 

past 10 years (or operating life, 

whichever is shorter). 

(2) * * * For years when waste 

composition data are not available, use 

the bulk waste parameter values for k 

and DOC in Table HH–1 to this subpart 

for the total quantity of waste disposed 

in those years. 

(3) Beginning in the first emissions 

reporting year and for each year 

thereafter, if scales are in place, you 

must determine the annual quantity of 

waste (in metric tons as received, i.e., 

wet weight) disposed of in the landfill 

using paragraph (a)(3)(i) of this section 

for all containers and for all vehicles 

used to haul waste to the landfill, except 

for passenger cars, light duty pickup 

trucks, or waste loads that cannot be 

measured using the scales due to 

physical limitations (load cannot 

physically access or fit on the scale) 

and/or operational limitations of the 

scale (load exceeding the limits or 

sensitivity range of the scale). If scales 

are not in place, you must use paragraph 

(a)(3)(ii) of this section to determine the 

annual quantity of waste disposed. For 

waste hauled to the landfill in passenger 

cars or light duty pickup trucks, you 

may use either paragraph (a)(3)(i) or 

paragraph (a)(3)(ii) of this section to 

determine the annual quantity of waste 

disposed. For loads that cannot be 

measured using the scales due to 

physical and/or operational limitations 

of the scale, you must use paragraph 

(a)(3)(ii) of this section or similar 

engineering calculations to determine 

the annual quantity of waste disposed. 

The approach used to determine the 

annual quantity of waste disposed of 

must be documented in the monitoring 

plan. 

(i) Use direct mass measurements of 

each individual load received at the 

landfill using either of the following 

methods: 

(A) Weigh using mass scales each 

vehicle or container used to haul waste 

as it enters the landfill or disposal area; 

weigh using mass scales each vehicle or 

container after it has off-loaded the 

waste; determine the quantity of waste 

received from the individual load as the 

difference in the two mass 

measurements; and determine the 

annual quantity of waste received as the 

sum of all waste loads received during 

the year. Alternatively, you may 


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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 reporting year, use methods 

in paragraph (a)(3) of this section when 

waste disposal quantity data are readily 

available. When waste disposal quantity 

data are not readily available, Wx shall 

be estimated using one of the applicable 

methods in paragraphs (a)(4)(i) through 

(a)(4)(iii) of this section. You must 

determine which method is most 

applicable to the conditions and 

disposal history of your facility. 

Historical waste disposal quantities 

should only be determined once, as part 

of the first annual report, and the same 

values should be used for all subsequent 

annual reports, supplemented by the 

next year’s data on new waste disposal. 

(i) Assume all prior years waste 

disposal quantities are the same as the 

waste quantity in the first year for 

which waste quantities are available. 

(ii) Use the estimated population 

served by the landfill in each year, the 

values for national average per capita 

waste disposal rates found in Table HH– 

2 to this subpart, and calculate the 

waste quantity landfilled using Equation 

HH–2 of this section. 

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 to 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)

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 a 

continuous monitoring system and N = 

365 (or N = 366 for leap years). For 

weekly sampling, as provided in 

paragraph (b)(2) of this section, use 

N=52. 

n = Index for measurement period. 

(V)n = Cumulative volumetric flow for the 

measurement period in actual cubic feet 

(acf). If the flow rate meter automatically 

corrects for temperature and pressure, 

replace ‘‘520°R/(T)n × (P)n/1 atm’’ with 

‘‘1’’. 

(KMC)n = Moisture correction term for the 

measurement period, volumetric basis, 

as follows: (KMC)n = 1 when (V)n and (C)n

are both measured on a dry basis or if 

both are measured on a wet basis; (KMC)n

= [1-(fH2O)n] when (V)n is measured on a 

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

basis; and (KMC)n = 1/[1-(fH2O)n] when 

(V)n is measured on a dry basis and (C)n

is measured on a wet basis. 

(fH2O)n = Average moisture content of landfill 

gas during the measurement period, 

volumetric basis (cubic feet water per 

cubic feet landfill gas) 

(CCH4)n = Average CH4 concentration of 

landfill gas for the measurement period 

(volume %). 

0.0423 = Density of CH4 lb/cfm at 520°R or 

60 degrees Fahrenheit and 1 atm. 

(T)n = Average temperature at which flow is 

measured for the measurement period 

(°R). 

(P)n = Average pressure at which flow is 

measured for the measurement period 

(atm). 

0.454/1,000 = Conversion factor (metric 

ton/lb). 

(2) If you do not continuously monitor 

according to paragraph (b)(1) of this 

section, you must determine the flow 

rate, CH4 concentration, temperature, 

pressure, and moisture content of the 

landfill gas that is collected and routed 

to a destruction device (before any 

treatment equipment) according to the 

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

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


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66472 Federal Register / Vol. 75, No. 208 / Thursday, October 28, 2010 / Rules and Regulations 

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 at least once each 

calendar week; if only one measurement 

is made each calendar week, there must 

be at least three days between 

measurements. 

(iii) * * * 

(A) Determine the temperature and 

pressure in the landfill gas that is 

collected and routed to a destruction 

device (before any treatment equipment) 

in a location near or representative of 

the location of the gas flow meter at 

least once each calendar week; if only 

one measurement is made each calendar 

week, there must be at least three days 

between measurements. 

(B) If the CH4 concentration is 

determined on a dry basis and flow is 

determined on a wet basis or CH4

concentration is determined on a wet 

basis and flow is determined on a dry 

basis, and the flow meter does not 

automatically correct for moisture 

content, determine the moisture content 

in the landfill gas that is collected and 

routed to a destruction device (before 

any treatment equipment) in a location 

near or representative of the location of 

the gas flow meter at least once each 

calendar week; if only one measurement 

is made each calendar week, there must 

be at least three days between 

measurements. 

(c) For all landfills, calculate CH4

generation (adjusted for oxidation in 

cover materials) and actual CH4

emissions (taking into account any CH4

recovery, and oxidation in cover 

materials) according to the applicable 

methods in paragraphs (c)(1) through 

(c)(3) of this section. 

* * * * * 

■ 53. Section 98.344 is amended by: 

■ a. Revising paragraph (a). 

■ b. Revising the first sentence of 

paragraph (b) introductory text. 

■ c. Revising paragraphs (b)(6)(ii) 

introductory text, (b)(6)(ii)(A), and 

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

■ d. Revising the definition of ‘‘CCH4’’ in 

Equation HH–9 of paragraph (b)(6)(iii). 

■ e. Revising the second and third 

sentences of paragraph (c) introductory 

text. 

■ f. Revising paragraph (d). 

■ g. Revising the first sentence of 

paragraph (e). 

The revisions read as follows: 

§ 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 

collection of a subsequent grab sample, 

determine the total gaseous organic 

concentration of the landfill gas using 

either Method 25A or 25B at 40 CFR 

part 60, appendix A–7 as specified in 

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

* * * * * 

(iii) * * * 

CCH4 = Methane concentration in the landfill 

gas (volume %) for use in Equation 

HH–4 of this subpart. 

* * * * * 

(c) * * * Each gas flow meter shall be 

recalibrated either biennially (every 2 

years) or at the minimum frequency 

specified by the manufacturer. Except as 

provided in § 98.343(b)(2)(i), each gas 

flow meter must be capable of correcting 

for the temperature and pressure and, if 

necessary, moisture content. 

* * * * * 

(d) All temperature, pressure, and if 

necessary, moisture content monitors 

must be calibrated using the procedures 

and frequencies specified by the 

manufacturer. 

(e) The owner or operator shall 

document the procedures used to ensure 

the accuracy of the estimates of disposal 

quantities and, if applicable, gas flow 

rate, gas composition, temperature, 

pressure, and moisture content 

measurements. * * * 

■ 54. Section 98.346 is amended by: 

■ a. Revising paragraph (a). 

■ b. Revising paragraph (b). 

■ c. Revising paragraph (c). 

■ d. Revising paragraph (d)(1). 

■ e. Revising paragraph (f). 

■ f. Revising paragraph (h). 

■ g. Revising paragraph (i)(1) 

■ h. Revising paragraph (i)(2) 

■ i. Revising paragraph (i)(3) 

■ j. Revising paragraph (i)(4) 

■ k. Revising paragraph (i)(5) 

■ l. Revising paragraph (i)(7). 

The revisions 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. 

(c) Waste composition for each year 

required for Equation HH–1 of this 

subpart, in percentage by weight, for 

each waste category listed in Table HH– 

1 to this subpart that is used in Equation 


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Federal Register / Vol. 75, No. 208 / Thursday, October 28, 2010 / Rules and Regulations 66473 

HH–1 of this subpart to calculate the 

annual modeled CH4 generation. 

(d) * * * 

(1) Degradable organic carbon (DOC), 

methane correction factor (MCF), and 

fraction of DOC dissimilated (DOCF) 

values used in the calculations. If an 

MCF value other than the default of 1 

is used, provide an indication of 

whether active aeration of the waste in 

the landfill was conducted during the 

reporting year, a description of the 

aeration system, including aeration 

blower capacity, the fraction of the 

landfill containing waste affected by the 

aeration, the total number of hours 

during the year the aeration blower was 

operated, and other factors used as a 

basis for the selected MCF value. 

* * * * * 

(f) The surface area of the landfill 

containing waste (in square meters), 

identification of the type of cover 

material used (as either organic cover, 

clay cover, sand cover, or other soil 

mixtures). If multiple cover types are 

used, the surface area associated with 

each cover type. 

* * * * * 

(h) For landfills without gas collection 

systems, the annual methane emissions 

(i.e., the methane generation, adjusted 

for oxidation, calculated using Equation 

HH–5 of this subpart), reported in 

metric tons CH4, and an indication of 

whether passive vents and/or passive 

flares (vents or flares that are not 

considered part of the gas collection 

system as defined in § 98.6) are present 

at this landfill. 

(i) * * * 

(1) Total volumetric flow of landfill 

gas collected for destruction for the 

reporting year (cubic feet at 520 °R or 60 

degrees Fahrenheit and 1 atm). 

(2) Annual average CH4 concentration 

of landfill gas collected for destruction 

(percent by volume). 

(3) Monthly average temperature and 

pressure for each month at which flow 

is measured for landfill gas collected for 

destruction, or statement that 

temperature and/or pressure is 

incorporated into internal calculations 

run by the monitoring equipment. 

(4) An indication as to whether flow 

was measured on a wet or dry basis, an 

indication as to whether CH4

concentration was measured on a wet or 

dry basis, and if required for Equation 

HH–4 of this subpart, monthly average 

moisture content for each month at 

which flow is measured for landfill gas 

collected for destruction. 

(5) An indication of whether 

destruction occurs at the landfill facility 

or off-site. If destruction occurs at the 

landfill facility, also report an 

indication of whether a back-up 

destruction device is present at the 

landfill, the annual operating hours for 

the primary destruction device, the 

annual operating hours for the back-up 

destruction device (if present), and the 

destruction efficiency used (percent). 

* * * * * 

(7) A description of the gas collection 

system (manufacturer, capacity, and 

number of wells), the surface area 

(square meters) and estimated waste 

depth (meters) for each area specified in 

Table HH–3 to this subpart, the 

estimated gas collection system 

efficiency for landfills with this gas 

collection system, the annual operating 

hours of the gas collection system, and 

an indication of whether passive vents 

and/or passive flares (vents or flares that 

are not considered part of the gas 

collection system as defined in § 98.6) 

are present at the landfill. 

* * * * * 

■ 55. Section 98.347 is amended by 

adding a second sentence to 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. 

■ 56. Section 98.348 is revised to read 

as follows: 

§ 98.348 Definitions. 

Except as specified in this section, all 

terms used in this subpart have the 

same meaning given in the Clean Air 

Act and subpart A of this part. 

Construction and demolition (C&D) 

waste landfill means a solid waste 

disposal facility subject to the 

requirements of part 257, subparts A or 

B of this chapter that receives 

construction and demolition waste and 

does not receive hazardous waste 

(defined in § 261.3 of this chapter) or 

industrial solid waste (defined in 

§ 258.2 of this chapter) or municipal 

solid waste (as defined in § 98.6) other 

than residential lead-based paint waste. 

A C&D waste landfill typically receives 

any one or more of the following types 

of solid wastes: Roadwork material, 

excavated material, demolition waste, 

construction/renovation waste, and site 

clearance waste. 

Destruction device means a flare, 

thermal oxidizer, boiler, turbine, 

internal combustion engine, or any 

other combustion unit used to destroy 

or oxidize methane contained in landfill 

gas. 

Industrial waste landfill means any 

landfill other than a municipal solid 

waste landfill, a RCRA Subtitle C 

hazardous waste landfill, or a TSCA 

hazardous waste landfill, in which 

industrial solid waste, such a RCRA 

Subtitle D wastes (nonhazardous 

industrial solid waste, defined in 

§ 257.2 of this chapter), commercial 

solid wastes, or conditionally exempt 

small quantity generator wastes, is 

placed. An industrial waste landfill 

includes all disposal areas at the 

facility. 

Solid waste has the meaning 

established by the Administrator 

pursuant to the Solid Waste Disposal 

Act (42 U.S.C.A. 6901 et seq.). 

Working capacity means the 

maximum volume or mass of waste that 

is actually placed in the landfill from an 

individual or representative type of 

container (such as a tank, truck, or 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. 

■ 57. Table HH–1 to subpart HH is 

revised to read as follows: 

TABLE HH–1 TO SUBPART HH OF PART 98—EMISSIONS FACTORS, OXIDATION FACTORS AND METHODS

Factor Default value Units 

DOC and k values—Bulk waste option 

DOC (bulk waste) ........................................................................................................ 0.20 .................... Weight fraction, wet basis. 

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


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TABLE HH–1 TO SUBPART HH OF PART 98—EMISSIONS FACTORS, OXIDATION FACTORS AND METHODS—Continued 

Factor Default value Units 

DOC and k values—Modified bulk MSW option 

DOC (bulk MSW, excluding inerts and C&D waste) ................................................... 0.31 .................... Weight fraction, wet basis. 

DOC (inerts, e.g., glass, plastics, metal, concrete) ..................................................... 0.00 .................... Weight fraction, wet basis. 

DOC (C&D waste) ....................................................................................................... 0.08 .................... Weight fraction, wet basis. 

k (bulk MSW, excluding inerts and C&D waste) ......................................................... 0.02 to 0.057 b .... yr¥1

k (inerts, e.g., glass, plastics, metal, concrete) ........................................................... 0.00 .................... yr¥1

k (C&D waste) .............................................................................................................. 0.02 to 0.04 b ...... yr¥1

DOC and k values—Waste composition option 

DOC (food waste) ........................................................................................................ 0.15 .................... Weight fraction, wet basis. 

DOC (garden) .............................................................................................................. 0.2 ...................... Weight fraction, wet basis. 

DOC (paper) ................................................................................................................ 0.4 ...................... Weight fraction, wet basis. 

DOC (wood and straw) ................................................................................................ 0.43 .................... Weight fraction, wet basis. 

DOC (textiles) .............................................................................................................. 0.24 .................... Weight fraction, wet basis. 

DOC (diapers) .............................................................................................................. 0.24 .................... Weight fraction, wet basis. 

DOC (sewage sludge) ................................................................................................. 0.05 .................... Weight fraction, wet basis. 

DOC (inerts, e.g., glass, plastics, metal, cement) ....................................................... 0.00 .................... Weight fraction, wet basis. 

k (food waste) .............................................................................................................. 0.06 to 0.185 c .... yr¥1

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

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

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

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

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

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

k (inerts e.g., glass, plastics, metal, concrete) ............................................................ 0.00 .................... yr¥1

Other parameters—All MSW landfills 

MCF ............................................................................................................................. 1. 

DOCF ............................................................................................................................ 0.5.

F ................................................................................................................................... 0.5.

OX ................................................................................................................................ 0.1.

DE ................................................................................................................................ 0.99.

a Recirculated leachate (in inches/year) is the total volume of leachate recirculated from company records or engineering estimates divided by 

the area of the portion of the landfill containing waste with appropriate unit conversions. Alternatively, landfills that use leachate recirculation can 

elect to use the k value of 0.057 rather than calculating the recirculated leachate rate. b Use the lesser value when precipitation plus recirculated leachate is less than 20 inches/year. Use the greater value when precipitation plus 

recirculated leachate is greater than 40 inches/year. Use the average of the range of values when precipitation plus recirculated leachate is 20 to 

40 inches/year (inclusive). Alternatively, landfills that use leachate recirculation can elect to use the greater value rather than calculating the recirculated leachate rate. c Use the lesser value when the potential evapotranspiration rate exceeds the mean annual precipitation rate plus recirculated leachate. Use 

the greater value when the potential evapotranspiration rate does not exceed the mean annual precipitation rate plus recirculated leachate. Alternatively, landfills that use leachate recirculation can elect to use the greater value rather than assessing the potential evapotranspiration rate or 

recirculated leachate rate. 

■ 58. Table HH–2 to subpart HH is 

amended by: 

■ a. Removing the third column ‘‘% to 

SWDS.’’ 

■ b. Removing the entries for ‘‘1950’’ 

through ‘‘1959.’’ 

■ c. Revising the entries for ‘‘1989’’ 

through ‘‘2006.’’ 

■ d. Adding entries for ‘‘2007’’ through 

‘‘2009.’’ 

TABLE HH–2 TO SUBPART HH OF

PART 98—U.S. PER CAPITA WASTE

DISPOSAL RATES

Year 

Waste per 

capita 

ton/cap/yr 

****

1989 .......................................... 0.83 

TABLE HH–2 TO SUBPART HH OF

PART 98—U.S. PER CAPITA WASTE

DISPOSAL RATES—Continued 

Year 

Waste per 

capita 

ton/cap/yr 

1990 .......................................... 0.82 

1991 .......................................... 0.76 

1992 .......................................... 0.74 

1993 .......................................... 0.76 

1994 .......................................... 0.75 

1995 .......................................... 0.70 

1996 .......................................... 0.68 

1997 .......................................... 0.69 

1998 .......................................... 0.75 

1999 .......................................... 0.75 

2000 .......................................... 0.80 

2001 .......................................... 0.91 

2002 .......................................... 1.02 

2003 .......................................... 1.02 

2004 .......................................... 1.01 

2005 .......................................... 0.98 

TABLE HH–2 TO SUBPART HH OF

PART 98—U.S. PER CAPITA WASTE

DISPOSAL RATES—Continued 

Year 

Waste per 

capita 

ton/cap/yr 

2006 .......................................... 0.95 

2007 .......................................... 0.95 

2008 .......................................... 0.95 

2009 .......................................... 0.95 

■ 59. Table HH–3 to subpart HH–3 is 

amended by revising the entries for ‘‘A2: 

Area without active gas collection, 

regardless of cover type H2: Average 

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

with daily soil cover and active gas 

collection H3: Average depth of waste in 

area A3,’’ ‘‘A4: Area with an 

intermediate soil cover and active gas 


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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: 

TABLE HH–3 TO SUBPART HH OF PART 98—LANDFILL GAS COLLECTION EFFICIENCIES

Description Landfill gas collection efficiency 

*******

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

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

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

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

*******

Subpart LL—[Amended] 

■ 60. Section 98.386 is amended by: 

■ a. Revising paragraph (a)(3). 

■ b. Adding a third sentence to the end 

of paragraph (a)(5). 

■ c. Adding a third sentence to the end 

of paragraph (a)(6). 

■ d. Revising paragraph (a)(7). 

■ e. Revising paragraphs (a)(16) and 

(a)(17). 

■ f. Revising paragraphs (b)(3) and 

(c)(3). 

■ g. Adding paragraph (d). 

The revisions and additions read as 

follows: 

§ 98.386 Data reporting requirements. 

* * * * * 

(a) * * * 

(3) For each feedstock reported in 

paragraph (a)(2) of this section that was 

produced by blending a fossil fuel-based 

product with a biomass-based product, 

report the percent of the volume 

reported in paragraph (a)(2) of this 

section that is fossil fuel-based 

(excluding any denaturant that may be 

present in any ethanol product). 

* * * * * 

(5) * * * Those products that enter 

the facility, but are not reported in 

(a)(1), shall not be reported under this 

paragraph. 

(6) * * * Those products that enter 

the facility, but are not reported in 

(a)(2), shall not be reported under this 

paragraph. 

(7) For each product reported in 

paragraph (a)(6) of this section that was 

produced by blending a fossil fuel-based 

product with a biomass-based product, 

report the percent of the volume 

reported in paragraph (a)(6) of this 

section that is fossil fuel-based 

(excluding any denaturant that may be 

present in any ethanol product). 

* * * * * 

(16) The CO2 emissions in metric tons 

that would result from the complete 

combustion or oxidation of each 

feedstock reported in paragraph (a)(2) of 

this section that were calculated 

according to § 98.393(b) or (h). 

(17) The CO2 emissions in metric tons 

that would result from the complete 

combustion or oxidation of each 

product (leaving the coal-to-liquid 

facility) reported in paragraph (a)(6) of 

this section that were calculated 

according to § 98.393(a) or (h). 

* * * * * 

(b) * * * 

(3) For each product reported in 

paragraph (b)(2) of this section that was 

produced by blending a fossil fuel-based 

product with a biomass-based product, 

report the percent of the volume 

reported in paragraph (b)(2) of this 

section that is fossil fuel-based 

(excluding any denaturant that may be 

present in any ethanol product). 

* * * * * 

(c) * * * 

(3) For each product reported in 

paragraph (c)(2) of this section that was 

produced by blending a fossil fuel-based 

product with a biomass-based product, 

report the percent of the volume 

reported in paragraph (c)(2) of this 

section that is fossil fuel-based 

(excluding any denaturant that may be 

present in any ethanol product). 

* * * * * 

(d) Blended feedstock and products. 

(1) Producers, exporters, and importers 

must report the following information 

for each blended product and feedstock 

where emissions were calculated 

according to § 98.393(i): 

(i) Volume or mass of each blending 

component. 

(ii) The CO2 emissions in metric tons 

that would result from the complete 

combustion or oxidation of each 

blended feedstock or product, using 

Equation MM–12 or Equation MM–13 of 

§ 98.393. 

(iii) Whether it is a blended feedstock 

or a blended product. 

(2) For a product that enters the 

facility to be further refined or 

otherwise used on site that is a blended 

feedstock, producers must meet the 

reporting requirements of paragraphs 

(a)(1) and (a)(2) of this section by 

reflecting the individual components of 

the blended feedstock. 

(3) For a product that is produced, 

imported, or exported that is a blended 

product, producers, importers, and 

exporters must meet the reporting 

requirements of paragraphs (a)(5), (a)(6), 

(b)(1), (b)(2), (c)(1), and (c)(2) of this 

section, as applicable, by reflecting the 

individual components of the blended 

product. 

Subpart MM—[Amended] 

■ 61. Section 98.393 is amended by: 

■ a. In paragraph (a)(1), revising the 

only sentence and the definition of 

‘‘Producti’’ in Equation MM–1. 

■ b. Revising the definition of ‘‘Producti’’ 

in Equation MM–2 of paragraph (a)(2). 

■ c. Revising the only sentence of 

paragraph (b)(1) and the first sentence in 

paragraph (f)(1). 

■ d. Revising the definition of ‘‘%Voli’’ 

in Equation MM–8 in paragraph (h)(1). 

■ e. Revising Equation MM–9 and the 

definition of ‘‘%Volj’’ in paragraph 

(h)(2). 

■ f. Revising paragraphs (h)(3) and 

(h)(4). 

■ g. Adding paragraph (i). 

The revisions and additions read as 

follows: 

§ 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 


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refinery gate, and excludes products that 

entered the refinery but are not reported 

under § 98.396(a)(1). For natural gas 

liquids, volumes shall reflect the 

individual components of the product as 

listed in Table MM–1 to subpart MM. 

* * * * * 

(2) * * * 

Producti = Annual mass of product ‘‘i’’ 

produced, imported, or exported by the 

reporting party (metric tons). For 

refiners, this mass only includes 

products ex refinery gate, and excludes 

products that entered the refinery but are 

not reported under § 98.396(a)(1). 

* * * * * 

(b) * * * 

(1) Except as provided in paragraphs 

(h) and (i) of this section, any refiner 

shall calculate CO2 emissions from each 

non-crude feedstock using Equation 

MM–2 of this section. 

* * * * * 

(f) * * * 

(1) Calculation Method 1. To 

determine the emission factor (i.e., EFi

in Equation MM–1) for solid products, 

multiply the default carbon share factor 

(i.e., percent carbon by mass) in column 

B of Table MM–1 to this subpart for the 

appropriate product by 44/12. * * * 

* * * * * 

(h) * * * 

(1) * * * 

%Voli = Percent volume of product ‘‘i’’ that 

is petroleum-based, not including any 

denaturant that may be present in any 

ethanol product, expressed as a fraction 

(e.g., 75% would be expressed as 0.75 in 

the above equation). 

(2) * * * 

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 

Method 2 of this subpart to determine 

the emission factor of a petroleum 

product that does not contain denatured 

ethanol must calculate the CO2

emissions associated with that product 

using Equation MM–10 of this section in 

place of Equation MM–1 of this section. 

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 to subpart MM that most closely 

represents the component of product ‘‘i’’ 

that is biomass-based. 

%Volm = Percent volume of petroleum 

product ‘‘i’’ that is biomass-based, 

expressed as a fraction (e.g., 75% would 

be expressed as 0.75 in the above 

equation). 

(ii) In the event that a petroleum 

product contains denatured ethanol, 

importers and exporters must follow 

Calculation Method 1 procedures in 

paragraph (h)(1) of this section; and 

refineries must sample the petroleum 

portion of the blended biomass-based 

fuel prior to blending and calculate CO2

emissions using Equation MM–10a of 

this section. 

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 = Annual CO2 emissions that would 

result from the complete combustion or 

oxidation of each non-crude feedstock ‘‘j’’ 

(metric tons). 

Feedstockj = Annual volume of each 

petroleum product ‘‘j’’ that enters the 

refinery to be further refined or 

otherwise used on site (barrels). 

EFj = Feedstock-specific CO2 emission factor 

(metric tons CO2 per barrel). 

EFm = Default CO2 emission factor from Table 

MM–2 to subpart MM that most closely 

represents the component of petroleum 

product ‘‘j’’ that is biomass-based. 

%Volm = Percent volume of non-crude 

feedstock ‘‘j’’ that is biomass-based, 

expressed as a fraction (e.g., 75% would 

be expressed as 0.75 in the above 

equation). 

(ii) In the event that a non-crude 

feedstock contains denatured ethanol, 

refiners must follow Calculation Method 

1 procedures in paragraph (h)(2) of this 

section. 

(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 


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Federal Register / Vol. 75, No. 208 / Thursday, October 28, 2010 / Rules and Regulations 66477 

to the method in paragraph (i)(3) of this 

section. The procedures in this section 

may be used only if all of the following 

criteria are met: 

(i) The reporter knows the relative 

proportion of each component of the 

blend (i.e., the mass or volume 

percentage). 

(ii) Each component of blended 

product ‘‘i’’ or blended non-crude 

feedstock ‘‘j’’ meets the strict definition 

of a product listed in Table MM–1 to 

subpart MM. 

(iii) The blended product or 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 = CO2 emission factors specific to each 

blending component (metric tons CO2

per barrel or per metric ton of product). 

n = Number of blending components blended 

into blended non-crude feedstock ‘‘j’’. 

(4) For refineries, if a blending 

component ‘‘k’’ used in paragraph (i)(2) 

of this section enters the refinery before 

blending as non-crude feedstock: 

(i) The emissions that would result 

from the complete combustion or 

oxidation of non-crude feedstock ‘‘k’’ 

must still be calculated separately using 

Equation MM–2 of this section and 

applied in Equation MM–4 of this 

section. 

(ii) The quantity of blending 

component ‘‘k’’ applied in Equation 

MM–12 of this section and the quantity 

of non-crude feedstock ‘‘k’’ applied in 

Equation MM–2 of this section must be 

determined using the same method or 

practice. 

■ 62. Section 98.394 is amended by: 

■ a. Revising paragraph (a)(1) 

introductory text. 

■ b. Adding paragraph (a)(3). 

■ c. Revising paragraphs (d)(1) through 

(d)(4). 

The revisions and additions read as 

follows: 

§ 98.394 Monitoring and QA/QC 

requirements. 

(a) * * * 

(1) The quantity of petroleum 

products, natural gas liquids, and 

biomass, as well as the quantity of crude 

oil measured on site at a refinery, shall 

be determined as follows: 

* * * * * 

(3) The quantity of crude oil not 

measured on site at a refinery shall be 

determined according to one of the 

following methods. You may use an 

appropriate standard method published 

by a consensus-based standards 

organization or you may use an industry 

standard practice. 

* * * * * 

(d) * * * 

(1) A representative sample or 

multiple representative samples of each 

batch of crude oil shall be taken 

according to one of the following 

methods. You may use an appropriate 

standard method published by a 

consensus-based standards organization 

or you may use an industry standard 

practice. 

(2) Samples shall be handled 

according to one of the following 

methods. You may use an appropriate 

standard method published by a 

consensus-based standards organization 

or you may use an industry standard 

practice. 

(3) API gravity shall be measured 

according to one of the following 

methods. You may use an appropriate 

standard method published by a 

consensus-based standards organization 

or you may use an industry standard 

practice. The weighted average API 

gravity for each batch shall be 

calculated by multiplying the volume 

associated with each representative 

sample by the API gravity, adding these 

values for all the samples, and then 

dividing that total value by the volume 

of the batch. 

(4) Sulfur content shall be measured 

according to one of the following 

methods. You may use an appropriate 

standard method published by a 

consensus-based standards organization 

or you may use an industry standard 

practice. The weighted average sulfur 

content for each batch shall be 

calculated by multiplying the volume 

associated with each representative 

sample by the sulfur content, adding 

these values for all the samples, and 

then dividing that total value by the 

volume of the batch. 

* * * * * 

■ 63. Section 98.396 is amended by: 

■ a. Revising paragraph (a)(3). 

■ b. Amending paragraphs (a)(5) and 

(a)(6) by adding a third sentence. 

■ c. Revising paragraphs (a)(7), (a)(16), 

and (a)(17), (a)(20)(ii), (a)(20)(iii), and 

(a)(20)(iv). 

■ d. Adding paragraphs (a)(20)(v), 

(a)(20)(vi), (a)(22), and (a)(23). 

■ e. Revising paragraphs (b)(3) and 

(c)(3). 

■ f. Adding paragraph (d). 

§ 98.396 Data reporting requirements. 

* * * * * 

(a) * * * 

(3) For each feedstock reported in 

paragraph (a)(2) of this section that was 

produced by blending a petroleumbased product with a biomass-based 

product, report the percent of the 

volume reported in paragraph (a)(2) of 

this section that is petroleum-based 


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(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). 

* * * * * 

(16) The CO2 emissions in metric tons 

that would result from the complete 

combustion or oxidation of each 

petroleum product and natural gas 

liquid (ex refinery gate) reported in 

paragraph (a)(6) of this section that were 

calculated according to § 98.393(a) or 

(h). 

(17) The CO2 emissions in metric tons 

that would result from the complete 

combustion or oxidation of each 

feedstock reported in paragraph (a)(2) of 

this section that were calculated 

according to § 98.393(b) or (h). 

* * * * * 

(20) * * * 

(ii) Weighted average API gravity 

representing the batch at the point of 

entry at the refinery. 

(iii) Weighted average sulfur content 

representing the batch at the point of 

entry at the refinery. 

(iv) Country of origin, of the batch, if 

known and data in paragraphs (a)(20)(v) 

and (a)(20)(vi) of this section are 

unknown. 

(v) EIA crude stream code and crude 

stream name of the batch, if known. 

(vi) Generic name for the crude stream 

and the appropriate EIA two-letter 

country or state and production area 

code of the batch, if known and no 

appropriate EIA crude stream code 

exists. 

* * * * * 

(22) Volume of crude oil in barrels 

that you injected into a crude oil supply 

or reservoir. A volume of crude oil that 

entered the refinery, but was not 

reported in paragraphs (a)(2) or (a)(20), 

shall not be reported under this 

paragraph. 

(23) Special provisions for 2010. For 

reporting year 2010 only, a refiner that 

knows the information under a specific 

tier of the batch definition in 40 CFR 

98.398, but does not have the necessary 

data collection and management in 

place to readily report this information, 

can use the next most appropriate tier 

of the batch definition for reporting 

batch information under paragraph 

98.396(a)(20). 

(b) * * * 

(3) For each product reported in 

paragraph (b)(2) of this section that was 

produced by blending a petroleumbased product with a biomass-based 

product, report the percent of the 

volume reported in paragraph (b)(2) of 

this section that is petroleum-based 

(excluding any denaturant that may be 

present in any ethanol product). 

* * * * * 

(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. 

(iii) Whether it is a blended non-crude 

feedstock or a blended product. 

(2) For a product that enters the 

refinery to be further refined or 

otherwise used on site that is a blended 

non-crude feedstock, refiners must meet 

the reporting requirements of 

paragraphs (a)(1) and (a)(2) of this 

section by reflecting the individual 

components of the blended non-crude 

feedstock. 

(3) For a product that is produced, 

imported, or exported that is a blended 

product, refiners, importers, and 

exporters must meet the reporting 

requirements of paragraphs (a)(5), (a)(6), 

(b)(1), (b)(2), (c)(1), and (c)(2) of this 

section, as applicable, by reflecting the 

individual components of the blended 

product. 

■ 64. Section 98.397 is amended by: 

a. Revising the second sentence of 

paragraph (b). 

b. Removing paragraph (e). 

c. Redesignating paragraphs (f) and (g) 

as (e) and (f), respectively. 

The amended text reads as follows: 

§ 98.397 Records that must be retained. 

* * * * * 

(b) * * * For all reported quantities of 

petroleum products, natural gas liquids, 

and biomass, as well as crude oil 

quantities measured on site at a refinery, 

reporters shall maintain metering, 

gauging, and other records normally 

maintained in the course of business to 

document product and feedstock flows 

including the date of initial calibration 

and the frequency of recalibration for 

the measurement equipment used. 

* * * * * 

■ 65. Section 98.398 is revised to read 

as follows: 

§ 98.398 Definitions. 

Except as specified in this section, all 

terms used in this subpart have the 

same meaning given in the Clean Air 

Act and subpart A of this part. 

Batch means either a volume of crude 

oil that enters a refinery or the 

components of such volume (e.g., the 

volumes of different crude streams that 

are blended together and then delivered 

to a refinery). The batch volume is the 

first appropriate tier in the following 

list: 

(1) Up to an annual volume of a type 

of crude oil identified by an EIA crude 

stream code, if the EIA crude stream 

code is known. 

(2) Up to an annual volume of a type 

of crude oil identified by a generic name 

for the crude stream and an appropriate 

EIA two-letter country or state and 

production area code, if the generic 

name and EIA two-letter code are 

known but no appropriate EIA crude 

stream code exists. 

(3) Up to a calendar month of crude 

oil volume from a single known foreign 

country of origin if the crude stream 

name is unknown. 

(4) Up to a calendar month of crude 

oil volume from the United States if the 

crude stream name and production area 

are unknown. 

(5) Up to a calendar month of crude 

oil volume if the country of origin is 

unknown. 

Subpart NN—[Amended] 

■ 66. Section 98.403 is amended by: 

■ a. Revising the definitions of ‘‘Fuelh’’ 

and ‘‘HHVh’’ in Equation NN–1 of 

paragraph (a)(1). 

■ b. Revising the definition of ‘‘Fuelh’’ in 

Equation NN–2 of paragraph (a)(2). 

■ c. Revising the definition of ‘‘Fuel1’’ in 

Equation NN–5 of paragraph (b)(3). 


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■ d. Revising the definition of ‘‘EFg’’ in 

Equation NN–7 of paragraph (c)(1). 

■ e. In paragraph (c)(2), revising 

Equation NN–8 and the definition of 

‘‘CO2i’’ in Equation NN–8. 

The revisions read as follows: 

§ 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)

* * * * * 

CO2i = Annual CO2 mass emissions that 

would result from the combustion or 

oxidation of fractionated NGLs delivered 

to all customers or on behalf of 

customers as calculated in paragraph 

(a)(1) or (a)(2) of this section (metric 

tons). 

* * * * * 

■ 67. Section 98.406 is amended by 

revising paragraphs (a)(6) and (a)(9) 

introductory text to read as follows: 

§ 98.406 Data reporting requirements. 

(a) * * * 

(6) Annual CO2 emissions (metric 

tons) that would result from the 

complete combustion or oxidation of the 

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: 

* * * * * 

■ 68. Section 98.407 is amended by 

revising paragraphs (a) and (d) to read 

as follows: 

§ 98.407 Records that must be retained. 

* * * * * 

(a) Records of all meter readings and 

documentation to support volumes of 

natural gas and NGLs that are reported 

under this part. 

* * * * * 

(d) Records related to the large endusers identified in § 98.406(b)(7). 

* * * * * 

■ 69. Tables NN–1 and NN–2 to Subpart 

NN are revised to read as follows: 

TABLE NN–1 TO SUBPART NN OF PART 98—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 TO SUBPART NN OF PART 98—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. 2010–26506 Filed 10–27–10; 8:45 am] 

BILLING CODE 6560–50–P 


srobinson on DSKHWCL6B1PROD with RULES2ER28OC10.043</MATH>