6560.50 

ENVIRONMENTAL PROTECTION AGENCY 

40 CFR Part 98 

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

RIN 2060-AQ33 

Mandatory Reporting of Greenhouse Gases 

AGENCY: Environmental Protection Agency (EPA). 

ACTION: Final rule

SUMMARY: EPA is amending specific provisions in the 

greenhouse gas reporting rule to clarify certain 

provisions, to correct technical and editorial errors, and 

to address certain questions and issues that have arisen 

since promulgation. These final changes include generally 

providing additional information and clarity on existing 

requirements, allowing greater flexibility or simplified 

calculation methods for certain sources, amending data 

reporting requirements to provide additional clarity on 

when different types of greenhouse gas emissions need to be 

calculated and reported, clarifying terms and definitions 

in certain equations and other technical corrections and 

amendments. 

DATES: The final rule is effective on December 31, 2010. 

The incorporation by reference of certain publications 
Page 2 of 442 

listed in the final rule amendments are approved by the 

director of the Federal Register as of December 31, 2010. 

ADDRESSES: EPA has established a docket under Docket ID 

No. EPA–HQ–OAR–2008-0508 for this action. All documents in 

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

index. Although listed in the index, some information is 

not publicly available, e.g., confidential business 

information (CBI) or other information whose disclosure is 

restricted by statute. Certain other material, such as 

copyrighted material, is not placed on the Internet and 

will be publicly available only in hard copy form. 

Publicly available docket materials are available either 

electronically through 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 
Page 3 of 442 

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 website 

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

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

Rule Help Center, followed by Contact Us. 

SUPPLEMENTARY INFORMATION: 

Regulated Entities. The Administrator determined that 

this action is subject to the provisions of Clean Air Act 

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

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

as the Administrator may determine”). These are final 

amendments to existing regulations. These amended 

regulations affect owners or operators of certain suppliers 

and direct emitters of greenhouse gases (GHGs). Regulated 

categories and entities include those listed in Table 1 of 

this preamble: 

Table 1. Examples of Affected Entities by Category 

Category NAICS Examples of affected facilities 

Facilities operating boilers, 

process heaters, incinerators, 

turbines, and internal combustion 

engines. 

211 Extractors of crude petroleum and 

natural gas. 

321 Manufacturers of lumber and wood 

products. 

322 Pulp and paper mills. 

General 

Stationary Fuel 

Combustion 

Sources 

325 Chemical manufacturers. 
Page 4 of 442 

Category NAICS Examples of affected facilities 

324 Petroleum refineries and 

manufacturers of coal products. 

316, 326, 

339 

Manufacturers of rubber and 

miscellaneous plastic products. 

331 Steel works, blast furnaces. 

332 Electroplating, plating, polishing, 

anodizing, and coloring. 

336 Manufacturers of motor vehicle 

parts and accessories. 

221 Electric, gas, and sanitary 

services. 

622 Health services. 

611 Educational services.

Electricity 

Generation 

221112 Fossil-fuel fired electric 

generating units, including units 

owned by Federal and municipal 

governments and units located in 

Indian Country. 

Adipic Acid 

Production 

325199 Adipic acid manufacturing 

facilities. 

Aluminum 

Production 

331312 Primary aluminum production 

facilities 

Ammonia 

Manufacturing 

325311 Anhydrous and aqueous ammonia 

production facilities. 

Cement 

Production 

327310 Portland Cement manufacturing 

plants. 

Ferroalloy 

Production 

331112 Ferroalloys manufacturing 

facilities. 

327211 Flat glass manufacturing 

facilities. 

327213 Glass container manufacturing 

facilities. 

Glass Production

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 production facilities 

Iron and Steel 

Production 

331111 Integrated iron and steel mills, 

steel companies, sinter plants, 

blast furnaces, basic oxygen 

process furnace shops. 

331419 Primary lead smelting and refining 

facilities. 

Lead Production 

331492 Secondary lead smelting and 

refining facilities. 
Page 5 of 442 

Category NAICS Examples of affected facilities 

Lime Production 327410 Calcium oxide, calcium hydroxide, 

dolomitic hydrates manufacturing 

facilities. 

Iron and Steel 

Production 

331111 Integrated iron and steel mills, 

steel companies, sinter plants, 

blast furnaces, basic oxygen 

process furnace shops. 

Lead Production 331419 Primary lead smelting and refining 

facilities. 

Nitric Acid 

Production 

325311 Nitric acid production facilities 

32511 Ethylene dichloride production 

facilities. 

325199 Acrylonitrile, ethylene oxide, 

methanol production facilities. 

325110 Ethylene production facilities. 

Petrochemical 

Production 

325182 Carbon black production facilities. 

Petroleum 

Refineries 

324110 Petroleum refineries. 

Phosphoric Acid 

Production 

325312 Phosphoric acid manufacturing 

facilities. 

322110 Pulp mills. 

322121 Paper mills. 

Pulp and Paper 

Manufacturing 

322130 Paperboard mills. 

Silicon Carbide 

Production 

327910 Silicon carbide abrasives 

manufacturing facilities. 

325181 Alkalies and chlorine manufacturing 

facilities. 

Soda Ash 

Manufacturing 

212391 Soda ash, natural, mining and/or 

beneficiation. 

Titanium Dioxide 

Production 

325188 Titanium dioxide manufacturing 

facilities. 

Zinc Production 331419 Primary zinc refining facilities. 

331492 Zinc dust reclaiming facilities, 

recovering from scrap and/or 

alloying purchased metals. 

Municipal Solid 562212 Solid waste landfills. 

Waste Landfills 221320 Sewage treatment facilities. 

112111 Beef cattle feedlots. 

112120 Dairy cattle and milk production 

facilities. 

112210 Hog and pig farms. 

112310 Chicken egg production facilities. 

112330 Turkey Production 

Manure 

Managementa

112320 Broilers and other meat type 

chicken production. 

Suppliers of 

Natural Gas and 

221210 Natural gas distribution 

facilities. 
Page 6 of 442 

Category NAICS Examples of affected facilities 

NGLs 211112 Natural gas liquid extraction 

facilities. 

Suppliers of 

Industrial GHGs 

325120 Industrial gas production 

facilities. 

Suppliers of 

Carbon Dioxide 

(CO2) 

325120 Industrial gas production 

facilities. 

a

 EPA will not be implementing subpart JJ of 40 CFR part 98 using funds 

provided in its FY2010 appropriations or Continuing Appropriations Act, 

2011 (Public Law 111-242), due to a Congressional restriction 

prohibiting the expenditure of funds for this purpose. 

Table 1 of this preamble is not intended to be 

exhaustive, but rather provides a guide for readers 

regarding facilities and suppliers likely to be affected by 

this action. Table 1 of this preamble lists the types of 

facilities and suppliers that EPA is now aware could be 

potentially affected by the reporting requirements. Other 

types of facilities and suppliers 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 subparts. If you have questions regarding the 

applicability of this action to a particular facility or 

supplier, consult the person listed in the preceding FOR 

FURTHER GENERAL INFORMATION CONTACT section. 

What is the effective date? The final rule is 

effective on December 31, 2010. Section 553(d) of the 

Administrative Procedure Act (APA), 5 U.S.C. Chapter 5, 
Page 7 of 442 

generally provides that rules may not take effect earlier 

than 30 days after they are published in the Federal 

Register. EPA is issuing this final rule under section 

307(d)(1) of the Clean Air Act, which states: “The 

provisions of section 553 through 557 . . . of Title 5 

shall not, except as expressly provided in this section, 

apply to actions to which this subsection applies.” Thus, 

section 553(d) of the APA does not apply to this rule. EPA 

is nevertheless acting consistently with the purposes 

underlying APA section 553(d) in making this rule effective 

on December 31, 2010. Section 5 U.S.C. 553(d)(3) allows an 

effective date less than 30 days after publication “as 

otherwise provided by the agency for good cause found and 

published with the rule.” As explained below, EPA finds 

that there is good cause for this rule to become effective 

on December 31, 2010, even though this results in an 

effective date fewer than 30 days from date of publication 

in the Federal Register. 

While this action is being signed prior to December 1, 

2010, there is likely to be a significant delay in the 

publication of this rule as it contains complex equations 

and tables and is relatively long in length. As an 

example, EPA signed a shorter technical amendments package 

related to the same underlying reporting rule on October 7, 
Page 8 of 442 

2010, and it was not published until October 28, 2010 (75 

FR 66434), three weeks later. 

The purpose of the 30-day waiting period prescribed in 

5 U.S.C. 553(d) is to give affected parties a reasonable 

time to adjust their behavior and prepare before the final 

rule takes effect. Where, as here, the final rule will be 

signed and made available on the EPA website more than 30 

days before the effective date, but where the publication 

is likely to be delayed due to the complexity and length of 

the rule, that purpose is still met. Moreover, most of the 

revisions being made in this package provide flexibilities 

to sources covered by the reporting rule, or otherwise 

relieve a restriction. Thus, a shorter effective date in 

such circumstances is consistent with the purposes of APA 

section 553(d), which provides an exception for any action 

that grants or recognizes an exemption or relieves a 

restriction. Accordingly, we find good cause exists to 

make this rule effective on December 31, 2010, consistent 

with the purposes of 5 U.S.C. 553(d)(3). 

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

judicial review of this final rule is available only by 

filing a petition for review in the U.S. Court of Appeals 

for the District of Columbia Circuit (the Court) by [INSERT 

THE DATE 60 DAYS FROM PUBLICATION IN THE FEDERAL REGISTER]. 
Page 9 of 442 

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. CAA section 307(d)(7)(B) 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 
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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. 

API American Petroleum Institute 

ARP Acid Rain Program 

ASME American Society of Mechanical Engineers 

ASTM American Society for Testing and Materials 

BAMM best available monitoring method 

CAA Clean Air Act 

cc cubic centimeters 

CE calibration error 

CEMS continuous emission monitoring system 

CFR Code of Federal Regulations 

CGA Cylinder gas audit 

CH4 methane 

CO carbon monoxide 

CO2 carbon dioxide 

CO2e CO2-equivalent 

CWPB center worked prebake 

FR Federal Register 

FTIR Fourier transform infrared 

GC gas chromatography 

GHG greenhouse gas 

GHGRP Greenhouse Gas Reporting Program 

GPA Gas Processors Association 

GWP global warming potential 

HFCs hydrofluorocarbons 

HHV high heat value 

HSS horizontal stud Søderberg 

IPCC Intergovernmental Panel on Climate Change 

IR infrared 

LDCs local natural gas distribution companies 
Page 11 of 442 

mmBtu/hr million British thermal units per hour 

mscf thousand standard cubic feet 

MSW municipal solid waste 

mtCO2e metric tons of CO2 equivalents 

MVC molar volume conversion factor 

NESHAP National Emission Standards for Hazardous Air 

Pollutants 

NIST National Institute of Standards and Technology 

NMR nuclear magnetic resonance 

NSPS New Source Performance Standards 

N2O nitrous oxide 

NAICS North American Industry Classification System 

NGLs natural gas liquids 

O2 oxygen 

OMB Office of Management and Budget 

PFC perfluorocarbon 

psia pounds per square inch absolute 

QA quality assurance 

QA/QC quality assurance/quality control 

RATA relative accuracy test audit 

RFA Regulatory Flexibility Act 

scf standard cubic feet 

scfm standard cubic feet per minute 

SF6 sulfur hexafluoride 

SO2 sulfur dioxide 

SWPB side worked prebake 

U.S. United States 

VSS vertical stud Søderberg 

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?
Page 12 of 442 

II. Final Amendments and Responses to Public Comments

A. Subpart A - General Provisions: Best Available 

Monitoring Methods

B. Subpart A - General Provisions: Calibration 

Requirements

C. Subpart A - General Provisions: Reporting of Biogenic 

Emissions

D. Subpart A - General Provisions: Requirements for 

Correction and Resubmission of Annual Reports

E. Subpart A - General Provisions: Information to Record 

for Missing Data Events

F. Subpart A - General Provisions: Other Technical 

Corrections and Amendments

G. Subpart C - General Stationary Fuel Combustion

H. Subpart D - Electricity Generation

I. Subpart F - Aluminum Production

J. Subpart G - Ammonia Manufacturing

K. Subpart P - Hydrogen Production

L. Subpart V - Nitric Acid Production

M. Subpart X - Petrochemical Production

N. Subpart Y - Petroleum Refineries

O. Subpart AA - Pulp and Paper Manufacturing

P. Subpart NN - Suppliers of Natural Gas and Natural Gas 

Liquids

Q. Subpart OO - Suppliers of Industrial Greenhouse Gases

R. Subpart PP - Suppliers of Carbon Dioxide

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 LowIncome Populations

K. Congressional Review Act

I. Background 

A. How is this preamble organized?
Page 13 of 442 

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 on GHGs. 

The second section of this preamble describes in 

detail the rule changes that are being promulgated to, 

among other things, correct technical errors, provide 

clarification, and 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 discusses the 

various statutory and executive order requirements 

applicable to this rulemaking. 

B. Background on This Action

The final Mandatory Reporting of Greenhouse Gases Rule 

was signed by EPA Administrator Lisa Jackson on September 

22, 2009 and published in the Federal Register on October 

30, 2009 (74 FR 56260-56519). This rule, which added Part 

98 to chapter 40 of the Code of Federal Regulations (CFR) 

as well as amending other parts of 40 CFR, became effective 

on December 29, 2009, and included reporting of GHG 

information from facilities and suppliers, consistent with 
Page 14 of 442 

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 

certain suppliers (e.g., fossil fuel, petroleum products, 

industrial gases and CO2) and manufacturers of mobile 

sources. 

EPA published a notice proposing these 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 August 

11, 2010 (75 FR 48744). The public comment period for the 

proposed rule amendments ended on September 27, 2010. EPA 

did not receive any requests to hold a public hearing. 

This is the second time that EPA has published a 

notice promulgating amendments to Part 98 to, among other 

things, correct certain technical and editorial errors 

identified since Part 98 was originally promulgated and to 

clarify and amend certain provisions that have been the 

subject of questions from reporting entities. The first 

final rule amendments were published on October 28, 2010 

(75 FR 66434). This final rule complements the final rule 

 

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

1844, 2128. 
Page 15 of 442 

published on October 28, 2010 and is not intended to 

duplicate or replace those amendments. 

C. Legal Authority

EPA is promulgating these rule amendments under its 

existing CAA authority, specifically authorities provided 

in CAA section 114. 

As stated in the preamble to the 2009 final rule (74 

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

broad authority to require the information mandated by Part 

98 because such data would inform and are relevant to EPA’s 

obligation to carry out a wide variety of CAA provisions. 

As discussed in the preamble to the initial proposal (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. For further information about EPA’s legal 

authority, see the preambles to the proposed and final 

rule, and Response to Comments Documents.2

 

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

Response to Comments Documents can be found at 

http://www.epa.gov/climatechange/emissions/responses.html
Page 16 of 442 

D. How will these amendments apply to 2011 reports?

We have determined that it is feasible for sources 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.3 

In response to general comments submitted on the proposed 

rulemaking, we have again reviewed the final amendments and 

determined that, with one limited exception, they can be 

implemented, as finalized, for the 2010 reporting year. 

The one new requirement, regarding reporting of 

biogenic CO2 emissions from units subject to 40 CFR Part 75, 

is being is phased in, so that it remains optional for 

reporting year 2010, but becomes mandatory for each 

subsequent year. Therefore this revision, as finalized, 

already accommodates implementation for the 2010 reporting 

year. 

In summary, except for the exception discussed above 

regarding biogenic CO2 emissions, these amendments do not 

require any additional monitoring or data collection above 

 

3 75 FR 48747 (August 11, 2010). 
Page 17 of 442 

what was already included in Part 98. Therefore, we have 

determined that reporters can use the same information that 

they have been collecting under Part 98 for each subpart to 

calculate and report GHG emissions for 2010 and submit 

reports in 2011 under the amended subparts. 

Following is a brief summary of major comments and 

responses. Several comments were received on this topic. 

Responses to additional significant comments received can 

be found in the document, “Response to Comments: Revision 

to Certain Provisions of the Mandatory Reporting of 

Greenhouse Gases Rule” (see EPA-HQ-OAR-2008-0508). 

Comment: Several commenters requested that we make 

use of the amendments optional for the 2010 reporting year 

and mandatory beginning with the 2011 reporting year. The 

commenters expressed concern that in 2010, sources may not 

have been collecting the required data to implement certain 

amendments. 

Response: We sought comment on the feasibility of 

incorporating the proposed revisions for the 2010 reporting 

year. In the proposal, we explained that we felt 

implementation for the 2010 reporting year would be 

feasible because the proposed revisions, to a great extent, 

would simply clarify existing regulatory requirements or 

add flexibility to the rule. Further, the proposed 
Page 18 of 442 

amendments would not substantially affect the type of 

information that must be collected or how emissions are 

calculated. We sought comment on this conclusion and 

whether this timeline is feasible or appropriate, 

considering the nature of the proposed changes and the way 

in which data have been collected thus far in 2010. We 

requested that commenters provide specific reasons why they 

believe that the proposed implementation schedule would or 

would not be feasible. We received some comments about 

making optional the use of the amendments in 2010, as well 

as comments proposing to extend submission of the first 

reports until June 1, 2011. We received a few industryspecific examples providing a rationale for extending the 

deadline for reporting, or making use of the amendments 

optional for the 2010 reporting year. For example, some 

commenters expressed concern that the proposed 

clarification of the definition of natural gas, as well as 

the introduction of fuel gas into Table C-1, could affect 

applicability under the rule and the use of the tiers under 

subpart C. We have addressed the underlying concerns 

expressed by these commenters, as EPA did not intend to 

change applicability or force facilities to use higher 

tiered calculation methodologies. Therefore, because we 

addressed the underlying concerns, we are finalizing 
Page 19 of 442 

requirements to incorporate the amendments into 2010 

reporting year data. 

II. Final Amendments and Responses to Public Comments 

We are amending various subparts in Part 98 to correct 

errors in the regulatory language that were identified as a 

result of working with reporters to implement the various 

subparts of Part 98. We are also amending certain rule 

provisions to provide greater clarity. The amendments to 

Part 98 include the following types of changes: 

• Additional information to understand better or more 

fully 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. 

• Amendments, in limited cases, to allow for the use of 

simplified emissions calculation methods. 

• Changes to correct cross references within and between 

subparts. 

• Other amendments related to certain issues identified 

as a result of working with reporters during rule 

implementation and outreach. 

• Applying a threshold for reporting for local 

distribution companies of equal to or greater than 

460,000 thousand standard cubic feet (mscf) of natural 

gas delivered per year. 

• Requiring separate reporting of biogenic CO2 emissions 

for units that are also subject to 40 CFR part 75, 

beginning with the 2011 reporting year. 
Page 20 of 442 

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 response document 

available in Docket ID No. EPA–HQ–OAR-2008-0508. 

A. Subpart A - General Provisions: Best Available 

Monitoring Methods 

1. Summary of Final Amendments and Major Changes Since 

Proposal.

EPA is finalizing the petition process established in 

40 CFR 98.3(j) that allows use of Best Available Monitoring 

Methods (BAMM) past December 31, 2010 for owners and 

operators required to report under subpart P (Hydrogen 

Production), subpart X (Petrochemical Production), or 

subpart Y (Petroleum Refineries), under limited 

circumstances. Owners or operators subject to these 

subparts can petition EPA to extend use of BAMM past 

December 31, 2010, if compliance with a specific provision 

in the regulation requires measurement device installation, 

and installation would necessitate an unscheduled process 

equipment or unit shutdown, or could be installed only 
Page 21 of 442 

through a “hot tap.” If the application is approved, the 

owner or operator can postpone installation of the 

measurement device until the next scheduled maintenance 

outage, but initially no later than December 31, 2013. If, 

in 2013, owners or operators still determine and certify 

that a scheduled shutdown will not occur by December 31, 

2013, they may re-apply to use best available monitoring 

methods for an additional two years. 

Process for requesting an extension of best available 

monitoring methods. We are adding a similar petition 

process to that recently concluded for the use of BAMM for 

2010 in 40 CFR 98.3(j). The process is for quantifying 

emissions from any source category at facilities subject to 

subparts P, X and/or Y, and solely for the installation of 

measurement devices that cannot be installed safely except 

during full process equipment or unit shutdown or through 

installation via a hot tap. BAMM is allowable initially no 

later than December 31, 2013. Subpart P, X, and/or Y 

owners or operators requesting to use BAMM beyond 2010 are 

required to electronically notify EPA by January 1, 2011 

that they intend to apply for BAMM for installation of 

measurement devices and certify that such installation will 

require a hot tap or unscheduled shutdown. 
Page 22 of 442 

Owners or operators must submit the full extension 

request for BAMM by February 15, 2011. The full extension 

request must include a description of the measurement 

devices that could not be installed in 2010 without a 

process equipment or unit shutdown, or through a hot tap, a 

clear explanation of why that activity could not be 

accomplished in 2010 with supporting material, an estimated 

date for the next planned maintenance outage, and a 

discussion of how emissions will be calculated in the 

interim. More specifically, the full extension request 

must identify the specific monitoring instrumentation for 

which the request is being made, indicate the locations 

where each piece of monitoring instrumentation will be 

installed, and note the specific rule requirements (by rule 

subpart, section, and paragraph numbers) for which the 

instrumentation is needed. The extension requests must 

also include supporting documentation demonstrating that it 

is not practicable to isolate the equipment and install the 

monitoring instrument without a full process equipment or 

unit shutdown, or through a hot tap, as well as providing 

the dates of the three most recent process equipment or 

unit shutdowns, the typical frequency of shutdowns for the 

respective equipment or unit, and the date of the next 

planned shutdown. 
Page 23 of 442 

Once subpart P, X, and/or Y owners or operators have 

notified EPA of their plan to apply for BAMM for 

measurement device installation, by January 1, 2011, and 

subsequently submitted a full extension request, by 

February 15, 2011, they can automatically use BAMM 

consistent with their request through June 30, 2011. This 

automatic extension is necessary because the current BAMM 

requests submitted by these facilities will end no later 

than December 31, 2010. The BAMM must be extended 

automatically to provide EPA the time to review thoroughly 

the BAMM requests submitted for post-2010, while ensuring 

that the petitioning facilities are not out of compliance 

with the rule during that review process. All measurement 

devices must be installed by July 1, 2011 unless EPA 

approves the BAMM extension request before that date. 

Approval of extension requests. In any approval of an 

extension request, EPA will approve the extension itself, 

establish a date by which all measurement devices must be 

installed, and indicate the approved alternate method for 

calculating GHG emissions in the interim. 

If EPA approves an extension request, the 

owner/operator has until the date approved by EPA to 

install the relevant remaining meters or other measurement 

devices, however initial approvals will not grant 
Page 24 of 442 

extensions beyond December 31, 2013. An owner/operator 

that already received approval from EPA to use BAMM during 

part or all of 2010 is required to submit a new request for 

use of BAMM beyond 2010. Unless EPA has approved an 

extension request, all owners or operators that submit a 

timely request under this new process for BAMM will be 

required to install all measurement devices by July 1, 

2011. 

We recognize that occasionally a facility may plan a 

scheduled process equipment or unit shutdown and the 

installation of required monitoring equipment, but the date 

of the scheduled shutdown is changed. We are adding a 

process by which owners or operators who receive an 

extension will have the opportunity to extend the use of 

BAMM beyond the date approved by EPA if they can 

demonstrate to the Administrator’s satisfaction that they 

are making a good faith effort to install the required 

equipment. At a minimum, facilities that determine that 

the date of a scheduled shutdown will be postponed are 

required to notify EPA within 4 weeks of such a 

determination, but no later than 4 weeks before the date 

for which the planned shutdown was scheduled. 

One-time request to extend best available monitoring 

methods past December 31, 2013. If subpart P, X, and/or Y 
Page 25 of 442 

owners or operators determine that a scheduled shutdown 

will not occur by December 31, 2013 and thus they want to 

continue to use BAMM, they are required to re-apply to use 

BAMM for one additional time period, not to extend beyond 

December 31, 2015. To obtain an extension for the use of 

BAMM past December 13, 2013, owners or operators are 

required to submit a new extension request by June 1, 2013 

that contains the information required in 40 CFR 

98.3(j)(4). All owners or operators that submit a request 

under this paragraph to extend the use of best available 

monitoring methods for measurement device installation are 

required to install all measurement devices by December 31, 

2013, unless the additional extension request under this 

paragraph is approved by EPA. 

2. Summary of Comments and Responses

This section contains a brief summary of major 

comments and responses. Several comments were received on 

this topic. Responses to additional significant comments 

received can be found in the document, “Response to 

Comments: Revision to Certain Provisions of the Mandatory 

Reporting of Greenhouse Gases Rule” (see EPA-HQ-OAR-2008-

0508). 

Comment: EPA received several comments, both in 

support of and in opposition to, the proposed extension of 
Page 26 of 442 

BAMM for facilities subject to subparts P, X and Y. Some 

commenters that supported the new BAMM process also 

recommended that EPA extend the process beyond hydrogen 

producers, petrochemical facilities and petroleum 

refineries. They suggested that the same logic should 

apply to all facilities, that installation of monitoring 

equipment should not require process equipment or unit 

shutdown. 

Other commenters were concerned that the new BAMM 

process conflicts with the need for consistent data. The 

commenters urged that if EPA nevertheless decides to 

finalize the requirements, there should be only a one-time 

application process with BAMM ending no later than December 

2013. Further, they asserted that EPA should require 

facilities to make use of unplanned shutdowns as an 

opportunity to install equipment. 

Response: EPA carefully considered the issues raised 

by commenters and decided to retain the BAMM extension 

process, as proposed, only for facilities subject to 

subparts P, X and Y. The proposal preamble sought comment 

on this very issue and requested that commenters provide 

information on additional subparts, if any, that would need 

this flexibility, and include information on why 

installation could not be done in the absence of such a 
Page 27 of 442 

shutdown or why such shutdowns did not or could not occur 

in 2010 without unreasonable burden on the facility. 

Commenters did not provide the requested information to 

support their position that the provision should be 

extended to other industries. In summary, the commenters 

argued only that EPA should provide this flexibility, but 

did not provide a rationale as to why additional industries 

needed the flexibility. 

Regarding concerns that the new BAMM process would 

lead to inconsistent data, EPA has determined that this 

limited opportunity for a BAMM extension will provide 

sufficiently consistent data for these industries without 

causing the unnecessary burden or potential safety concerns 

that would be associated with installation of monitoring 

devices during unplanned shutdowns or hot taps. EPA notes 

that the BAMM process will still require facilities to 

follow the calculation methods in the rule, but will allow 

owners or operators to use alternative methods to provide 

the inputs to those calculations. Further, unlike the BAMM 

process that was established by promulgation of the October 

30, 2009 reporting rule (74 FR 56379-56380), any request 

for BAMM after 2010 will require EPA approval of a 

facility’s proposed approach to be implemented in lieu of 

the requirements in the rule. This further ensures that 
Page 28 of 442 

EPA will continue to receive data of the appropriate 

quality. 

EPA decided not to limit BAMM to a one-time extension 

through 2013, because we determined that the reasons 

supporting extension through 2013 were still valid post 

2013. Specifically, facilities in these particularly 

complex industries should not have to shut down 

unnecessarily in order to install equipment. Data provided 

by these industries show that some units, for example crude 

distillation units, are shut down only every 4 to 7 years. 

Other units such as vacuum distillation units, fluid 

catalytic cracking units, distillate hydrotreating units, 

catalytic feed hydrotreaters, hydrocrackers, coking units, 

sulfur recovery units and cogeneration units can be shut 

down as infrequently as every 5 years (see final Background 

Technical Support document to the Revision of Certain 

Provisions of the Mandatory Reporting of Greenhouse Gases 

Rule). Thus, providing a potential end date for BAMM of 

December 31, 2015, is appropriate based on information 

presented for these industries on the typical frequency of 

shutdown for these facilities. 

We also are not requiring a facility to order the 

measurement equipment early and have it on hand in the 

event of an unplanned shutdown before the scheduled 
Page 29 of 442 

shutdown. First, it would be hard to enforce a requirement 

to install equipment during an unplanned shutdown “if 

feasible” because it would be hard to objectively determine 

whether a facility should have installed equipment during 

an unplanned shutdown. Moreover, during an unplanned 

shutdown, the priority is often to get the equipment up and 

running as quickly and safely as possible; therefore, there 

is not necessarily time to install the measurement 

equipment. 

Comment: In a related comment, one commenter raised 

concerns about Tier 3 monitoring requirements for a stream 

at its facility that is dangerous to monitor due to the 

presence of hydrogen cyanide. They indicated that they 

used BAMM to implement an approach other than direct 

sampling of the inputs to the equations for the 2010 

reporting year, and now are considering implementing the 

Tier 4 method for future years. However, they argued the 

rule should provide a mechanism to address these dangerous 

streams. 

Response: No rule change has been made as a result of 

the comment. For the 2010 reporting year, the BAMM 

provisions were designed for use where it was not possible 

to acquire, install and operate a required piece of 

equipment during the early months of the GHG Reporting 
Page 30 of 442 

Program. Safety concerns were a valid reason for approving 

these early BAMM applications. 

Although, the commenter notes concerns with conducting 

the Tier 3 method for quantifying emissions from stationary 

combustion at the facility due to the presence of a 

hydrogen cyanide stream, EPA notes that the rule does not 

limit them to use of a Tier 3 approach. As acknowledged by 

the commenter, they also have the opportunity to use Tier 4 

to meet the requirements of the rule and, by taking 

advantage of BAMM for 2010, had one year to install the 

Tier 4 equipment. The commenter merely wants additional 

time beyond that already provided in the rule to comply 

with the Tier 4 requirements. The commenter does not 

justify the requested extension by pointing to issues like 

unplanned shutdowns or hot taps, as discussed in the 

proposal. EPA has determined the unique situation raised 

by the commenter does not warrant expanding the BAMM 

process generally beyond industries subject to subparts P, 

X and Y. 

B. Subpart A - General Provisions: Calibration 

Requirements

1. Summary of Final Amendments and Major Changes Since 

Proposal.
Page 31 of 442 

EPA has finalized amendments to 40 CFR 98.3(i)(1) to 

specify that the calibration accuracy requirements of 40 

CFR 98.3(i)(2) and (i)(3) are required only for flow meters 

that measure liquid and gaseous fuel feed rates, feedstock 

flow rates, or process stream flow rates that are used in 

the GHG emissions calculations, and only when the 

calibration accuracy requirement is specified in an 

applicable subpart of Part 98. For instance, the QA/QC 

requirements in 40 CFR 98.34(b)(1) of subpart C require all 

flow meters that measure liquid and gaseous fuel flow rates 

for the Tier 3 CO2 calculation methodology to be calibrated 

according to 40 CFR 98.3(i); therefore, the accuracy 

standards in 40 CFR 98.3(i)(2) and (i)(3) will continue to 

apply to these meters. 

We are also amending 40 CFR 98.3(i) to clarify that 

the calibration accuracy specifications of 40 CFR 

98.3(i)(2) and (i)(3) do not apply where the use of company 

records or the use of best available information is 

specified to quantify fuel usage or other parameters, nor 

do they apply to sources that use Part 75 methodologies to 

calculate CO2 mass emissions because the Part 75 qualityassurance is sufficient. Although calibration accuracy 

requirements are not applicable for these data sources, per 

the requirements of 98.3(g)(5), reporters are still 
Page 32 of 442 

required to explain in their monitoring plan the processes 

and methods used to collect the necessary data for the GHG 

calculations. 

We are also amending 40 CFR 98.3(i)(1) to clarify that 

the calibration accuracy specifications in 40 CFR 

98.3(i)(2) and (i)(3) do not apply to other measurement 

devices (e.g., weighing devices) that provide data for the 

GHG emissions calculations. Rather, these devices must be 

calibrated to meet the accuracy requirements of the 

relevant subpart(s), or, in the absence of such 

requirements, meet appropriate, technology-based errorlimits, such as industry consensus standards or 

manufacturer’s accuracy specifications. Consistent with 40 

CFR 98.3(g)(5)(i)(C), the procedures and methods used to 

quality-assure the data from the measurement devices must 

be documented in the written monitoring plan. 

We are adding a new paragraph 40 CFR 98.3(i)(1)(ii) to 

clarify that flow meters and other measurement devices need 

to be installed and calibrated by the date on which data 

collection needs to begin, if a facility or supplier 

becomes subject to Part 98 after April 1, 2010. 

We are adding new paragraph 40 CFR 98.3(i)(1)(iii) to 

specify the frequency at which subsequent recalibrations of 

flow meters and other measurement devices must be 
Page 33 of 442 

performed. Recalibration must be at the frequency 

specified in each applicable subpart, or at the frequency 

recommended by the manufacturer or by an industry consensus 

standard practice, if no recalibration frequency was 

specified in an applicable subpart. 

We are adding new paragraph 40 CFR 98.3(i)(7) to 

specify the consequences of a failed flow meter 

calibration. Data become invalid prospectively, beginning 

at the hour of the failed calibration and continuing until 

a successful calibration is completed. Appropriate 

substitute data values must be used during the period of 

data invalidation. 

In 40 CFR 98.3(i)(2) and (3), we are adding absolute 

value signs to the numerators of Equations A-2 and A-3. 

These were inadvertently omitted in the October 30, 2009 

Part 98. 

We are also amending 40 CFR 98.3(i)(3) to increase the 

alternative accuracy specification for orifice, nozzle, and 

venturi flow meters (i.e., the arithmetic sum of the three 

transmitter calibration errors (CE) at each calibration 

level) from 5.0 percent to 6.0 percent, since each 

transmitter is individually allowed an accuracy of 2.0 

percent. We are also amending 40 CFR 98.3(i)(3) for 

orifice, nozzle, and venturi flow meters to account for 
Page 34 of 442 

cases where not all three transmitters for total pressure, 

differential pressure, and temperature are located in the 

vicinity of a flow meter’s primary element. Instead of 

being required to install additional transmitters, 

reporters are, as described below, conditionally allowed to 

use assumed values for temperature and/or total pressure 

based on measurements of these parameters at remote 

locations. If only two of the three transmitters are 

installed and an assumed value is used for temperature or 

total pressure, the maximum allowable calibration error is 

4.0 percent. If two assumed values are used and only the 

differential pressure transmitter is calibrated, the 

maximum allowable calibration error is 2.0 percent. 

We are also amending 40 CFR 98.3(i)(3) to add five 

conditions that must be met in order for a source to use 

assumed values for temperature and/or total pressure at the 

flow meter location, based on measurements of these 

parameters at a remote location (or locations). 

• The owner or operator must demonstrate that the remote 

readings, when corrected, are truly representative of 

the actual temperature and/or total pressure at the 

flow meter location, under all expected ambient 

conditions. Pressure and temperature surveys can be 

performed to determine the difference between the 

readings obtained with the remote transmitters and the 

actual conditions at the flow meter location. 

• All temperature and/or total pressure measurements in 

the demonstration must be made with calibrated gauges, 
Page 35 of 442 

sensors, transmitters, or other appropriate 

measurement devices. 

• The methods used for the demonstration, along with the 

data from the demonstration, supporting engineering 

calculations (if any), and the mathematical 

relationship(s) between the remote readings and the 

actual flow meter conditions derived from the 

demonstration data must be documented in the 

monitoring plan for the unit and maintained in a 

format suitable for auditing and inspection. 

• The temperature and/or total pressure at the flow 

meter must be calculated on a daily basis from the 

remotely measured values, and the measured flow rates 

must then be corrected to standard conditions. 

• The mathematical correlation(s) between the remote 

readings and actual flow meter conditions must be 

checked at least once a year, and any necessary 

adjustments must be made to the correlation(s) going 

forward. 

We are amending 40 CFR 98.3(i)(4) to include an 

additional exemption from the calibration requirements of 

40 CFR 98.3(i) for flow meters that are used exclusively to 

measure the flow rates of fuels used for unit startup. For 

instance, a meter that is used only to measure the flow 

rate of startup fuel (e.g., natural gas) to a coal-fired 

unit is exempted. 

Section 98.3(i)(4) is being further amended to clarify 

that gas billing meters are exempted from the monitoring 

plan and recordkeeping provisions of 40 CFR 

98.3(g)(5)(i)(c), (g)(6) and (g)(7), which require, 

respectively, that a description of the methods used to 

quality-assure data from instruments used to provide data 
Page 36 of 442 

for the GHG emissions calculations be included in the 

written monitoring plan, that the results of all required 

certification and QA tests be kept, and that maintenance 

records be kept for those instruments. 

We are amending 40 CFR 98.3(i)(5) to clarify that flow 

meters that were already calibrated according to 40 CFR 

98.3(i)(1) following a manufacturer’s recommended 

calibration schedule or an industry consensus calibration 

schedule do not need to be recalibrated by the date 

specified in 40 CFR 98.3(i)(1) as long as the flow meter is 

still within the recommended calibration interval. This 

paragraph is also being amended to clarify that the 

deadline for successive calibrations will be according to 

the manufacturer’s recommended calibration schedule or an 

industry consensus calibration schedule. 

We are amending 40 CFR 98.3(i)(6) to account for units 

and processes that operate continuously with infrequent 

outages and cannot meet the flow meter calibration deadline 

without disrupting normal process operation. Part 98 

allowed the owner or operator to postpone the initial 

calibration until the next scheduled maintenance outage. 

Although the rule allowed postponement of calibration, it 

did not specify how to report fuel consumption for the 

entire time period extending from January 1, 2010 until the 
Page 37 of 442 

next maintenance outage. We are amending 40 CFR 98.3(i)(6) 

to permit sources to use the best available data from 

company records to quantify fuel usage until the next 

scheduled maintenance outage. This revision addresses 

situations where the next scheduled outage is in 2011, or 

later. 

The major change since proposal is identified in the 

following list. The rationale for this and any other 

significant changes can be found in this preamble or the 

document, “Response to Comments: Revision to Certain 

Provisions of the Mandatory Reporting of Greenhouse Gases 

Rule” (see EPA-HQ-OAR-2008-0508). 

• Removed the words “ignition” and “ignition fuel” from 

40 CFR 98.3(i)(4), so that only fuel flow meters that 

are used exclusively for startup are exempted from the 

calibration requirements of 40 CFR 98.3(i). 

2. Summary of Comments and Responses

This section contains a brief summary of major 

comments and responses. Several comments were received on 

this topic. Responses to additional significant comments 

received can be found in the document, “Response to 

Comments: Revision to Certain Provisions of the Mandatory 

Reporting of Greenhouse Gases Rule” (see EPA-HQ-OAR-2008-

0508). 

Comment: We received several comments relating to the 

proposed changes to the calibration accuracy requirements 
Page 38 of 442 

set in 40 CFR 98.3(i). Commenters expressed concern that 

removing the rule-wide 5 percent calibration accuracy 

requirement would compromise the rule’s data quality. The 

commenters noted that a global calibration accuracy 

requirement is necessary to provide data that are accurate 

and comparable within and across industries. By dropping 

this requirement, the commenters believed small calibration 

errors will systematically produce major errors in reported 

data. For measuring devices other than flow meters they 

argued that it is not clear what an "appropriate" error 

range is, or what calibration standards a reporter would 

deem "applicable," and suggest that by stating calibration 

standards are “not limited to industry standards...,” EPA is 

waiving calibration requirements for other measuring 

devices altogether. They acknowledge that there is a 

requirement to document the calibration procedure used in 

the monitoring plan, but they believe it is not enforceable 

and severely reduces transparency. The commenters contend 

that the use of different calibration methods and varying 

levels of accuracy would make it difficult to correctly 

interpret and compare the emissions data, and would render 

future policy development very difficult. 

In summary, commenters that were concerned about our 

removal of the blanket 5 percent calibration accuracy 
Page 39 of 442 

requirements asserted that EPA has a mandate to implement 

the rule and cannot promulgate any subsequent rule that 

would compromise the quality of the data reported. They 

further argue that it is arbitrary and capricious, in light 

of EPA’s reporting mandate, to waive the calibration 

accuracy requirements for any flow meters. All such 

meters, they contend, should be required to meet these 

minimum accuracy requirements, with no exceptions. 

Response: We acknowledge the concerns of the 

commenters and agree that a high level of data quality is a 

valuable component of any environmental program. However, 

we believe the changes to the calibration accuracy 

requirements of 40 CFR 98.3(i) do not jeopardize the 

integrity of the reporting program nor compromise EPA’s 

ability to use the data in the future to support climate 

policy development. 

As originally promulgated, 40 CFR 98.3(i) required 

that “all measurement devices shall be calibrated to an 

accuracy of 5 percent.” However, as promulgated, 40 CFR 

98.3(i)(2) and (i)(3) only provided calibration procedures 

for flow meters. No specific procedures were provided for 

other measurement device. As a result, measurement devices 

other than flow meters would necessarily be calibrated 
Page 40 of 442 

according to procedures specified in other subparts, 

industry consensus methods, or manufacturer specifications. 

In the “Technical Support Document for Revision of 

Certain Provisions: Proposed Rule for Mandatory Reporting 

of Greenhouse Gases,” dated July 8, 2010 (the TSD), vendor 

information on various types of measuring devices shows 

accuracy ranges of significantly less than five percent. 

Requiring the calibrations to be performed according to the 

accuracy specified by the device manufacturer, rather than 

5 percent, would likely actually increase the data accuracy 

of the rule. In addition, we recognize that other programs 

to which reporters may be subject impose calibration 

standards that will affect many of the instruments used for 

reporting under Part 98. For example, the tested accuracy 

of fuel flow meters and transmitter transducers used in the 

Acid Rain Program from 2005 through 2009 was well below one 

percent. 

As a result of the wide range of industries and 

measuring devices used within each industry, we have 

determined it is not practical to set a global calibration 

standard or method that would apply generically to every 

measurement device. Replacing the five percent requirement 

from the 2009 fine rule with manufacturer’s specifications 

or industry specific standards will provide a higher level 
Page 41 of 442 

of data certainty across the rule while accommodating the 

wide variety of industries and equipment covered by the 

rule. We think it is highly unlikely that companies will 

choose to use arbitrary standards as the procedures and 

methods used to quality-assure the measurement data must be 

listed in the facility or supplier’s monitoring plan. 

The commenters correctly note that the calibration 

accuracy requirements of 40 CFR 98.3(i) have been removed 

where company records or best available information are 

used. Since promulgation, we have consistently affirmed 

that meters used to generate company records are not 

required to be calibrated according to 40 CFR 98.3(i). The 

purpose behind allowing the use of company records and best 

available information was to permit companies to use fuel 

billing receipts or other quality assured information they 

currently maintain. EPA authorized the use of company 

records to alleviate burden and did not intend for such 

data to be subject to additional calibration requirements, 

which would defeat the purpose of this flexibility. 

To be clear, we disagree with the commenter’s 

assertions that we are “waiving” any calibration accuracy 

requirements or that certain types of flow meters would not 

have to be calibrated. All measurement technologies, 

except for the limited exceptions in 40 CFR 98.3(i) must 
Page 42 of 442 

meet calibration accuracy requirements. Further, most 

major emission sources should be covered by either the 

requirements of 40 CFR 98.38(i) or another program that 

provides a similarly, if not significantly more, stringent 

accuracy requirement. We have concluded that the 

amendments to the calibration accuracy requirements do not 

compromise our ability to implement successfully this 

reporting rule. 

Comment: One commenter pointed out an inconsistency 

in the proposed rule regarding the term “ignition fuel.” 

EPA proposed to amend 40 CFR 98.3(i)(4) to exempt fuel flow 

meters that are used exclusively for startup and ignition 

fuel from the calibration requirements of 40 CFR 98.3(i). 

However, EPA also proposed in 40 CFR 98.30(d) to exempt 

pilot lights from GHG emission reporting requirements. The 

commenter noted that pilot lights are essentially the same 

as ignitors, and the reference in 40 CFR 98.3(i)(4) to flow 

meters that measure ignition fuel appears to imply that GHG 

emissions from the combustion of ignition fuel must be 

reported. 

Response: The GHG emissions reporting exemption for 

pilot lights in 40 CFR 98.30(d) refers to emissions from 

combustion of the fuel that supplies the pilot light. 

Therefore, in the final rule, we have removed the words 
Page 43 of 442 

“ignition” and “ignition fuel” from 40 CFR 98.3(i)(4). 

Paragraph (i)(4) now refers only to startup fuel, which is 

distinctly different from ignition fuel. For instance, at 

startup, a coal-fired boiler may burn natural gas for 

several hours at high heat input values, whereas a pilot 

light is a small flame that simply ignites or initiates 

combustion of the main fuel (e.g., fuel oil). 

C. Subpart A - General Provisions: Reporting of Biogenic 

Emissions 

1. Summary of Final Amendments and Major Changes Since 

Proposal.

Under the proposed amendments, EPA’s goal was to 

reflect in regulatory language clarifications that have 

been issued stating that separate reporting of biogenic 

emissions for units subject to 40 CFR part 75 was optional. 

To clarify this optional reporting, we proposed to amend 

the data elements in subpart A (specifically 40 CFR 

98.3(c)(4)) and subpart C that currently require separate 

accounting and reporting of biogenic CO2 emissions so that 

it is optional for units that are subject to subpart D of 

this part or units that use the methods in part 75 to 

quantify CO2 mass emissions in accordance with 40 CFR 

98.33(a)(5) (40 CFR part 75 units or “part 75 units”). 

More specifically, to effect this clarification, we 
Page 44 of 442 

proposed to revise the reporting for all facilities such 

that all facilities would report combined non-biogenic and 

biogenic CO2, and all facilities, except those with ”part 75 

units”, would still have been required to calculate and 

report biogenic CO2 emissions separately. 

We received numerous adverse comments on the proposed 

amendments that would re-structure 40 CFR 98.3(c)(4) and 

clarify that separate reporting of biogenic CO2 emissions 

was optional for ”part 75 units”. Most commenters urged 

EPA to make separate reporting of biogenic emissions 

mandatory for all reporters. Many commenters also objected 

to the restructuring of 40 CFR 98.3(c)(4), which would have 

had all units reporting combined biogenic and non-biogenic 

CO2 emissions. 

Based on the comments received, we have decided to 

withdraw the proposed re-structuring of 40 CFR 98.3(c)(4). 

We have also reconsidered the optional reporting of 

biogenic CO2 emissions reporting for ”part 75 units”. In 

the final rule, a new paragraph, (c)(12), has been added to 

40 CFR 98.3(c), which states that reporting biogenic CO2 is 

optional for ”part 75 units” only for the first year of the 

program (i.e., for the 2010 reporting year). Thereafter, 

all ”part 75 units” units must separately report their 

biogenic CO2 emissions. We are allowing the optional 
Page 45 of 442 

biogenic CO2 emissions reporting for the 2010 reporting year 

in light of the 2009 final rule, as well as our previous 

statements and guidance on the issue. It is likely that at 

least some 40 CFR part 75 sources are following that policy 

guidance and have elected not to separately report biogenic 

CO2 emissions. It is equally likely that these sources have 

not been keeping the necessary records or performing the 

required emission testing to enable them to report these 

emissions for 2010. 

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 

document, “Response to Comments: Revision to Certain 

Provisions of the Mandatory Reporting of Greenhouse Gases 

Rule” (see EPA-HQ-OAR-2008-0508). 

• Retaining the facility level reporting requirements 

from the 2009 final rule (74 FR 56373) in 40 CFR 

98.3(c)(4) that requires reporting of CO2 emissions 

(excluding biogenic CO2) and separate reporting of 

biogenic emissions. 

• Introducing new paragraph 40 CFR 98.3(c)(12) that 

allows facilities with 40 CFR part 75 units the option 

to include biogenic emissions in their facility totals 

for the 2010 reporting year only. 

2. Summary of Comments and Responses

This section contains a brief summary of major 

comments and responses. Several comments were received on 

this topic. Responses to additional significant comments 
Page 46 of 442 

received can be found in the document, “Response to 

Comments: Revision to Certain Provisions of the Mandatory 

Reporting of Greenhouse Gases Rule” (see EPA-HQ-OAR-2008-

0508). 

Comment: EPA received a large number of comments 

related to the proposed amendments to make separate 

reporting of biogenic CO2 emissions optional for units 

subject to 40 CFR part 75. The three main concerns, each 

raised by multiple commenters, were that (1) all reporters 

should be required to separately report biogenic CO2

emissions; (2) reporters should never be required to 

combine fossil CO2 and biogenic CO2; and, (3) if EPA 

nevertheless finalizes requirements allowing separate 

reporting of biogenic CO2 to be optional for units subject 

to 40 CFR part 75, then EPA’s implementation of the 

proposed revisions should be narrower in scope and not 

affect reporting requirements for all reporters. 

Regarding the first issue, some commenters argued that 

the requirements of the Acid Rain Program (ARP) should not 

constrain EPA in the GHG context and that all reporters 

under 40 CFR part 98 should be required to report biogenic 

CO2 emissions, regardless of the fact that such separate 

reporting is not a requirement in ARP. Commenters 
Page 47 of 442 

suggested that this is important for consistency across the 

GHG Reporting Program. 

Several commenters suggested that it is never 

appropriate to combine fossil CO2 and biogenic CO2 into a 

single reported value. Commenters noted that there is a 

distinction between fossil CO2 and biogenic CO2 and that in 

order to ensure transparency for future climate policy 

these two values should not be combined into a single 

reported emissions value. Further, they argued that EPA’s 

proposed requirement for sources to combine fossil and 

biogenic emissions together in one total ignores the 

natural biomass carbon cycle and is counter to the 

principle of “carbon neutrality”, thereby overstating net 

CO2 entering the atmosphere. 

The commenters suggested that requiring separate 

reporting of biogenic CO2 is consistent with the 

Intergovernmental Panel on Climate Change and national, 

regional, and corporate GHG protocols and that EPA should 

not depart from this established accounting convention. 

These commenters also pointed out that EPA uses this same 

rationale for requiring separate reporting of biogenic CO2

emissions in its own response to comments to the GHG 

Reporting Rule (74 FR 56351). Further, the commenters 

articulated that separate reporting of biogenic emissions 
Page 48 of 442 

is necessary to provide the public and policymakers with 

information on the extent of biomass combustion and the 

sectors of the economy where biomass fuels are used, which 

is information important for developing future climate 

policy. Several organizations also commented that an 

accurate, economy-wide inventory of biogenic CO2 emissions 

is important because the evidence to date demonstrates that 

biomass is not inherently carbon neutral. 

Finally, commenters noted that if EPA nevertheless 

decides to finalize the rule allowing optional reporting of 

biogenic CO2 emissions for 40 CFR part 75 units, EPA should 

modify the proposed rule so the amendments affect only 

facilities with part 75 units, and do not change the 

reporting requirements for all other reporters. Commenters 

were concerned that EPA’s proposed change required all 

reporters to report total CO2 (including biogenic CO2

emissions), but only required facilities with non-part 75 

units to report their biogenic emissions separately. 

Facilities with part 75 units would have the option to 

report separately biogenic CO2 from those units. The 

commenters suggested that if EPA chooses to finalize 

optional separate reporting for part 75 units, then EPA 

should revert to the reporting requirements in subpart A 

that were in the 2009 final rule (i.e., report CO2 excluding 
Page 49 of 442 

biogenic CO2) (74 FR 56379) for all other reporters and add 

a new paragraph specifically for facilities with part 75 

units. 

Response: We appreciate the significant feedback 

generated by the proposed amendments designed to clarify 

that separate reporting of biogenic emissions was optional 

for units subject to 40 CFR part 75. We also recognize 

that many industry and environmental groups have 

significant interest in the treatment of biomass in GHG 

reports, and specifically in the accounting of biogenic CO2

emissions. Based on the significant feedback received, 

including comments received from facilities with 40 CFR 

part 75 units, as well as the fact that one of the 

fundamental goals of the Greenhouse Gas Reporting Program 

(GHGRP) is to collect data to support a range of potential 

future climate policies, we have reconsidered our position 

and decided to make the separate reporting of biogenic 

emissions mandatory for part 75 units beginning in the 2011 

reporting year. Separate reporting of biogenic CO2 

emissions is optional for these units in the 2010 reporting 

year. 

Per the requirements in the new paragraph 40 CFR 

98.3(c)(12), facilities with one or more part 75 units must 

elect in the 2010 reporting year whether to report biogenic 
Page 50 of 442 

CO2 emissions from 40 CFR part 75 units separately, or 

report only total CO2 emissions (including biogenic CO2) for 

the 40 CFR part 75 units at their facility. Beginning in 

the 2011 reporting year, these facilities must separately 

report biogenic CO2 emissions for the entire facility per 

the requirements in 40 CFR 98.3(c)(4), like all other 

facilities. 

In addition, the final rule does not adopt the 

proposed restructuring of 40 CFR 98.3(c)(4) and leaves in 

place the facility-level reporting requirements in 40 CFR 

98.3(c)(4) for any facility in 2010 or for future years. 

All other facilities, except those with part 75 units, 

must, as finalized in the 2009 final rule, report CO2

(excluding biogenic CO2) and then report separately biogenic 

CO2 emissions. We would note that neither the original 

proposed amendments, nor the amendments finalized today, 

affect the fact that biogenic CO2 emissions are excluded 

from the applicability determination under 40 CFR 98.2. 

Commenters provided many reasons for supporting 

mandatory separate reporting of biogenic CO2 emissions from 

all facilities, including the increased transparency that 

such reporting brings. Some commenters supported the 

assumption of the carbon neutrality of biomass while others 

dispelled it, but both sides were united in their comments 
Page 51 of 442 

that it is important to understand the GHG emissions 

associated with biomass consumption. Our decision to also 

require separate reporting of biogenic emissions for units 

that use the methods in 40 CFR part 75 is founded solely on 

the principle that having data available at a more 

disaggregated level for a reporting program like this one 

improves transparency and better enables us and other 

stakeholders to use the data to evaluate future potential 

policy options, without prejudging what those policies 

might be. This decision is not based on any conclusions 

about “carbon neutrality” or the appropriateness of 

combining fossil CO2 and biogenic CO2 into a single value4. 

Rather, EPA's approach preserves the flexibility for the 

Agency and for stakeholders to understand reported CO2

emissions in multiple ways. Despite the benefits of having 

separate data with which to distinguish biogenic CO2 

emissions, which we do not dispute, the 2009 final rule did 

not require this reporting for units subject to 40 CFR part 

75. This is consistent with the Response to Comments 

document for subpart D of the final rule5 where it states 

 

4 EPA requested comment on approaches to accounting for GHG emissions 

from bioenergy and other biogenic sources earlier this year. The Call 

for Information (75 FR 41173 and 75 FR 45112), supporting information 

and comments can be found in docket EPA-HQ-OAR-2010-0560. Please refer 

to those documents for more information about this issue. 

5 Mandatory Greenhouse Gas Reporting Rule, EPA’s Response to Public 

Comments, Volume 16, Subpart D Electricity Generation. Found at 
Page 52 of 442 

“It is EPA's intent that Acid Rain Program units will be 

able to continue to measure and report CO2 emissions as they 

do under the Acid Rain Program” which did not require 

separate reporting of biogenic CO2. However, when we opened 

the relevant paragraphs to notice and comment, we received 

overwhelming support for making the separate reporting of 

biogenic CO2 emissions mandatory, including from facilities 

with part 75 units. This support, in combination with the 

value of having the data for policy analysis, led us to 

reconsider our position and require separate reporting of 

biogenic CO2 emissions beginning in the 2011 reporting year 

for the 40 CFR part 75 units. We decided to retain 

optional reporting for the 2010 reporting year due to the 

fact that we have provided guidance indicating that 

separate reporting was optional for these part 75 units, 

and therefore, some facilities may not have incorporated 

procedures into their monitoring plans or developed 

internal systems for collecting the necessary information 

to facilitate the biogenic CO2 emissions calculations. 

To implement the changes described above, we are 

adding new paragraph 40 CFR 98.3(c)(12), as well as 

amending paragraphs 40 CFR 98.33(e) (to provide an 

 

http://www.epa.gov/climatechange/emissions/downloads09/documents/Subpar

tD-CommentReponses.pdf. 
Page 53 of 442 

additional option for part 75 units to calculate the 

biogenic CO2 emissions), 40 CFR 98.34(f), several paragraphs 

in 40 CFR 98.36(d), and 40 CFR 98.43. 

D. Subpart A - General Provisions: Requirements for 

Correction and Resubmission of Annual Reports 

1. Summary of Final Amendments and Major Changes Since 

Proposal.

Subpart A, as promulgated in October 2009, required 

that an “owner or operator shall submit a revised report 

within 45 days of discovering or being notified by EPA of 

errors in an annual GHG report. The revised report must 

correct all identified errors...” We are amending 40 CFR 

98.3(h) to clarify the types of errors that trigger a 

resubmission and the process for resubmitting annual GHG 

reports. 

First, reports only have to be resubmitted when the 

owner or operator or the Administrator determines that a 

substantive error exists. A substantive error is defined 

as one that impacts the quantity of GHG emissions reported 

or otherwise prevents the reported data from being 

validated or verified. This clarification is important 

because some errors are not significant (e.g., an error in 

the zip code) and do not impact emissions. Such non-
Page 54 of 442 

significant errors will not obligate the owner or operator 

to resubmit the annual report. 

The owner or operator is required to resubmit the 

report within 45 days of identifying the substantive error, 

or of being notified by the Administrator of a substantive 

error, unless the owner or operator provides information 

demonstrating that the previously submitted report does not 

contain the identified substantive error or that the 

identified error is not a substantive error. This 

amendment provides owners and operators the opportunity to 

demonstrate whether an error the Administrator has deemed 

to be a substantive error is not, in fact, a substantive 

error. 

Finally, we are also allowing owners and operators to 

request an extension of the 45-day resubmission deadline to 

address facility-specific circumstances that arise in 

either correcting an error or determining whether or not an 

identified error is, in fact, a substantive error. Owners 

and operators are required to notify EPA by e-mail at least 

two business days prior to the end of the 45-day 

resubmission deadline if they seek an extension. An 

automatic 30-day extension will be granted if EPA does not 

respond to the extension request by the end of the 45-day 

period. 
Page 55 of 442 

We are including the opportunity to extend the period 

for resubmission in recognition that the data system is 

still under development and we do not yet fully know the 

full range of errors that will be identified and, 

therefore, the time required to address such errors. 

Verification and quality assurance and quality control 

checks are currently under development in the data system. 

Some flags that the data system might generate will not 

necessarily reflect substantive errors, but rather will be 

flags to alert the owner or operator to review the 

submission carefully to make sure the information provided 

is correct. On the other hand, some flags could identify 

substantive errors that affect the overall GHG emissions 

reported to EPA. Although we have concluded that it is 

important to provide facilities and suppliers the 

opportunity to extend this deadline, we believe that the 

45-day time period is a sufficient time period for the vast 

majority of facilities and suppliers. 

There have been no major changes from proposal 

regarding requirements for correction and resubmission of 

annual reports. 

2. Summary of Comments and Responses

This section contains a brief summary of major 

comments and responses. Several comments were received on 
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this subpart. Responses to additional comments received 

can be found in the document, “Response to Comments: 

Revision to Certain Provisions of the Mandatory Reporting 

of Greenhouse Gases Rule” (see EPA-HQ-OAR-2008-0508). 

Comment: One commenter, representing several 

organizations, was concerned that the amended process for 

submitting revised annual GHG reports upon identification 

or notification by EPA of an error was too complex and 

would substantially slow down correction of reported 

errors. Generally, they asserted that the 45-day process 

that was in the final Part 98 (74 FR 56381) should be 

appropriate for most reporters, and to the extent there 

were any outliers, then EPA could use enforcement 

discretion for those specific reporters as opposed to 

changing the rule for all reporters. The commenter was 

further concerned that EPA proposed to allow reporters to 

extend their resubmission deadline in the event of a 

disagreement between EPA and the reporter, by at least 30 

days. The commenters suggested that the process does not 

give EPA a clear method to dispute these points with 

operators, does not specify that EPA’s view trumps the 

operator’s opinion, and does not allow members of the 

public to argue that an error is, in fact, substantive, and 

must be corrected. They contended that the overall process 
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could take months or years to correct errors, and the 

operators may still refuse to correct some of them. They 

argued this is a departure from the existing rule, and 

serves only to hinder what was a straight-forward and 

effective process.

Response: The process in these final rule amendments 

for submission of revised annual GHG reports to correct any 

substantive errors in these reports is reasonable and 

consistent with the purpose of the GHG Reporting Program. 

The purpose of these reporting requirements is to provide 

EPA with accurate and timely information on greenhouse 

gases in order to gain a better understanding of the 

relative emissions of specific industries and facilities, 

the factors that influence emission rates, and the actions 

that facilities could in the future, or already take, to 

reduce emissions. In light of this purpose, it is 

reasonable to focus an ongoing requirement to correct 

errors in an annual report on “substantive errors,” i.e., 

errors that affect emissions data quality, validation, or 

verification. Further, because this is a new program 

covering a wide variety of industries and processes, some 

of whom may not be familiar with GHG accounting and 

reporting, we have determined that under these 

circumstances it is reasonable to establish a procedure 
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engaging owners and operators on whether the annual report 

actually contains identified “substantive errors.” 

The commenters’ claims that this procedure provides no 

“clear method” of determining what are substantive errors, 

may take “months, perhaps years,” may result in owners 

refusing to correct errors, and is unnecessary are 

unsupported and speculative. First, EPA has concluded that 

the definition of “substantive error”--an error that 

impacts emissions data quality or otherwise prevents the 

data from being validated or verified--is reasonably clear 

and is consistent with the purposes of GHG emissions 

reporting. The commenter fails to show what is unclear 

about this definition, nor why it is unreasonable to focus 

corrections on substantive errors, versus insignificant 

ones that do not impact the accuracy of submitted 

information. 

Second, these final rule amendments set time limits 

for correction of substantive errors, i.e., correction 

through submission of a revised annual GHG report within 45 

days of discovery (or notification by EPA of the errors) 

plus any “reasonable extensions” of time (including one 

automatic 30 day extension). The commenter fails to 

provide any basis for conflating these limited time frames 

into periods of many months or years. Further, because 
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refusal by an owner or operator to correct substantive 

errors within the appropriate time frame would be a 

violation of the CAA and subject to significant civil 

penalties, the commenter has no basis for assuming that 

owners and operators would simply refuse to make the 

corrections. 

Third, the error correction process provides a 

standard process that is applicable to all owners and 

operators and that owners and operators and EPA can use to 

attempt to resolve issues concerning error correction. EPA 

has determined that this process will likely result in more 

efficient error correction and resolution of error 

correction issues by setting a limited time for contesting 

EPA’s identification of substantive errors. In addition, 

EPA’s provision of a standard process provides more 

certainty for owners and operators of an opportunity to 

resolve issues than if EPA were simply to rely on 

enforcement discretion, as recommended by a commenter. 

The commenters also claimed the public will have no 

opportunity to argue that errors are substantive and should 

be corrected. However, this does not represent a change 

from the error correction process under the 2009 final 

rule. The amendments for resubmission of annual reports 
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did not change public involvement in the resubmission 

process. 

The process in today’s rule better focuses the 

resources of EPA, regulated industries and the public on 

those errors that are most relevant to generating accurate 

data. 

Comment: Several commenters requested that EPA 

provide a numerical determination of what is a “substantive 

error.” One commenter proposed a +/- 10 percent change in 

the reported GHG emissions value as a result of the 

identified error. Another commenter requested that EPA 

clarify that substantive errors are only those that exceed 

1 percent to 5 percent of the total annual CO2 equivalent 

emissions. 

One commenter requested that, in the final preamble, 

EPA clarify that any error not be considered substantive 

unless it exceeds 1 percent to 5 percent of the total 

annual CO2 equivalent (“CO2e”) emission amount reported by 

an individual reporting facility. The commenter also 

requested that EPA modify the “contains one or more 

substantive errors” language to allow the agency 

flexibility to investigate potential as well as documented 

errors.
Page 61 of 442 

Response: The final rule defines substantive error as 

an error that impacts the quantity of GHG emissions 

reported or otherwise prevents the reported data from being 

validated or verified. EPA has determined that it is not 

appropriate to establish a threshold below which errors do 

not have to be corrected and resubmitted. EPA has 

determined that if an error in the GHG emissions estimate 

occurs, then that emissions error should be corrected and 

the annual GHG emissions report resubmitted. If a facility 

were to go through the process of identifying the estimate 

in GHG emissions, calculating what the GHG emissions total 

should have been, and then determining the percent 

difference between the original reported estimate and the 

revised estimate, then the reporter has all of the 

information necessary to report that revised estimate.

E. Subpart A - General Provisions: Information to Record 

for Missing Data Events

1. Summary of Final Amendments and Major Changes Since 

Proposal.

We are amending 40 CFR 98.3(g)(4) by removing 

requirements to maintain records on the duration of a 

missing data event and actions taken to minimize future 

occurrences, while retaining the requirement that records 

be kept of the cause of each missing data event and the 
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corrective actions taken. We are also clarifying that the 

records retained pursuant to 40 CFR 75.57(h) may be used to 

meet the recordkeeping requirements under Part 98 for the 

same missing data events. 

There have been no major changes from proposal 

regarding recordkeeping requirements for missing data 

events. 

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 the document, “Response to 

Comments: Revision to Certain Provisions of the Mandatory 

Reporting of Greenhouse Gases Rule” (see EPA-HQ-OAR-2008-

0508). 

Comment: Some commenters stated that although EPA has 

justified this proposal by noting that 40 CFR part 75 does 

not require separate accounting of “the duration of missing 

data events or... actions taken to minimize occurrence in the 

future," that alone is not sufficient justification for not 

including these requirements under the reporting program. 

The commenters asserted that part 75's requirements do not 

constrain EPA's obligations in the GHG context. The 

commenters wrote that reporting the duration of a missing 
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data event cannot be considered overly burdensome because 

reporters that accurately use missing data procedures must 

know the duration of missing data events and so must be 

collecting this information regardless. Also, the 

commenters indicated that most facilities covered by the 

rule do not use CEMS, and thus, EPA should not change the 

"minimize occurrence" requirement for all reporters (CEMS 

users and non-CEMS users) because missing data events 

associated with the use of CEMS often have no clear 

measures to avoid similar occurrences in the future. 

Response: With respect to removal of the requirement 

to record the duration of a missing data event, EPA 

determined that the requirement in 40 CFR 98.3(c)(8) to 

report the total number of hours in the year that missing 

data are used for each data element provides sufficient 

information for purposes of the GHG Reporting Program. 

Although the “total number of hours” will not provide 

information on the duration of each missing data event, EPA 

will know the total fraction of the year for which missing 

data are used for a particular data element. We have 

determined that this information provides EPA sufficient 

information on the extent of use of the missing data 

provisions for any given reporter. 
Page 64 of 442 

EPA also decided to remove recordkeeping requirements 

related to “actions taken to prevent or minimize occurrence 

in the future” after considering the value of the potential 

loss of data as compared to the burden of compliance with 

the rule as written. As described below, we determined 

that sufficient information is available regarding missing 

data without requiring this additional information. 

First, reporters must report annual hours for each 

missing data element. Through this reported data, EPA can 

identify whether missing data is particularly prevalent for 

a given data element at a given facility. Second, records 

must be retained on the cause of the event and actions 

taken to restore malfunctioning equipment. If EPA elects 

to review these records, this information, along with 

reported information on the total hours of missing data for 

each data element, will suggest whether the source is 

taking action to prevent or minimize occurrence in the 

future. Therefore, we have determined that it is not 

necessary to collect information specifically on actions 

taken to prevent or minimize occurrence of missing data in 

the future. 

EPA acknowledges the point made by the commenters that 

most facilities subject to the rule do not use CEMS, and 

therefore, this fact can not be used as a justification for 
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removing requirements related to minimizing future 

occurrence. Further, EPA agrees that information on 

duration would likely be collected when following the 

applicable missing data procedures. Nevertheless, based on 

the preceding discussion, EPA has concluded that sufficient 

data will be available on missing data through the required 

reporting of total number of hours in the year that missing 

data are used for each data element (per 40 CFR 

98.3(c)(8)), and the recordkeeping requirements on cause of 

the event and actions taken to restore malfunctioning 

equipment. EPA has determined that requiring collection 

and retention of additional data on duration and actions 

taken to prevent or minimize occurrence in the future is 

not necessary under the reporting program at this time.

F. Subpart A - General Provisions: Other Technical 

Corrections and Amendments

1. Summary of Final Amendments and Major Changes Since 

Proposal.

We are making several additional amendments to subpart 

A, as follows. 

We are making technical corrections to 40 CFR 

98.3(c)(4)(i) through (c)(4)(iii) and (c)(4)(vi) to clarify 

that facilities must report GHG emissions from all 

applicable source categories, which includes general 
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stationary fuel combustion, miscellaneous carbonates and 

any other source category covered by Part 98. This is 

consistent with the language in the 2009 final rule which 

required facilities to report emissions from all applicable 

source categories in subparts C through JJ. In a recent 

final rule (July 12, 2010, 75 FR 39736) we updated 40 CFR 

98.2 to remove the lists of source categories covered by 

the rule and replace the list with Tables, specifically 

Table A-3 and Table A-4 of this chapter. This change was 

merely a reorganization and did not change applicability 

under the rule. The reformatting from lists to tables 

would enable EPA to add source categories in the future, 

and therefore add new subparts to the rule, without having 

to update all language referring to “subparts C through 

JJ.” In finalizing that rule, we made the appropriate 

changes to 40 CFR 98.2 indicating facilities must report 

GHG emissions from stationary fuel combustion sources, 

miscellaneous use of carbonates and all applicable source 

categories in Table A-3 and Table A-4. However, only the 

references to Table A-3 and Table A-4 were carried over to 

40 CFR 98.3(c), which might suggest that facilities did not 

have to report emissions from general stationary 

combustion, because combustion is not in Table A-3 or Table 

A-4. We are therefore amending 40 CFR 98.3(c) to clarify 
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that facilities must also report emissions from general 

stationary combustion and miscellaneous use of carbonates. 

We are amending 40 CFR 98.3(c)(5)(i) to clarify that 

for the purposes of meeting the requirements of this 

paragraph, suppliers of industrial fluorinated GHGs only 

need to calculate and report GHG emissions in mtCO2e for 

those fluorinated GHGs that are listed in Table A-1. 

Suppliers of industrial fluorinated GHGs do not need to 

calculate and report GHG emissions in metric tons CO2

equivalents (mtCO2e) for fluorinated GHGs not listed in 

Table A-1. However, it is important to note that suppliers 

are still required to report these gases under 40 CFR 

98.3(c)(5)(ii) (in metric tons of GHG). 

We are amending 40 CFR 98.3(d)(3) to correct the year 

in which reporters that submit an abbreviated report for 

2010 must submit a full report, from 2011 to 2012. The 

full report submitted in 2012 will be for the 2011 

reporting year. 

We are amending 40 CFR 98.3(f) to correct the crossreference from “§98.3(c)(8)” to “§98.3(c)(9).” We are 

amending 40 CFR 98.3(g)(5)(iii) to correct a spelling 

error. 

We are amending the elements required with a 

certificate of representation under 40 CFR 98.4(i)(2) to 
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include organization name (company affiliation-employer). 

We are also adding the same element to the delegation by 

designated representative and alternate designated 

representative under 40 CFR 98.4(m)(2). Part 98 and the 

amendments do not require the designated representative, 

alternate designated representative, or agent to be an 

employee of the reporting entity. If a designated 

representative further delegates their authority to an 

agent the agent gains access to all data for that facility 

or supplier. To underline the importance of granting 

access to the correct person, EPA requires the designated 

representative (or alternate) to confirm each agent 

delegation. Adding organization name to the certificate of 

representation and notice of delegation adds a level of 

assurance to the confirmation process. 

Finally, we are amending 40 CFR 98.6 (Definitions) and 

40 CFR 98.7 (What standardized methods are incorporated by 

reference into this part?). We are adding or changing 

several definitions to subpart A, which are needed to 

clarify terms used in other subparts of Part 98. 

We are amending the definitions of several terms in 40 

CFR 98.6: 

• Bulk natural gas Liquid 

• Distillate fuel oil 
Page 69 of 442 

• Fossil fuel 

• Fuel gas 

• Municipal solid waste or MSW 

• Natural gas 

• Natural gas liquids, and 

• Standard conditions 

Bulk natural gas liquid. We are amending the 

definitions of “bulk natural gas liquid or NGL” and 

“natural gas liquids (NGL)” by removing the phrase “lease 

separators and field facilities” for enhanced clarity. We 

have retained the words “or other methods” in both 

definitions because the list of separation processes in the 

definitions (absorption, condensation, adsorption) is not 

exhaustive, and other separation/extraction processes may 

be employed at some facilities. We do not wish to exclude 

the reporting of emissions associated with products 

separated/extracted by means not explicitly stated in the 

rule. 

Distillate fuel oil. We are expanding the definition 

of “Distillate fuel oil” to include kerosene-type jet fuel. 

Fossil fuel. We are amending the definition of fossil 

fuel, as proposed, to read, “Fossil fuel means natural gas, 

petroleum, coal, or any form of solid, liquid, or gaseous 

fuel derived from such material for purpose of creating 

useful heat.” This amendment finalizes the same definition 
Page 70 of 442 

of fossil fuel that was originally proposed in April 2009 

(74 FR 16621), but was subsequently amended in the final 

Part 98 (74 FR 56387). The change is not intended to have 

any impact on coverage of greenhouse gases under the GHG 

Reporting Program. 

Fuel gas. We are amending the definition of fuel gas 

to clarify that it includes only gas generated at 

refineries or petrochemical processes subject to subpart X 

and to remove the phrase “or similar industrial process 

unit.” For a fuel explanation of this final change, please 

see the Comments and Response discussion under Section II.G 

of this preamble. 

Municipal solid waste. We are amending the definition 

of municipal solid waste to be similar to, but not exactly 

the same as, the definition of “municipal solid waste” in 

subpart Ea of the NSPS regulations (40 CFR 60.51a). The 

amended definition explains what is meant by “household 

waste,” “commercial/retail waste,” and “institutional 

waste.” Household, commercial/retail, and institutional 

wastes include yard waste, refuse-derived fuel, and motor 

vehicle maintenance materials. Insofar as there is 

separate collection, processing and disposal of industrial 

source waste streams consisting of used oil, wood pallets, 

construction, renovation, and demolition wastes (which 
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includes, but is not limited to, railroad ties and 

telephone poles), paper, clean wood, plastics, industrial 

process or manufacturing wastes, medical waste, motor 

vehicle parts or vehicle fluff, or used tires that do not 

contain hazardous waste identified or listed under 42 

U.S.C. 6921, such wastes are not municipal solid waste. 

However, such wastes qualify as municipal solid waste where 

they are collected with other municipal solid waste or are 

otherwise combined with other municipal solid waste for 

processing and/or disposal. 

Natural gas. We are finalizing the definition of 

natural gas to remove any specifications regarding Btu 

value or methane content. The final definition reads, 

“Natural gas means a naturally occurring mixture of 

hydrocarbon and non-hydrocarbon gases found in geologic 

formations beneath the earth’s surface, of which the 

principal constituent is methane. Natural gas may be field 

quality or pipeline quality.” For a full explanation of 

this final change, please see the Comments and Response 

discussion under this section of the preamble. 

Standard conditions. For consistency across the rule, 

and to reflect typical operating procedures at various 

types of industries covered by 40 CFR part 98, we are 

amending the definition of standard conditions to mean 
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either 60 or 68 degrees Fahrenheit and 14.7 pounds per 

square inch absolute. 

We are adding definitions of the following terms to 40 

CFR 98.6 to address the large number of questions received 

requesting clarification on the meaning of these terms: 

• Agricultural by-products, 

• Primary fuel, 

• Solid by-products, 

• Used oil, and 

• Wood residuals. 

We received no comments on the definitions of 

“Agricultural by-products,” “Primary fuel,” and “Solid byproducts.” Therefore, these definitions have been 

finalized, as proposed. For the purposes of Part 98, 

“Agricultural by-products” includes the parts of crops that 

are not ordinarily used for food (e.g., corn straw, peanut 

shells, pomace, etc.). “Primary fuel” is defined as the 

fuel that contributes the greatest percentage of the annual 

heat input to a combustion unit. “Solid by-products” 

includes plant matter such as vegetable waste, animal 

materials/wastes, and other solid biomass, except for wood, 

wood waste and sulphite lyes (black liquor). 

We proposed to add the term “waste oil” to Table C-1 

but we received comment use of the term “waste oil” could 

result in used oil being classified as hazardous waste. We 
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have therefore changed the term to “used oil.” Used oil 

has been added to Table C-1 as a new fuel type, and is 

defined as a petroleum-derived or synthetically-derived oil 

whose physical properties have changed as a result of 

handling or use, such that the oil cannot be used for its 

original purpose. Used oil consists primarily of 

automotive oils (e.g., used motor oil, transmission oil, 

hydraulic fluids, brake fluid, etc.) and industrial oils 

(e.g., industrial engine oils, metalworking oils, process 

oils, industrial grease, etc). For a full explanation of 

this final change, please see the Comments and Response 

discussion under this section of the preamble. 

The definition of “wood residuals” has been finalized 

similar to the proposal, but EPA has also specifically 

included trim, sander dust, and sawdust from wood products 

manufacturing (including resinated wood product residuals) 

in the final definition. 

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. The 

rationale for any additions or deletions of methods in a 

particular subpart is discussed in the relevant subpart. 

Major changes since proposal are identified in the 

following list. The rationale for these and any other 
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significant changes can be found in this preamble or the 

document, “Response to Comments: Revision to Certain 

Provisions of the Mandatory Reporting of Greenhouse Gases 

Rule” (see EPA-HQ-OAR-2008-0508). 

• Not adopting the proposed amendments to 40 CFR 

98.3(c)(1) to report a facility or supplier ID number. 

• Clarifying the definition of municipal solid waste. 

Clarifying that separate collection, processing and 

disposal of industrial source waste streams consisting 

of used oil, wood pallets, construction, renovation, 

and demolition wastes, clean wood, industrial process 

or manufacturing wastes, medical waste, motor vehicle 

parts or vehicle fluff, or used tires that do not 

contain hazardous waste identified or listed under 42 

U.S.C. 6921, are not municipal solid waste. However, 

such wastes qualify as municipal solid waste where 

they are collected with other municipal solid waste or 

are otherwise combined with other municipal solid 

waste for processing and/or disposal. 

• Finalizing the definition of natural gas to remove any 

specifications regarding Btu value or methane content. 

• Amending the definition of standard conditions to 

provide two alternatives. 

• Replacing the term “waste oil” with “used oil.” 

• Amending the definition of “wood residuals” to include 

trim, sander dust and sawdust from wood products 

manufacturing, including resinated wood product 

residuals. 

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 comments received 

can be found in the document, “Response to Comments: 

Revision to Certain Provisions of the Mandatory Reporting 

of Greenhouse Gases Rule” (see EPA-HQ-OAR-2008-0508). 
Page 75 of 442 

Comment: Several commenters objected to the proposed 

definition of municipal solid waste or MSW. One commenter 

in particular pointed to the regulatory history of the 

definition in 40 CFR 60, subpart Ea, indicating that some 

of the materials excluded by the proposed definition under 

40 CFR part 98 are often included in MSW. According to the 

commenter, some of the exclusions in subpart Ea were added 

to the definition to provide an exemption to certain 

sources that combust materials such as used oil or wood 

pellets separately. By excluding materials often 

considered to be part of MSW, the commenter expressed 

concern that the proposed definition of MSW in 40 CFR part 

98 might force some municipal waste combustors who 

considered themselves to be combusting MSW and would 

therefore otherwise be allowed to use Tier 2, to not meet 

the definition of MSW under 40 CFR part 98 and therefore 

have to install CEMS and use the Tier 4 methodology to 

quantify CO2 emissions. 

Response: EPA proposed to amend the definition of MSW 

to provide greater clarity on what is included as MSW. 

Several questions were raised during implementation of the 

GHGRP because the definition of MSW in the final Part 98 

rule was too generic and did not define terms such as 

“house, commercial/retail, and institutional waste.” To 
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clarify the definition, EPA sought to use another EPA 

definition of the term, and did not intend to push some 

municipal waste combustors into a higher tier. Based on 

supplementary information provided by the commenter (please 

refer to EPA-HQ-OAR-2008-0508), the final definition of MSW 

includes materials that should not have been excluded, and 

clarifies that when these materials are extracted from MSW 

and combusted separately, they are not classified as MSW. 

Comment: Two commenters on the definition of “Natural 

gas” pointed out that not all natural gas (particularly 

field gas) can consistently meet the proposed 

specifications. The commenters were concerned that EPA’s 

proposal to include specifications that natural gas must be 

composed of at least 70 percent methane by volume or have a 

high heat value between 910 and 1,150 Btu per standard 

cubic foot would be problematic for subpart W, when 

finalized, because these ranges could exclude field gas. 

Response: The definition of natural gas in the final 

rule caused significant confusion because it included not 

only naturally occurring mixtures of hydrocarbons, but also 

fuels such as field gas, process gas and fuel gas. We 

proposed to change the definition of “natural gas” to 

include specifications on the methane content and a range 

of Btu values that must be achieved before the gas can be 
Page 77 of 442 

referred to as “natural gas.” Clarifying the definition of 

natural gas is important, particularly given that it is a 

fuel in Table C-1 and if an owner or operator burns a fuel 

outside the range of the specifications, then they could be 

pushed into Tier 3 if any unit has a maximum rated heat 

input capacity greater than 250 million British thermal 

units per hour (mmBtu/hr). 

Based on the comments received we have decided to 

finalize the definition of natural gas without any 

specifications regarding minimum or maximum Btu values or a 

minimum methane content. Although the commenters were 

concerned specifically about the implications of the 

definition of natural gas for the oil and gas industry, 

where the fuels combusted can often fall outside the listed 

specifications thereby potentially forcing them into Tier 

3, these concerns did not weigh heavily into our 

determination to remove the specifications. Rather, we 

considered that most facilities subject to subpart C only 

typically burn natural gas within the proposed 

specifications. For these facilities, it was not necessary 

to list specifications, because most would already fall 

into the specifications we had proposed. Further, we were 

concerned that by introducing specifications to the 

definition of natural gas we could inadvertently push a 
Page 78 of 442 

small number of owners or operators into Tier 3, if they 

have been combusting a fuel outside that range. 

It is true that facilities in the oil and gas industry 

are more likely to combust gas outside the listed 

specifications (e.g., field gas). However, facilities in 

the oil and gas industry will be subject to the reporting 

requirements under subpart W beginning with the 2011 

reporting year. The concerns raised by the commenters with 

respect to calculating combustion-related emissions from 

natural gas were explicitly considered within the context 

of subpart W. 

Comment: One commenter brought to our attention that 

the term “used oil” is more appropriate than “waste oil.” 

According to the commenter, the term “waste oil” could 

result in used oil being classified as hazardous waste 

rather than traditional fuel, and might bring the Resource 

Conservation and Recovery Act program into view. 

Response: Without indicating whether we agree with the 

commenter’s concern or not, we have decided to avoid 

potential complication or confusion and have replaced the 

term “waste oil” with “used oil” in the final rule. 

Comment: We received two comments on the definition 

of “wood residuals.” Both commenters requested that the 

definition explicitly include trim, sander dust and sawdust 
Page 79 of 442 

from wood products manufacturing, including resinated wood 

product residuals because they were concerned that the 

proposed definition was too broad and it was not clear if 

these products were included. 

Response: We agree with the commenter. We did not 

intend to exclude these types of products from the 

definition of wood residuals and agree that these terms 

should be included in the definition in order to provide 

clarity. 

Comment: Several commenters expressed concern about 

EPA’s proposal to add a reporting requirement for facility 

ID. Two commenters suggested that EPA provide a separate 

public comment period for including a facility ID reporting 

requirement, and in that proposal, include a specific 

mechanism for assigning the ID numbers. 

Response: Although we maintain that assigning a 

unique ID number to each facility or supplier, for 

administrative purposes, is important to facilitate program 

implementation, we have decided it is not necessary to 

finalize this reporting requirement at this time, given the 

concerns raised by the commenters. We will consider this 

issue further for future rulemakings. Note that we are 

still finalizing the technical clarification in 40 CFR 
Page 80 of 442 

98.3(c)(1) that it is the physical street address of the 

facility or supplier that must be reported. 

G. Subpart C - General Stationary Fuel Combustion

1. Summary of Final Amendments and Major Changes Since 

Proposal.

Numerous issues have been raised by owners and 

operators in relation to the requirements in subpart C for 

general stationary fuel combustion. The issues being 

addressed by the final amendments include the following: 

• Definition of the source category. 

• GHGs to report. 

• Calculating GHG emissions. 

• Natural gas consumption expressed in therms. 

• Use of Equation C-2b. 

• Categories of gaseous fuels. 

• Use of mass-based gas flow meters. 

• Site-specific stack gas moisture content values. 

• Determining emissions from an exhaust stream diverted 

from a CEMS monitored stack. 

• Biomass combustion in Part 75 units using the CO2

calculation methodologies in 40 CFR 98.33(a)(5). 

• Use of Tier 3. 

• Tier 4 monitoring threshold for units that combust 

MSW. 

• Applicability of Tier 4 to common stack 

configurations. 

• Starting dates for the use of Tier 4. 

• Methane (CH4) and nitrous oxide (N2O) calculations. 

• CO2 emissions from sorbent. 

• Biogenic CO2 emissions from biomass combustion. 

• Fuel sampling for coal and fuel oil. 
Page 81 of 442 

• Tier 3 sampling frequency for gaseous fuels. 

• GHG emissions from blended fuel combustion. 

• Use of consensus standard methods. 

• CO2 monitor span values. 

• CEMS data validation. 

• Use of American Society of Testing and Materials 

(ASTM) Methods D7459-08 and D6866-08. 

• Electronic data reporting and recordkeeping. 

• Common stack reporting option. 

• Common fuel supply pipe reporting option. 

• Table C-1 default HHV and CO2 emission factors. 

• Table C-2 default CH4 and N2O emission factors. 

Definition of the source category. We are adding new 

paragraph 40 CFR 98.30(d), clarifying that the GHG 

emissions from a pilot light need not be included in the 

emissions totals for the facility. A pilot light is a 

small auxiliary flame that simply ignites the burner of a 

combustion process in a boiler, turbine, or other fuel 

combustion device, and is not used to produce electricity 

or steam, or provide useful energy to an industrial 

process, or reduce waste by removing combustible matter. 

GHGs to report. We are amending 40 CFR 98.32 to 

clarify that CO2, CH4, and N2O mass emissions from a 

stationary fuel combustion unit do not need to be reported 

under subpart C if such an exclusion is indicated elsewhere 

in subpart C. 
Page 82 of 442 

Calculating GHG emissions. We are amending the 

introductory text of 40 CFR 98.33(a) to provide additional 

detail and clarify who may (or must) use the calculation 

methods in the subsequent paragraphs to calculate and 

report GHG emissions. Specifically, we are amending this 

text to point out that certain sources may use the methods 

in 40 CFR part 75 to calculate CO2 emissions, if they are 

already using part 75 to report heat input data year-round 

under another CAA program. The introductory text of 40 CFR 

98.33(a) is also being amended to clarify the reporting of 

CO2 emissions from biomass combustion when a unit combusts 

both biomass and fossil fuels. 

Natural gas consumption expressed in therms. We are 

amending 40 CFR 98.33(a)(1) by adding two new equations to 

Tier 1. When natural gas consumption is expressed in 

therms, Equation C-1a enables sources to calculate CO2 mass 

emissions directly from the information on the billing 

records, without having to request or obtain additional 

data from the fuel suppliers. We are also allowing 

Equation C-1a to be used for units of any size when the 

fuel usage information on natural gas billing records is 

expressed in units of therms. A new paragraph, (b)(1)(v), 

has been added to 40 CFR 98.33 to reflect this. Section 
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98.36(e)(2)(i) is also amended to allow gaseous fuel 

consumption to be reported in units of therms. 

Equation C-1b has been added to Tier 1 to accommodate 

situations in which the fuel usage information on gas 

billing records is expressed in mmBtu. We are also adding 

two new equations to 40 CFR 98.33(c), i.e., Equations C-8a 

and C-8b, for calculating CH4 and N2O emissions when the 

fuel usage information on natural gas billing records is in 

units of therms or mmBtu. 

Use of Equation C-2b. We are amending 40 CFR 

98.33(a)(2)(ii), to require calculation of a weighted HHV, 

using Equation C-2b, only for individual Tier 2 units with 

a maximum rated heat input capacity greater than or equal 

to 100 mmBtu/hr, and for groups of units that contain at 

least one unit of that size. For Tier 2 units smaller than 

100 mmBtu/hr and for aggregated groups of Tier 2 units 

under 40 CFR 98.36(c)(1) in which all units in the group 

are smaller than 100 mmBtu/hr, we are allowing reporters to 

use either an annual arithmetic average HHV or an annual 

fuel-weighted average HHV in Equation C-2a. 

Categories of gaseous fuels. We have revised 40 CFR 

98.34(a)(2)(iii) by replacing the term “fossil fuel-derived 

gaseous fuels” with a more inclusive term, i.e., “gaseous 

fuels other than natural gas.” Corresponding changes to 
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Table C-1 were also made for consistency, placing blast 

furnace gas, coke oven gas, fuel gas, and propane in a new 

category, “Other fuels (gaseous).” 

Use of mass-based gas flow meters. The Tier 3 CO2

emissions calculation methodology in 40 CFR 98.33(a)(3) 

allows reporters to use flow meters that measure mass flow 

rates of liquid fuels to quantify fuel consumption, 

provided that they (the reporters) determine the density of 

the fuel and convert the measured mass of fuel to units of 

volume (i.e., gallons), for use in Equation C-4. In 

response to a number of requests, we are amending 40 CFR 

98.33(a)(3)(iv), to conditionally allow reporters to use 

flow meters that measure mass flow rates of gaseous fuels 

for Tier 3 applications, as well as for liquid fuels. A 

reporter wanting to use this option will have to measure 

the density of the gaseous fuel, either with a calibrated 

density meter or by using a consensus standard method or 

standard industry practice, in order to convert the 

measured mass of fuel to units of standard cubic feet, for 

use in Equation C-5. 

Site-specific stack gas moisture content values. We 

are amending 40 CFR 98.33(a)(4)(iii) to allow the use of 

site-specific moisture constants under the Tier 4 

methodology. The site-specific moisture default value(s) 
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must represent the fuel(s) or fuel blends that are 

combusted in the unit during normal, stable operation, and 

must account for any distinct difference(s) in stack gas 

moisture content associated with different process 

operating conditions. Generally, for each site-specific 

default moisture percentage, at least nine runs are 

required using EPA Method 4 - Determination of Moisture 

Content In Stack Gases (40 CFR part 60, appendix A-3). 

Each site-specific default moisture value would be 

calculated by taking the arithmetic average of the Method 4 

runs. Moisture data from the relative accuracy test audit 

(RATA) of a CEMS could be used for this purpose. The final 

rule does allow the site-specific moisture default values 

to be based on fewer than nine Method 4 runs in cases where 

moisture data from the RATA of a CEMS are used to derive 

the default value and the applicable regulation allows a 

single moisture run to represent two or more RATA runs. 

Each site-specific moisture default value must be 

updated at least annually and whenever the reporter 

determines the current value is non-representative due to 

changes in unit or process operation. The updated moisture 

value must be used in the subsequent CO2 emissions 

calculations. 
Page 86 of 442 

Determining emissions from an exhaust stream diverted 

from a CEMS monitored stack. We are finalizing amendments 

to 40 CFR 98.33(a)(4) by adding a new paragraph, 

(a)(4)(viii), to address the determination of CO2 mass 

emissions from a unit subject to the Tier 4 calculation 

methodology when a portion of the flue gases generated by 

the unit exhaust through a stack that is not equipped with 

a CEMS to measure CO2 emissions (herein referred to as an 

“unmonitored stack”). The final amendments require annual 

emission testing of a diverted gas stream to be performed 

at a set point that best represents normal operation, using 

EPA Methods 2 and 3A and (if moisture correction is 

necessary) Method 4. A CO2 mass emission rate is calculated 

from the test results. If, over time, flow rate of the 

diverted stream varies little from the tested flow rate, 

then the annual CO2 mass emissions for the diverted stream 

(which must be added to the CO2 mass emissions measured at 

the main stack) are determined simply by multiplying the CO2

mass emission rate from the emission testing by the number 

of operating hours in which a portion of the flue gas was 

diverted from the main flue gas exhaust system. However, 

if the flow rate of the diverted stream varies 

significantly over the reporting year, the owner or 

operator must either perform additional stack testing or 
Page 87 of 442 

use the best available information (e.g., fan settings and 

damper positions) and engineering judgment to estimate the 

CO2 mass emission rate at a minimum of two additional set 

points, to represent the variation across the normal 

operating range. Then, the most appropriate CO2 mass 

emission rate must be applied to each hour in which a 

portion of flue gas is diverted from the main exhaust 

system. The procedures used to determine the annual CO2

mass emissions for the diverted stream must be documented 

in the GHG monitoring plan. 

Biomass combustion in Part 75 units using the CO2

calculation methodologies in 40 CFR 98.33(a)(5). We are 

amending 40 CFR 98.33(a)(5)(iii)(D) to redesignate it as 40 

CFR 98.33(a)(5)(iv). This is to correct a paragraph 

numbering error in subpart C, because this paragraph 

applies to all of 40 CFR 98.33(a)(5) and not just to 40 CFR 

98.33(a)(5)(iii). 

We had proposed to amend 40 CFR 98.3(c) in subpart A 

and 40 CFR 98.33(a)(5) to clarify that the separate 

reporting of biogenic CO2 is optional for units that are not 

subject to the Acid Rain Program, but are using 40 CFR part 

75 methodologies to calculate CO2 mass emissions, as 

described in 40 CFR 98.33(a)(5)(i) through (a)(5)(iii). 

After considering the comments received on this proposal 
Page 88 of 442 

and other information (see EPA-HQ-OAR-2008-0508), however, 

we are finalizing language which makes it clear that 

reporting of biogenic CO2 emissions from these units is 

optional for reporting year 2010, and mandatory thereafter. 

Please see the discussion in Section II.C of this preamble 

regarding separate reporting of biogenic emissions for 

units subject to 40 CFR part 75. 

Use of Tier 3. We are amending 40 CFR 

98.33(b)(3)(iii) to clarify that the paragraph applies also 

to common pipe configurations where at least one unit 

served by the common pipe has a heat input capacity greater 

than 250 mmBtu/hr. 

We are also adding a new paragraph, (b)(3)(iv), to 40 

CFR 98.33, requiring Tier 3 to be used when specified in 

another subpart of Part 98, regardless of unit size. For 

example, subpart Y requires certain units that combust fuel 

gas to use Equation C-5 in subpart C (which is the Tier 3 

equation for gaseous fuel combustion) to calculate CO2 mass 

emissions, without regard to unit size. 

Tier 4 monitoring threshold for units that combust 

MSW. We are amending 40 CFR 98.33(b)(4)(ii)(A) to change 

the Tier 4 monitoring threshold from 250 tons MSW per day 

to 600 tons MSW per day, based on analysis that this value 

is approximately equivalent to the 250 mmBtu/hr Tier 4 heat 
Page 89 of 442 

input threshold for other large stationary combustion 

units. Units less than 600 tons MSW per day that do not 

meet the requirements in 40 CFR 98.33(b)(4)(iii) are 

allowed to use Tier 2 to calculate CO2 mass emissions 

(specifically, Equation C-2c). 

Applicability of Tier 4 to common stack 

configurations. We are amending 40 CFR 98.33(b)(4) by 

adding provisions to clarify how the Tier 4 criteria apply 

to common stack configurations. Paragraph (b)(4)(i) is 

expanded to include monitored common stack configurations 

that consist of stationary combustion units, process units, 

or both types of units. A new paragraph, (b)(4)(iv) is 

also added describing the following three distinct common 

stack configurations to which Tier 4 might apply. 

The first, most basic configuration is one in which 

the combined effluent gas streams from two or more 

stationary fuel combustion units are vented through a 

monitored common stack (or duct). In this case, Tier 4 

applies if the following conditions are met: 

• There is at least one large unit in the configuration 

that has a maximum rated heat input capacity greater 

than 250 mmBtu/hr or an input capacity greater than 

600 tons/day of MSW (as applicable). 

• At least one large combustion unit in the 

configuration meets the conditions of 40 CFR 

98.33(b)(4)(ii)(A) through (b)(4)(ii)(C). 
Page 90 of 442 

• The CEMS installed at the common stack (or duct) meets 

all of the requirements of 40 CFR 98.33 (b)(4)(ii)(D) 

through (b)(4)(ii)(F). 

Tier 4 also applies when all of the combustion units 

in the configuration are small (not greater than 250 

mmBtu/hr or 600 tons/day of MSW), if at least one of the 

units meets the conditions of 40 CFR 98.33(b)(4)(iii). 

The second configuration is one in which the combined 

effluent gas streams from a stationary combustion unit and 

a process or manufacturing unit are vented through a common 

stack or duct. Many subparts of Part 98 describe this 

situation (see subparts F, G, K, Q, Z, BB, EE, and GG). In 

this case, the use of Tier 4 is required if the stationary 

combustion unit and the monitors installed at the common 

stack or duct meet the applicability criteria of 40 CFR 

98.33(b)(4)(ii) or 98.33(b)(4)(iii). If multiple 

stationary combustion units and a process unit (or units) 

are vented through a common stack or duct, Tier 4 is 

required if at least one of the combustion units and the 

monitors installed at the common stack or duct meet the 

conditions of 40 CFR 98.33(b)(4)(ii) or 98.33(b)(4)(iii). 

The third configuration is one in which the combined 

effluent streams from two or more process or manufacturing 

units are vented through a common stack or duct. In this 

case, if any of these units is required to use Tier 4 under 
Page 91 of 442 

an applicable subpart of Part 98, the owner or operator can 

either monitor the CO2 mass emissions at the Tier 4 unit(s) 

before the effluent streams are combined together, or 

monitor the combined CO2 mass emissions from all units at 

the common stack or duct. However, if it is not feasible 

to monitor the individual units, the combined CO2 mass 

emissions will have to be monitored at the common stack or 

duct, using Tier 4. 

Starting dates for the use of Tier 4. In the October 

30, 2009 final rule, 40 CFR 98.33(b)(5) of subpart C states 

that units that are required to use the Tier 4 methodology 

must begin using it on January 1, 2010 if all required CEMS 

are in place. Otherwise, use of Tier 4 begins on January 

1, 2011, and Tier 2 or Tier 3 may be used to report CO2 mass 

emissions in 2010. We are amending 40 CFR 98.33(b)(5) to 

clarify that sources can begin monitoring CO2 emissions data 

prior to January 1, 2011 from CEMS that successfully 

complete certification testing in 2010. Note that changes 

in methodology during a reporting year are allowed by Part 

98, and must be documented in the annual GHG emissions 

report (see 40 CFR 98.3(c)(6)). 

This revision will allow sources to discontinue using 

Tier 2 or 3 and begin reporting their 2010 emissions under 

Tier 4 as of the date on which all required certification 
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tests are passed. Data recorded during the certification 

test period for a CEMS can also be used for Part 98 

reporting, provided that: all required certification tests 

are passed in sequence, with no test failures; and no 

unscheduled maintenance or repair of the CEMS is required 

during the test period. 

We are also amending 40 CFR 98.33(b)(5) by adding a 

new paragraph, (b)(5)(iii), to address situations where the 

owner or operator of an affected unit that has been using 

Tier 1, 2, or 3 to calculate CO2 mass emissions makes a 

change that triggers Tier 4 applicability by changing: the 

primary fuel, the manner of unit operation, or the 

installed continuous monitoring equipment. In such cases, 

the owner or operator will be required to begin using Tier 

4 no later than 180 days from the date on which the change 

is implemented. This allows adequate time for the owner or 

operator to obtain and/or certify any of the required Tier 

4 continuous monitors. 

Methane and nitrous oxide calculations. Today’s 

amendments remove the term “normal operation” from 40 CFR 

98.33(c)(4)(i) and (c)(4)(ii). Therefore, calculation of 

CH4 and N2O emissions is simply required for each Table C-2 

fuel combusted in the unit during the reporting year. 
Page 93 of 442 

We are also further amending 40 CFR 98.33(c)(4)(ii), 

to allow additional reporting flexibility for certain units 

that combust more than one type of fuel; specifically, for 

units that report heat input data to EPA year-round using 

part 75 CEMS. Under the final amendments to 40 CFR 

98.33(c)(4)(ii), 40 CFR part 75 units that use the worstcase F-factor reporting option can attribute 100 percent of 

the unit’s annual heat input to the fuel with the highest 

F-factor, as though it were the only fuel combusted during 

the report year. 

For Tier 4 units, the requirement to use the best 

available information to determine the annual heat input 

from each type of fuel is being retained in 40 CFR 

98.33(c)(4)(i), but we are also now allowing it under 40 

CFR 98.33(c)(4)(ii)(D) as an alternative for part 75 units, 

in cases where fuel-specific heat input values cannot be 

determined solely from the part 75 electronic data reports. 

Carbon dioxide emissions from sorbent. We are 

amending 40 CFR 98.33(d) to make it more generally 

applicable to different types of CO2–producing sorbents. 

The term “R” is redefined as the number of moles of CO2 

released upon capture of one mole of acid gas. When the 

sorbent is CaCO3, the value of R is 1.00. For other CO2–

producing sorbents, a specific value of R is determined by 
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the reporting facility from the chemical formula of the 

sorbent and the chemical reaction with the acid gas species 

that is being removed. 

Biogenic CO2 emissions from biomass combustion. 

The title and introductory text of 40 CFR 98.33(e) are 

being amended to more precisely define the requirements for 

reporting biogenic CO2 emissions. In general, biogenic CO2

emissions reporting is required only for the combustion of 

the biomass fuels listed in Table C-1 and for municipal 

solid waste (which consists partly of biomass and partly of 

fossil fuel derivatives). 

We are also amending 40 CFR 98.33(e) to describe three 

cases in which reporters may not need to report biogenic CO2

emissions separate from total CO2 emissions, for units that 

combust biomass: 

1. If a biomass fuel is not listed in Table C-1 and is 

combusted in a unit that is not required to use Tier 

4, a reporter is not required to separately report the 

biogenic CO2 emissions from combustion of that fuel 

unless: 

– The fuel is combusted in a large unit (greater than 

250 mmBtu/hr heat input capacity). 

– The biomass fuel accounts for 10 percent or more of 

the annual heat input to the unit. 

In that case, according to 40 CFR 98.33(b)(3)(iii), 

Tier 3 must be used to determine the carbon content of the 

biomass fuel and to calculate the biogenic CO2 emissions. 
Page 95 of 442 

2. If a unit is subject to subpart C or D and uses the CO2

mass emissions calculation methodologies in 40 CFR 

part 75 to satisfy the Part 98 reporting requirements, 

the reporter has the option to report biogenic CO2

emissions for the 2010 reporting year, but is required 

to report them thereafter. 

3. For the combustion of tires, which are also partly 

biogenic (typically about 20 percent biomass, for car 

and truck tires), the reporter has the option, but not 

the requirement, to separately report the biogenic CO2

emissions, by following the applicable provisions in 

40 CFR 98.33(e). 

No comments were received on the proposal to make 

biogenic CO2 emissions reporting optional for the combustion 

of tires, and the proposal has been finalized without 

modification. However, tire-derived fuel has a biomass 

component, and perhaps it should be treated in the same 

manner as MSW, which is also partly biogenic. A number of 

units that are subject to Part 98 combust tires as the 

primary fuel or as a secondary fuel. Therefore, we are 

considering whether these units should be required to 

account for their biogenic CO2 emissions. However, before 

making this mandatory we intend to open it to notice and 

comment in a future rulemaking. 

We are amending 40 CFR 98.33(e)(1) by removing the 

restriction against using Tier 1 to calculate biogenic CO2

emissions on units that use CEMS to measure the total CO2

mass emissions. However, the use of Tier 1 is not allowed 

for calculating biogenic CO2 emissions for combustion of 
Page 96 of 442 

MSW, as originally specified in 40 CFR 98.33(e)(1) of 

subpart C, and is also not allowed for the combustion of 

tires, if biogenic CO2 emissions are calculated for tires. 

We are amending the methodology in 40 CFR 98.33(e)(2), 

which is specifically for units using a CEMS to measure CO2

mass emissions, by limiting it to cases where the CO2

emissions measured by the CEMS are solely from combustion, 

i.e., the stack gas contains no additional process CO2 or 

CO2 from sorbent; and prohibiting its use if the unit 

combusts MSW or tires. 

For sources that combust MSW, we are amending 40 CFR 

98.33(e)(3) to require, except as provided below, the 

quarterly use of ASTM methods D7459-08 and D6866-08, as 

described in 40 CFR 98.34(d), when any MSW is combusted 

either as the primary fuel or as the only fuel with a 

biogenic component. We are also amending 40 CFR 

98.33(e)(3) to allow the ASTM methods to be used, as 

described in 40 CFR 98.34(e), for any unit in which 

biogenic (or partly biogenic) fuels, and non-biogenic fuels 

are combusted, in any proportions. 

In response to comments, we have added an alternative 

calculation methodology for biogenic CO2 emissions from the 

combustion of MSW and/or tires, which may be used when the 

total contribution of these fuels to the unit’s heat input 
Page 97 of 442 

is 10 percent or less. If a unit combusts both MSW and 

tires and the reporter exercises the option not to 

separately report biogenic CO2 emissions from the tires, the 

alternative calculation methodology may still be used for 

the MSW, provided that the contribution of MSW to the 

unit’s total heat input does not exceed 10 percent. The 

methodology may also be used for small, batch incinerators 

that burn no more than 1,000 tons of MSW per year. 

Units that qualify for and elect to use the 

alternative methodology will use Tier 1 to calculate the 

total annual CO2 emissions from the combustion of the MSW or 

tires, and multiply the result by an appropriate default 

factor that represents the biomass fraction of the fuel, to 

obtain an estimate of the annual biogenic CO2 emissions. 

Based on additional background research conducted, we have 

concluded that reasonable default factors are 0.20 for 

tires and 0.60 for MSW (please refer to the Background 

Technical Support Document-Revision of Certain Provisions). 

We are also amending 40 CFR 98.33(e) to delete and 

reserve 40 CFR 98.33(e)(4) and the related subparagraphs. 

Although 40 CFR 98.33(e)(4) allowed the ASTM methods to be 

used to determine biogenic CO2 emissions for various 

combinations of biogenic and fossil fuels, we are deleting 

and reserving that paragraph because the paragraph also 
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included an unnecessary restriction, i.e., it only applied 

to units that use CEMS to measure total CO2 mass emissions. 

The amendments to 40 CFR 98.33(e)(3) described above will 

achieve the same intended purpose as paragraph (e)(4), 

without imposing this restriction, so paragraph (e)(4) is 

no longer needed. 

We are amending 40 CFR 98.33(e)(5) so that it also 

applies to units that are using Tier 2 (Equation C-2a), as 

well as Tier 1 (Equation C-1), for calculating biogenic CO2

mass emissions. The approach in 40 CFR 98.33(e)(5) for 

estimating solid biomass fuel consumption is equally 

applicable to units using those two equations to calculate 

biogenic CO2 emissions. Equation C-2a applies when HHV data 

for a biomass fuel are available at the minimum frequency 

specified in 40 CFR 98.34(a)(2). 

Finally, one commenter asked EPA to allow Part 75 

units to calculate biogenic CO2 emissions using the same 

general approach that is used in 40 CFR 98.33(c)(4)(ii) for 

the CH4 and N2O emissions calculations. This requires a 

heat input-based equation similar to Equation C-10 to be 

added to the rule. We find this request to be reasonable 

and have added a new paragraph, (e)(6), to 40 CFR 98.33(e). 

Paragraph (e)(6) provides the required equation, i.e., 

Equation C-15a. In cases where (HI)A, the fraction of unit 
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heat input from combustion of the biomass fuel, cannot be 

determined from the information in Part 75 electronic data 

reports (e.g., for units that measure the total CO2

emissions with CEMS, if the “worst-case” F-factor option is 

used, or if biomass and fossil fuels with identical Ffactors are combusted), facilities must use the “best 

available information” (as described in 40 CFR 

98.33(c)(4)(ii)(C) and (c)(4)(ii)(D)) to determine (HI)A. 

Fuel sampling for coal and fuel oil. We are amending 

40 CFR 98.34(a)(2), to clarify the frequency at which the 

HHV needs to be determined for different types of fuels. 

First, we are amending 40 CFR 98.34(a)(2)(ii) to 

expand the list of fuels for which sampling of each fuel 

lot is sufficient to include other solid or liquid fuels 

that are delivered in lots. 

Second, we are amending the definition of the term 

“fuel lot” in 40 CFR 98.34(a)(2)(ii), as it pertains to 

facilities that receive multiple deliveries of a particular 

type of fuel from the same supply source each month, either 

by truck, rail, or pipeline. The amendment clarifies that 

a fuel lot consists of all of the deliveries of that fuel 

for a given calendar month. Thus, for these facilities, 

the required HHV sampling has to be no more frequent than 

once per month. We did receive requests to clarify the 
Page 100 of 442 

meaning of the terms “type of fuel” and “supply source,” 

pertaining to the proposal to require only one monthly 

sample to represent multiple fuel deliveries. The final 

rule clarifies that for coal, the type of fuel refers to 

the coal rank (i.e., anthracite, bituminous, subbituminous, or lignite). For fuel oil, the type of fuel 

refers to the grade number or classification of the oil 

(e.g., No. 2 oil, No. 6 oil, jet-A fuel, etc.). The term 

“supply source” is not so easily defined. For the reasons 

set forth in the Response to Comments (Section II.G.2 of 

this preamble), we have chosen not to include a definition 

of “supply source” in the final rule. 

Third, we are adding parallel language to 40 CFR 

98.34(b)(3)(ii), the Tier 3 fuel sampling provisions for 

coal and fuel oil, for consistency with the revisions to 40 

CFR 98.34(a)(2)(ii). 

Finally, we are amending 40 CFR 98.34(a)(2)(ii) and 40 

CFR 98.34(b)(3)(ii) to allow manual oil samples to be taken 

after each addition of oil to the storage tank. Daily 

manual sampling, flow-proportional sampling, and continuous 

drip sampling are also allowed. The final rule requires at 

least one sample to be obtained from each storage tank that 

is currently in service, and whenever oil is added, for as 

long as the tank remains in service. If multiple additions 
Page 101 of 442 

(e.g., from multiple deliveries) are made on a given day, 

taking one sample after the final addition is sufficient. 

No sampling is required for addition of fuel to a tank that 

is out of service. Rather, a sample must be taken when the 

tank is brought into service and whenever oil is added to 

the tank, for as long as the tank remains in service. If 

the daily manual sampling option is implemented, sampling 

from a particular tank is required only on those days when 

oil from that tank is combusted in the unit(s). 

Tier 3 sampling frequency for gaseous fuels. 

We are amending 40 CFR 98.34(b)(3)(ii)(E) to clarify 

that daily sampling of gaseous fuels other than natural gas 

and biogas for carbon content and molecular weight is only 

required where continuous, on-line equipment is in place; 

weekly sampling is required in all other cases. 

GHG emissions from blended fuel combustion. One of 

the most frequently asked questions by the regulated 

community since publication of the October 30, 2009 final 

Part 98 is, “How does one calculate CO2 mass emissions from 

the combustion of blended fuels?” Subpart C provided only 

limited guidance on this issue. We are now finalizing 

amendments to 40 CFR 98.34(a)(3), (b)(1)(vi), and (b)(3)(v) 

to clarify reporting requirements for calculating emissions 

from blended fuels. The amendments make a clear 
Page 102 of 442 

distinction between cases where the mass or volume of each 

fuel in the blend is accurately measured prior to mixing 

(e.g., using individual flow meters for each component) and 

cases where the exact composition of the blend is not 

known. In the former case, the fact that the fuels are 

blended is of no consequence; because the exact quantity of 

each fuel in the blend is known, the CO2 emissions from 

combustion of each component must be calculated separately. 

In the latter case, the blend is considered to be a 

distinct “fuel type,” and the reporter must measure its 

mass or volume and essential properties (e.g., HHV, carbon 

content, etc.) at a prescribed frequency. 

When the mass or volume of each individual component 

of a blend is not precisely known prior to mixing, the 

appropriate method used to calculate the CO2 mass emissions 

from combustion of the blend is as follows. For smaller 

combustion units (heat input capacity not more than 250 

mmBtu/hr), Tier 2 (or possibly Tier 1) can be used when all 

components of the blend are listed in Table C-1 of subpart 

C. In order to perform these CO2 emissions calculations for 

the blend, a reasonable estimate of the percentage 

composition of the blend would be required, using the best 

available information (e.g., from the typical or expected 

range of values of each component). A heat-weighted CO2
Page 103 of 442 

emission factor must be calculated, using new Equation C16. For Tier 1 applications, a heat-weighted default HHV 

must be determined, using new Equation C-17. 

In cases where a fuel blend consists of a mixture of 

fuel(s) listed in Table C-1 and fuel(s) not listed in Table 

C-1, calculation of CO2 and other GHG emissions from 

combustion of the blend is required only for the Table C-1 

fuel(s), using the best available estimate of the mass or 

volume percentage(s) of the Table C-1 fuel(s) in the blend. 

In these cases, the use of Tier 1 is required, with 

modifications to certain terms in Equations C-17 and C-1, 

to account for the fact that the blend is not composed 

entirely of Table C-1 fuels. An example calculation is 

provided in 40 CFR 98.34(a)(3)(iv). 

For larger combustion units (heat input capacity 

greater than 250 mmBtu/hr) that do not qualify to use Tier 

1 or 2, the owner or operator must use Tier 3 to calculate 

the CO2 mass emissions from combustion of a blended fuel. 

The mathematics for Tier 3 are simpler than for Tiers 1 and 

2, since no default values are used in the calculations, 

and an estimate of the percentage composition of the blend 

is not required. To apply Tier 3, the only requirements 

are to accurately measure the annual consumption of the 

blended fuel and to determine its carbon content and (if 
Page 104 of 442 

necessary) molecular weight, at a prescribed frequency. By 

considering the blended fuel to be a distinct “fuel type,” 

in cases where that fuel is not listed in Table C-1, GHG 

emissions reporting is required in accordance with 40 CFR 

98.33(b)(3)(iii), if the blended fuel (as opposed to each 

individual component of the blend) provides at least 10 

percent of the annual heat input to a unit or group of 

units, and if the use of Tier 4 is not required. 

To address the calculation of CH4 and N2O mass 

emissions from the combustion of blended fuels, we are 

adding a new paragraph, (c)(6), to 40 CFR 98.33. 

Calculation of CH4 and N2O emissions is required only for 

components of a blend that are listed in Table C-2 of 

subpart C. 

If the mass or volume of each component of a blend is 

measured before the fuels are mixed and combusted, the 

existing CH4 and N2O mass emissions calculation procedures 

in 40 CFR 98.33(c)(1) through (5) must be followed for each 

component separately. The fact that the fuels are mixed 

prior to combustion is of no consequence in this case. 

If the mass or volume of each individual component is 

not measured prior to mixing, a reasonable estimate of the 

percentage composition of the blend is required, based on 

the best available information, and the procedures in 40 
Page 105 of 442 

CFR 98.33(c)(6)(ii) will be followed. First, the annual 

consumption of each component fuel in the blend is 

calculated by multiplying the total quantity of the blend 

combusted during the reporting year by the estimated mass 

or volume percentage of that component. Next, the annual 

heat input from the combustion of each component is 

calculated by multiplying its annual consumption by the 

appropriate HHV (either the default HHV from Table C-1 or, 

if available, the measured annual average value). The 

annual CH4 and N2O mass emissions for each component must 

then be calculated using the applicable equation in 40 CFR 

98.33(c), i.e., Equation C-8, C-9a, or C-10. Finally, the 

calculated CH4 and N2O emissions are summed across all 

components, and these sums are reported as the annual CH4

and N2O mass emissions for the blend. 

Use of consensus standard methods. We are amending 40 

CFR 98.33(a)(3)(iv) and (a)(3)(v) to remove reference to 

specific standard methods and allow the use of standards 

from consensus-based organizations or industry standard 

practice. We are amending 40 CFR 98.34 to remove the 

specific ASTM and GPA method list for fuel sampling and 

analysis in 40 CFR 98.34(a)(6), to remove the list of 

American Gas Association (AGA) and American Society of 

Mechanical Engineers (ASME) methods for fuel meter 
Page 106 of 442 

calibration in 40 CFR 98.34 (b)(4), and to delete the list 

of ASTM methods to determine carbon content and molecular 

weight in 40 CFR 98.34(b)(5). We are also redesignating 40 

CFR 98.34(b)(5) as 40 CFR 98.34(b)(4), and amending newly 

designated 40 CFR 98.34(b)(4). Finally, we are amending 40 

CFR 98.34(b)(1)(A) to remove the cross-reference to the 

fuel flow meter test methods listed in 40 CFR 98.34(b)(4). 

These amendments allow the owner or operator to use 

manufacturers’ procedures, appropriate methods published by 

consensus-based standards organizations such as ASTM, ASME, 

American Petroleum Institute (API), AGA, ISO, etc.; or use 

industry-accepted practice. The methods used must be 

documented in the monitoring plan under 40 CFR 98.3(g)(5). 

CO2 monitor span values. The Tier 4 calculation method 

in 40 CFR 98.33(a)(4) requires a CO2 concentration monitor 

and a stack gas flow rate monitor to measure CO2 mass 

emissions. The CO2 monitor must be certified and qualityassured according to one of the following: 40 CFR part 60, 

40 CFR part 75, or an applicable State CEM program. When 

the part 60 option is selected, one of the required quality 

assurance (QA) tests of the CO2 monitor is a cylinder gas 

audit (CGA). The CGA checks the response of the CO2

analyzer at two calibration gas concentrations, i.e., one 

between 5 and 8 percent CO2 and one between 10 and 14 
Page 107 of 442 

percent CO2. These CO2 concentration levels are appropriate 

for most stationary combustion applications. However, when 

CO2 emissions from an industrial process (e.g., cement 

manufacturing) are combined with combustion CO2 emissions, 

the resultant CO2 concentration in the stack gas can be 

substantially higher than for the combustion emissions 

alone. In such cases, a span value of 30 percent CO2 (or 

higher) may be required. 

When the CO2 span exceeds 20 percent CO2, the CGA 

concentrations specified in Part 60 only evaluate the lower 

portion of the measurement scale and are no longer 

representative. Therefore, we are amending 40 CFR 98.34(c) 

by adding a new paragraph (c)(6), which allows the CGA of a 

CO2 monitor to be performed using calibration gas 

concentrations of 40 to 60 percent of span and 80 to 100 

percent of span, when the CO2 span value is set higher than 

20 percent CO2. 

CEMS data validation. In subpart C, 40 CFR 98.34(c) 

provides the monitoring and QA requirements for Tier 4. 

However, no criteria for hourly CEMS data validation were 

specified in the final rule. We are adding a new 

paragraph, (c)(7), to 40 CFR 98.34, which requires hourly 

CEMS data validation to be consistent with the sections of 

40 CFR part 60 or part 75 cited in the preceding paragraph 
Page 108 of 442 

of this preamble. Alternatively, the hourly data 

validation procedures in an applicable State CEM program 

can be followed. 

Use of ASTM Methods D7459-08 and D6866-08. Sections 

98.34(d) and (e) of subpart C, respectively, outline 

procedures for quantifying biogenic CO2 emissions for units 

that combust MSW and other units that combust combinations 

of fossil fuels and biomass. Flue gas samples are taken 

quarterly using ASTM Method D7459-08 and analyzed using 

ASTM Method D6866-08. We are amending 40 CFR 98.34(d) and 

(e), as discussed in the following paragraphs. 

The amendments to 40 CFR 98.34(d) require the ASTM 

methods to be used when MSW is combusted in a unit, either 

as the primary fuel, or as the only fuel with a biogenic 

component, unless the unit qualifies for the alternative 

Tier 1 calculation methodology described above, under 

“Biogenic CO2 emissions from biomass combustion.” 

Quarterly sampling with ASTM Method D7459-08 is required 

for a minimum of 24 cumulative hours of sampling per 

quarter, except as provided below. 

We are amending 40 CFR 98.34(e) to remove the 

restriction limiting the use of ASTM Methods D7459-08 and 

D6866-08 to units with CEMS. Rather, any unit that 

combusts combinations of fossil and biogenic fuels (or 
Page 109 of 442 

partly biogenic fuels, such as tires), in any proportions, 

is allowed to determine biogenic CO2 emissions using the 

ASTM methods on a quarterly basis. At least 24 cumulative 

hours of sampling per quarter are required, except as 

provided immediately below. 

We are adding an option to 40 CFR 98.34(d) and (e), 

allowing sources to demonstrate that 8 hours of sampling 

per quarter is sufficient. The demonstration requires a 

minimum of two 8-hour tests and one 24-hour test, performed 

under normal, stable operating conditions. The 

demonstration tests must be distinct, i.e., no overlapping 

of the 8-hour and 24-hour test periods is permitted. If 

the average biogenic fraction obtained from the 8-hour 

tests is within ± 5 percent of the results from the 24-hour 

test, then, in subsequent quarters, the Method D7459-08 

sampling time may be reduced to 8 hours. The results of 

the demonstration must be documented in the monitoring 

plan. 

We are also amending 40 CFR 98.34(d) by adding an 

alternative to allow the owner or operator to collect an 

integrated sample by extracting a small amount of flue gas 

(1 to 5 cubic centimeters (cc)) during every unit operating 

hour in the quarter, in order to obtain a more 

representative sample for analysis. 
Page 110 of 442 

Procedures for estimating missing data. We are 

amending 40 CFR 98.35(a) to clarify that the missing data 

procedures in 40 CFR part 75 are only to be followed by 

units that are in the Acid Rain Program and those that 

monitor and report emissions and heat input data year 

round. Units that only monitor and report during the ozone 

season must follow the missing data procedures in 40 CFR 

98.35(b). 

Electronic data reporting and recordkeeping. We are 

amending the data element lists in 40 CFR 98.36 by adding a 

number of essential data elements and eliminating or 

modifying others. The most significant revisions to the 

data element lists are summarized in the following 

paragraphs. We are also adding an alternative reporting 

option to 40 CFR 98.36(c) to reduce the reporting burden 

for certain facilities. 

We are adding the reporting of methodology start and 

end dates in several places throughout 40 CFR 98.36(b), 

(c), and (d). 

We are amending the data element lists in 40 CFR 98.36 

to be consistent with respect to reporting of emissions by 

fuel type and reporting of biogenic CO2 emissions. 

Specifically, for clarity and consistency with the changes 

to 40 CFR 98.3(c), we have modified the amendments to 40 
Page 111 of 442 

CFR 98.36(d)(1)(ii), (d)(1)(ix), (d)(2)(ii)(I), and 

(d)(2)(iii)(I) from the proposal. These sections state 

that for units subject to 40 CFR part 75, reporting of 

biogenic CO2 emissions is optional only for the 2010 

reporting year. Reporting of these emissions becomes 

mandatory starting with the 2011 reporting year. 

We are removing 40 CFR 98.36(b)(10) to remove the 

requirement to report the customer meter number for units 

that combust natural gas. 

We are finalizing requirements in 40 CFR 

98.36(c)(1)(ii) that only the maximum rated heat input 

capacity of the largest unit in a group must be reported. 

We are also finalizing requirements for 98.36(c)(3) in a 

similar manner, for groups of units served by a common pipe 

We are amending 40 CFR 98.36 to remove the requirement 

to report the combined annual GHG emissions from fossil 

fuel combustion in metric tons of CO2e (i.e., the sum of the 

CO2, CH4, and N2O emissions) by removing 40 CFR 98.36(b)(9), 

(c)(1)(ix), (c)(2)(viii), and (c)(3)(viii). These data 

elements were duplicative of requirements in subpart A. 

We are amending 40 CFR 98.36(b), (c), and (d) to 

require reporting the fuel-specific annual heat input 

estimates, for the purpose of verifying the reported CH4 and 

N2O emissions. Also, we are amending 40 CFR 98.36(e)(2)(iv) 
Page 112 of 442 

to require reporting of the annual average HHV when 

measured HHV data are used to calculate CH4 and N2O 

emissions for a Tier 3 unit, in lieu of using a default HHV 

from Table C-1. 

We are amending 40 CFR 98.36(b) and (d) to make the 

data elements reported under Tiers 1 through 4 consistent 

for the reporting of biogenic CO2 emissions and CO2 from 

fossil fuel combustion. Also, as previously noted in 

Section II.C of this preamble, the amendments to 40 CFR 

98.36(d) state that reporting of biogenic CO2 emissions is 

optional only for the 2010 reporting year for units using 

the CO2 mass emissions calculation methods in 40 CFR part 

75. 

For units that use the Tier 4 methodology to calculate 

CO2 mass emissions, we are amending 40 CFR 98.36(b)(7)(i) 

and (b)(7)(ii) (redesignated as 40 CFR 98.36(b)(9)(i) and 

(b)(9)(ii), respectively) and 40 CFR 98.36 (c)(2)(vi) 

(redesignated as 40 CFR 98.36 (c)(2)(viii)). The 

amendments to these sections require the annual “nonbiogenic” CO2 mass emissions to be reported instead of 

reporting the annual CO2 mass emissions from fossil fuel 

combustion. 

We are adding a new alternative reporting option, 

under 40 CFR 98.36(c)(4). This new option applies to 
Page 113 of 442 

specific situations where a common liquid or gaseous fuel 

supply is shared between large combustion units such as 

boilers or combustion turbines (including Acid Rain Program 

units and other combustion units that use the methods in 40 

CFR part 75 to calculate CO2 mass emissions), and small 

combustion sources such as space heaters, hot water 

heaters, etc. In such cases, a source can simplify 

reporting by attributing all of the GHG emissions from 

combustion of the shared fuel to the large combustion 

unit(s), provided that: 

• The total quantity of the shared fuel supply that is 

combusted during the report year is measured, either 

at the “gate” to the facility or at a point inside the 

facility, using a fuel flow meter, a billing meter or 

tank drop measurements; and 

• On an annual basis, at least 95 percent of the shared 

fuel supply (by mass or volume) is burned in the large 

combustion unit(s) and the remainder of the fuel is 

fed to the small combustion sources. 

Company records can be used to determine the 

percentage distribution of the shared fuel to the large and 

small units. Facilities using this reporting option are 

required to document in their monitoring plan which units 

share the common fuel supply and the method used to 

determine that the reporting option applies. For the small 

combustion sources, a description of the type(s) and 

approximate number of units involved is sufficient. 
Page 114 of 442 

Finally, we are amending 40 CFR 98.36(e)(2)(iii) to 

simplify the recordkeeping requirements in cases where the 

results of fuel analyses for HHV are provided by the fuel 

supplier. Parallel language is added in a new paragraph, 

40 CFR 98.36(e)(2)(v)(E), for the results of carbon content 

and molecular weight analyses received from the fuel 

supplier. In both cases, the owner or operator is required 

to keep records of only the dates on which the fuel 

sampling results are received, rather than keeping records 

of the dates on which the supplier’s fuel samples were 

taken (which may not be readily available). 

Common stack reporting option. Section 98.36(c)(2) of 

subpart C allows subpart C stationary fuel combustion units 

that share a common stack or duct to use the Tier 4 

Calculation Methodology to monitor and report the combined 

CO2 mass emissions at the common stack or duct, in lieu of 

monitoring each unit individually. However, 40 CFR 

98.36(c)(2) does not address circumstances where at least 

one of the units sharing the common stack is not a subpart 

C stationary fuel combustion unit, but is subject to 

another subpart of 40 CFR part 98. In view of this, we are 

amending 40 CFR 98.36(c)(2) by extending the applicability 

of the common stack monitoring and reporting option to 

situations where off-gases from multiple process units or 
Page 115 of 442 

mixtures of combustion products and process off-gases are 

combined together and vented through a common stack or 

duct. 

The amendments to 40 CFR 98.36(c)(2) apply not only to 

ordinary common stack or duct situations where the gas 

streams from multiple units are combined together, but also 

apply when combustion and/or process off-gas streams from a 

single unit (e.g., from a kiln, furnace, petrochemical 

process unit, or smelter) are routed to a stack. To 

accommodate this variation on the concept of a common 

stack, 40 CFR 98.36(c)(2)(ii) is amended to require sources 

to report “1” as the “Number of units sharing the common 

stack or duct” where combustion and/or process emissions 

from a single unit are vented through the same stack or 

duct. 

Finally, since the concept of maximum rated heat input 

capacity may not be applicable to certain types of process 

or manufacturing units, we are amending 40 CFR 

98.36(c)(2)(iii), to require that the “combined maximum 

rated heat input capacity of the units sharing the common 

stack or duct” only be reported when all of the units 

sharing the common stack or duct are stationary fuel 

combustion units. 
Page 116 of 442 

Common fuel supply pipe reporting option. Section 

98.36(c)(3) of subpart C allows units that are served by a 

common fuel supply pipe to report the combined CO2 emissions 

from all of the units in lieu of reporting CO2 emissions 

separately from each unit. To use this reporting option, 

the total amount of fuel combusted in the units must be 

accurately measured with a flow meter calibrated according 

to the requirements in 40 CFR 98.34. Section 98.36(c)(3) 

also states that the applicable tier to use for this 

reporting option is based on the maximum rated heat input 

of the largest unit in the group. 

We are amending 40 CFR 98.36(c)(3) as follows. First, 

the erroneous citation of “§98.34(a)” is corrected to read 

“§98.34(b).” Second, we are amending the requirement in 40 

CFR 98.36(c)(3) to calibrate the fuel flow meter to the 

accuracy required by 40 CFR 98.34(b) (which crossreferences the accuracy specifications in 40 CFR 98.3(i)), 

so that this calibration requirement applies only when Tier 

3 is the required tier for calculating CO2 mass emissions. 

This is consistent with the final amendments to 40 CFR 

98.3(i), where we clarify that the equipment used to 

generate company records under Tier 1 and 2 is not required 

to meet the calibration accuracy specifications of 40 CFR 

98.3(i). 
Page 117 of 442 

The applicable measurement tier for the common pipe 

option, according to subpart C, is based on the rated heat 

input capacity of the largest unit in the group. On the 

surface, this appears to mean that the use of Tiers 1 and 2 

is restricted to common pipe configurations where the 

highest rated heat input capacity of any unit is 250 

mmBtu/hr or less, and that Tier 3 is required if any unit 

has a maximum rated heat input capacity greater than 250 

mmBtu/hr. In general, this is true. However, there is one 

exception in the current rule and we are amending the rule 

to add a second one. Section 98.33(b)(2)(ii) of the 

current rule allows the use of Tier 2 instead of Tier 3 for 

the combustion of natural gas and/or distillate oil in a 

unit with a rated heat input capacity greater than 250 

mmBtu/hr. Today’s rule adds a new paragraph, (b)(1)(v), to 

40 CFR 98.33, allowing Tier 1 to be used when natural gas 

consumption is determined from billing records, and fuel 

usage on those records is expressed in units of therms or 

mmBtu. Therefore, we are also amending 40 CFR 98.36(c)(3) 

to reflect these two exceptions for common pipe 

configurations that include a unit with a maximum rated 

heat input capacity greater than 250 mmBtu/hr. 

Finally, we are amending the provision in 40 CFR 

98.36(c)(3) regarding the partial diversion of a fuel 
Page 118 of 442 

stream such as natural gas that is measured “at the gate” 

to a facility (e.g., using a calibrated flow meter or a gas 

billing meter). Subpart C specifies that when part of a 

fuel stream is diverted to a chemical or industrial process 

where it is used but not combusted, and the remainder of 

the fuel is sent to a group of combustion units, you may 

subtract the diverted portion of the fuel stream from the 

total quantity of the fuel measured at the gate before 

applying the common pipe methodology to the combustion 

units. We are amending the rule to expand this provision 

to include cases where the diverted portion of the fuel 

stream is sent either to a flare or to another stationary 

combustion unit (or units) on site, including units that 

use 40 CFR part 75 methodologies to calculate annual CO2

mass emissions (e.g., Acid Rain Program units). Provided 

that the GHG emissions from the flare and/or other 

combustion unit(s) are properly accounted for according to 

the applicable subpart(s) of Part 98, you are allowed to 

subtract the diverted portion of the fuel stream from the 

total quantity of the fuel measured at the gate, and then 

apply the common pipe reporting option to the group of 

combustion units served by the common pipe, using the Tier 

1, Tier 2, or Tier 3 calculation methodology (as 

applicable). 
Page 119 of 442 

Table C-1. Table C-1 of subpart C provides default 

HHV values and default CO2 emission factors for various 

types of fuel. We are finalizing several amendments to 

Table C-1; specifically, we have: 

• Replaced the categories “fossil fuel-derived fuels 

(solid)” and “fossil fuel-derived fuels (gaseous)” 

with more inclusive terms, i.e., “other fuels (solid)” 

and “other fuels (gaseous).” The “other fuels 

(solid)” category includes four fuels: plastics, 

municipal solid waste, tires, and petroleum coke. The 

“other fuels (gaseous)” category includes blast 

furnace gas, coke oven gas, propane gas, and fuel gas. 

• Removed the word “pipeline” from the description of 

natural gas. 

• Retained the following fuels: “wood residuals,” 

“agricultural by-products,” and “solid by-products”, 

and added definitions of these terms to 40 CFR 98.6 

(see section II.F of this preamble for further 

discussion). 

• Added “Used oil” to the list of petroleum products, 

and added a definition to 40 CFR 98.6 (see section 

II.F of this preamble for further discussion). 

• Removed “still gas” from the list of petroleum 

products and added “fuel gas.” 

• Corrected a typographic error in the HHV for ethane; 

changing it to 0.069 mmBtu/gal, rather than 0.096 

mmBtu/gal. 

• Revised footnote 1 regarding municipal waste combustor 

(MWC) units to make it clear that only MWC units that 

produce steam are prohibited from using the default 

HHV for MSW in Table C-1; MWC units that produce steam 

can still use the default CO2 emission factor for MSW. 

• Modified footnote 1 to Table C-1, to reflect the new 

biogenic CO2 emissions calculation options for certain 

units that combust MSW and/or tires. 

• Revised footnote 2 to clarify that if the conditions 

in 40 CFR 98.243(d)(2)(i) and (d)(2)(ii) and 40 CFR 

98.252(a)(1) and (a)(2) do not apply, reporters 

subject to 40 CFR 98.243(d) of subpart X or subpart Y 

shall use either Tier 3 or Tier 4 

• Remove the qualifier of 100 percent for ethanol and 

biodiesel. 
Page 120 of 442 

• Added a default CO2 emission factor and a default high 

heat value for petroleum-derived ethanol. These are 

the same as the default values for biomass-derived 

ethanol. 

Table C-2. We are finalizing the proposed amendments 

to remove the first iteration of Table C-2 and make minor 

corrections to the second one. The amendments consist of 

correcting the exponents (powers-of-ten) of several 

emission factors. 

Standard conditions. A number of commenters requested 

that, for consistency with the rest of Part 98, we allow 

sources to use 60 oF as standard temperature instead of 68

oF, when Equation C-5 is used to calculate CO2 mass 

emissions from the combustion of gaseous fuel. We proposed 

to allow this alternative for subparts X and Y, because the 

refining and petrochemical industries use 60 oF as standard 

temperature. We have concluded that the commenters’ 

request to modify Equation C-5 accordingly is reasonable, 

and we are revising the definition of the term “MVC (molar 

volume conversion)” in the nomenclature of Equation C-5 

(see revised 40 CFR 98.33(a)(3)(iii)). The revised 

definition of MVC allows sources to use a MVC value of 

either 849.5 standard cubic feet per kilogram mole (scf/kg 

mole) for a standard temperature of 68 oF, or 836.6 scf/kg 

mole for a standard temperature of 60 oF. A corresponding 

change has been made to the definition of “Standard 
Page 121 of 442 

conditions” in 40 CFR 98.6. For verification purposes, a 

data element has been added at 40 CFR 98.36(e)(2)(iv)(G), 

requiring sources using Equation C-5 to report which MVC 

value was used in the emissions calculations. 

Miscellaneous revisions. We are amending 40 CFR 

98.34(c) by adding the citations from 40 CFR part 75 that 

pertain to the initial certification of Tier 4 moisture 

monitoring systems. These amendments also correct an 

inadvertent omission in the verification section of subpart 

C, specifically, in 40 CFR 98.36(e)(2)(v)(C). That section 

requires units using the Tier 3 methodology to keep records 

of the method(s) used for carbon content determination. 

However, no mention is made of keeping records of the 

method(s) used to determine the molecular weight, which is 

a requirement for gaseous fuels. To correct this 

inadvertent oversight, we have amended 40 CFR 

98.36(e)(2)(v)(C) to require records to be kept of the 

method(s) used for both carbon content and (if applicable) 

molecular weight determination. Finally, we have corrected 

typographical errors in the definition of “CC” in the 

nomenclature of Equation C-5. This equation applies to 

gaseous fuels, not liquid fuels, and the units of measure 

for CC must be kg C per kg of fuel, rather than kg C per 

gallon. 
Page 122 of 442 

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 

document, “Response to Comments: Revision to Certain 

Provisions of the Mandatory Reporting of Greenhouse Gases 

Rule” (see EPA-HQ-OAR-2008-0508). 

• A new equation has been added to Tier 1 to accommodate 

situations in which the fuel usage information on gas 

billing records is expressed in mmBtu. We have also 

added two new equations to 40 CFR 98.33(c) for 

calculating CH4 and N2O emissions when the fuel usage 

information on natural gas billing records is in units 

of therms or mmBtu. 

• For units using the Tier 2 methodology that receive 

HHV data less frequently than monthly, or, for small 

units (< 100 mmBtu/hr) regardless of the HHV sampling 

frequency, we are allowing Equation C-2b to be used to 

calculate a fuel-weighted annual average HHV, instead 

of calculating the arithmetic average annual HHV. 

• For consistency with other subparts, we have revised 

the nomenclature of Equation C-5, to allow reporters 

to use a molar volume conversion (MVC) constant 

referenced to a standard temperature of either 60 oF or 

68 oF. 

• For Tier 4 applications, we are allowing site-specific 

moisture default values to be based on fewer than nine 

Method 4 runs in cases where moisture data from the 

RATA of a CEMS are used to derive the default value 

and the applicable regulation allows a single moisture 

run to represent two or more RATA runs. 

• We have modified the approach for calculating CO2 mass 

emissions from an exhaust stream diverted from a CEMS 

monitored stack. 

• For consistency with Subpart A, we have added language 

in several places stating that for Part 75 units, 

separate reporting of biogenic CO2 emissions is 

optional in reporting year 2010 and mandatory 

thereafter. 
Page 123 of 442 

• We have added a new paragraph, (e)(6), to 40 CFR 

98.33, allowing Part 75 units to calculate biogenic CO2

emissions using the same general approach that is used 

in 40 CFR 98.33(c)(4)(ii) for the CH4 and N2O emissions 

calculations. 

• We have added an alternative calculation methodology, 

for biogenic CO2 emissions from the combustion of MSW 

and tires that may be used when the total contribution 

of these fuels to the unit’s heat input is 10 percent 

or less. The methodology, which uses the Tier 1 

equation together with default biogenic percentages, 

may also be used for small, batch incinerators that 

burn no more than 1,000 tons of MSW per year. 

• We have removed the term “consecutive” between the 

words “24” and “hours”, in reference to the minimum 

required sampling time for determining the percentage 

of biogenic CO2 in flue gas when ASTM Method D7459-08 

is used, thereby allowing samples to be collected for 

24 total hours in a quarter, rather than 24 

consecutive hours. We have also added a provision 

allowing sources to perform additional testing to 

demonstrate that sampling for 8 hours is sufficient. 

• We have added language to 40 CFR 98.34(a)(2)(ii)and 

(b)(3)(ii)(B) explaining how to implement certain fuel 

oil sampling options, specifically, daily manual 

sampling and sampling after each addition of oil to 

the tank. 

• To minimize unnecessary burden related to collecting 

information on small units aggregated in a group and 

for the common pipe configuration, we are removing and 

reserving 40 CFR 98.36 (c)(1)(ii), (c)(1)(iii), and 

(c)(3)(ii). We are no longer requiring sources to 

report the number of units in, or the cumulative heat 

input capacity of, an aggregated group of units or a 

group of units served by a common pipe. Only the 

maximum rated heat input capacity of the largest unit 

in the group must be reported. 

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 comments received 
Page 124 of 442 

can be found in the document, “Response to Comments: 

Revision to Certain Provisions of the Mandatory Reporting 

of Greenhouse Gases Rule” (see EPA-HQ-OAR-2008-0508). 

Natural gas consumption expressed in therms. 

Comment: Commenters were generally supportive of 

EPA’s proposal to provide equations for cases where natural 

gas consumption is expressed in therms in billing records. 

One commenter noted that the proposed rule failed to take 

into account that on some natural gas billing records, the 

fuel usage is expressed in units of mmBtu. The commenter 

also brought to our attention that the proposed rule did 

not provide corresponding equations for calculating CH4 and 

N2O emissions when the fuel usage information on gas billing 

records is expressed in therms. 

Response: We agree with these comments and have made 

the following adjustments to the final rule text. First, a 

new equation, Equation C-1b, has been added to Tier 1 to 

accommodate situations in which the fuel usage information 

on gas billing records is expressed in mmBtu. Second, we 

have added two new equations to 40 CFR 98.33(c), i.e., 

Equations C-8a and C-8b, for calculating CH4 and N2O 

emissions when the fuel usage information on natural gas 

billing records is in units of therms or mmBtu. 

Site-specific stack gas moisture content values.
Page 125 of 442 

Comment: Commenters were generally supportive of the 

proposed rule changes related to determining the sitespecific moisture default values. Two commenters requested 

that we allow the site-specific moisture default values to 

be based on fewer than nine Method 4 runs, in cases where 

moisture data from the RATA of a CEMS are used to derive 

the default value and the applicable regulation allows a 

single moisture run to represent two or more RATA runs. 

Response: We believe that this is a reasonable 

request and have incorporated it into the final rule. 

Determining emissions from an exhaust stream diverted 

from a CEMS monitored stack. 

Comment: Commenters were supportive of the intent of 

the proposed amendments, but indicated that the proposed 

methodology for estimating the CO2 mass emissions from the 

diverted gas stream would not be implementable at every 

affected facility. Specifically, commenters took issue 

with EPA’s assumption that the CO2 concentration in the 

diverted stream will be the same as the concentration in 

the main stack. According to the commenters, this is not 

the case, because dilution air introduced via auxiliary 

fans and other equipment will lower the CO2 concentration of 

the side stream. 
Page 126 of 442 

Response: We agree with the commenters’ assessment 

and have modified the proposed approach for quantifying 

emissions in the diverted stream. The final rule requires 

annual emission testing of the diverted gas stream to be 

performed at a set point that best represents normal 

operation, using EPA Methods 2 and 3A and (if moisture 

correction is necessary) Method 4. A CO2 mass emission rate 

is calculated from the test results. If, over time, flow 

rate of the diverted stream varies little from the tested 

flow rate, then the annual CO2 mass emissions for the 

diverted stream (which must be added to the CO2 mass 

emissions measured at the main stack) will be determined 

simply by multiplying the CO2 mass emission rate from the 

emission testing by the number of operating hours in which 

a portion of the flue gas was diverted from the main flue 

gas exhaust system. However, if the flow rate of the 

diverted stream varies significantly over the reporting 

year, the owner or operator must either perform additional 

stack testing or use the best available information (e.g., 

fan settings and damper positions) and engineering judgment 

to estimate the CO2 mass emission rate at a minimum of two 

additional set points, to represent the variation across 

the normal operating range. Then, the most appropriate CO2

mass emission rate must be applied to each hour in which a 
Page 127 of 442 

portion of flue gas is diverted from the main exhaust 

system. The procedures used to determine the annual CO2

mass emissions for the diverted stream must be documented 

in the monitoring plan. 

Fuel sampling for coal and fuel oil. 

Comment: Commenters were generally supportive of the 

proposed amendments to 40 CFR 98.34(a)(2)(ii) and 40 CFR 

98.34(b)(3)(ii) regarding the definition of “fuel lot.” 

However, we did receive requests to clarify the meaning of 

the terms “type of fuel” and “supply source,” pertaining to 

the proposal to require only one monthly sample to 

represent multiple fuel deliveries. 

Response: The final rule clarifies that for coal, the 

type of fuel refers to the coal rank (i.e., anthracite, 

bituminous, sub-bituminous, or lignite). For fuel oil, the 

type of fuel refers to the grade number or classification 

of the oil (e.g., No. 2 oil, No. 6 oil, jet-A fuel, etc.). 

The term “supply source” is not so easily defined, however, 

and we have chosen not to include a definition to the final 

rule. Instead, you may use the following general 

guidelines. The term “supply source” can certainly refer 

to the coal mine, bulk terminal, or refinery from which the 

fuel is obtained. However, it also can apply to a fuel 

vendor who receives a particular type of fuel from 
Page 128 of 442 

different locations and distributes the fuel to his 

customers, provided the important properties of the fuel, 

such as its heating value, sulfur content, carbon content, 

etc., are guaranteed to be within specified ranges. 

Comment: With respect to the HHV sampling 

requirements for each fuel lot, commenters expressed 

concern that the option to sample fuel oil after each 

addition of fuel to the storage tank might not represent 

the fuel actually being combusted. For instance, fuel may 

be added to an empty or a partly full tank that is out of 

service. Also, for a tank that is currently in service, 

due to infrequent combustion of fuel oil, it may have been 

months, or even years, since oil was last added to the 

tank, and it may be months or years before oil is added 

again. 

Response: To address these concerns, the final rule 

requires at least one sample to be obtained from each 

storage tank that is currently in service, and an 

additional sample whenever fuel is added to the tank while 

it remains in service. If multiple additions are made to 

an in-service tank on a given day (e.g., from multiple 

deliveries) one sample taken after the final addition is 

sufficient. No sampling is required for addition of fuel 

to a tank that is out of service. Rather, a sample must be 
Page 129 of 442 

taken when the tank is brought into service and whenever 

oil is added to the tank, for as long as the tank remains 

in service. 

Tier 4 monitoring threshold for units that combust 

MSW. 

Comment: Commenters were generally supportive of the 

proposed amendment to increase the Tier 4 monitoring 

threshold for combustion of municipal solid waste from 250 

to 600 tons per day. One concern was that the amendment 

might not be finalized before the end of 2010; therefore, 

they asked for the final rule to provide a six month 

extension of the January 1, 2011 regulatory deadline for 

installing and certifying CEMS. Some commenters were 

concerned that this proposed change would affect the 

quantity of emissions reported under the program and were, 

therefore, concerned about finalizing this proposed 

amendment. 

Response: There is no need for the requested 

extension because units at or above the 600 ton per day 

threshold have been on notice since the 2009 final rule 

that they are required to use CEMS. The proposed revision 

to the Tier 4 monitoring threshold should not have caused 

them to think otherwise. For units in-between the original 

threshold of 250 tons per day and the revised threshold of 
Page 130 of 442 

600 tons per day, an extension is unnecessary because these 

units can use Tier 2 for the 2010 reporting year. We 

disagree with concerns that the final amendments will 

impact the quantity of data reported to the program, 

because the final amendments still require the same units 

to report GHG emissions. The only difference is that they 

may be using the Tier 2 methodology instead of Tier 4. 

Biogenic CO2 emissions from biomass combustion. 

Comment: Regarding the proposed revisions to the 

optional biogenic CO2 emissions calculation methodology for 

units with CEMS described in 40 CFR 98.33(e)(2), one 

commenter recommended that we make the methodology more 

flexible by modifying Equation C-13. The change to this 

equation proposed by the commenter would allow the volume 

of CO2 from combustion of the biomass fuel (rather than the 

fossil fuel) to be calculated directly and then used in 

Equation C-14 to calculate the biogenic percentage of the 

annual CO2 mass emissions. 

Response: EPA has not incorporated the commenter’s 

proposed changes. Although the proposed modification to 

the methodology could work for fuels such as wood residue 

and bark (which have F-factors listed in Table 1 in section 

3.3.5 of 40 CFR part 75, appendix F), the commenter appears 

to be unaware that we proposed to remove from 40 CFR 
Page 131 of 442 

98.33(e)(1) the restriction prohibiting units with CEMS 

from using the Tier 1 methodology to calculate biogenic CO2

emissions. As stated above, we are finalizing that 

amendment as proposed. Therefore, since both Tier 1 and 

the commenter’s suggested methodology require sources to 

quantify the amount of biomass fuel combusted, and since 

the Tier 1 methodology is significantly simpler than the 

commenter’s proposal, there is no need to revise the 

calculation procedures in 40 CFR 98.33(e)(2). 

Comment: Many units and industrial processes burn 

relatively small amounts of partly biogenic fuels such as 

tires and MSW, as supplementary fuels. Quarterly sampling 

and analysis of the flue gas using ASTM Methods D7459-08 

and D6866-08 is the only available methodology in Part 98 

for quantifying biogenic CO2 emissions from these fuels. 

Some commenters requested relief from reporting biogenic CO2

emissions from such fuels when they account for less than 

10 percent of a unit’s heat input. Another commenter asked 

EPA to either make reporting of biogenic CO2 optional or 

reduce the amount of required testing with the ASTM methods 

to once every five years, for small batch incinerators that 

combust MSW. The commenter provided data for a typical 

batch incinerator, showing that in 2009, less than 400 

metric tons of biogenic CO2 were emitted from the unit. 
Page 132 of 442 

Response: We do not intend to grant a reporting 

exemption for MSW combustion, and, for tires, although the 

reporting is optional at present, we intend to revisit this 

issue in the future. However, we are persuaded that the 

cost of performing the ASTM methods (roughly $5,000 to 

$10,000 each quarter) is unreasonably high for sources that 

burn very small amounts of MSW and/or tires and emit 

comparatively little biogenic CO2. Also, for sources that 

combust tires and wish to report biogenic CO2, the ASTM 

methods are their only option. In view of these 

considerations, we have added an alternative calculation 

methodology for biogenic CO2 emissions from the combustion 

of tires and/or MSW. The methodology is found at 40 CFR 

98.33(e)(3)(iv), and may be used when the total 

contribution of these fuels to the unit’s heat input is 10 

percent or less. We are also allowing this methodology to 

be used for small batch incinerators that burn no more than 

1,000 tons of MSW per year. Supplementary information 

provided by the commenter who requested reduced testing of 

these incinerators indicates that the rated capacities of 

the units can be as high as 1,300 lb/hr of MSW, but that in 

practice, since the units operate in batch mode, a more 

realistic estimate of the actual, annualized capacity of 

the units is somewhere between 100 and 200 lb/hr (see EPA-
Page 133 of 442 

HQ-OAR-2008-0508). If one of these incinerators were to 

combust as much as 200 lb/hr of MSW on an annualized basis, 

this would equate to approximately 875 tons of MSW per 

year. The total annual CO2 emissions from the combustion of 

875 tons of MSW is estimated to be about 800 metric tons, 

based on the default emission factors in Table C-1. 

Assuming a biogenic fraction of 0.60 for MSW, the biogenic 

portion of the total annual CO2 emissions would be 480 

metric tons, which is less than 2 percent of the 25,000 

metric ton applicability threshold in 40 CFR 98.2 for Part 

98 facilities. Based on the above analysis, we have 

concluded that it is appropriate to allow Tier 1 to be used 

together with a default biogenic percentage of 0.60 to 

estimate the biogenic CO2 emissions from MSW combustion in 

small batch incinerators, in lieu of using ASTM Methods 

D7459-08 and D6866-08. To allow for some possible 

variation in the annualized capacity of these units, the 

final rule extends the use of the alternative calculation 

methodology to batch incinerators that combust no more than 

1,000 tons of MSW per year (which corresponds to about 540 

tons of biogenic CO2 per year). 

Comment: With regard to the use of use of ASTM Methods 

D7459-08 and D6866-08, two commenters from facilities that 

combust refuse-derived fuel (RDF) asked us to consider 
Page 134 of 442 

shortening the sampling time to 8 hours, in cases where the 

fuel is relatively homogeneous. Both commenters submitted 

data comparing the results of 8-hour samples against the 

results of 24-hour samples. For one source, the 8-hour 

sample results were within 3.3 percent of the 24-hour 

results, and for the other source the results were within 

1.7 percent. 

Response: EPA agrees that under certain 

circumstances, it may be appropriate to shorten the 

sampling time. Therefore, we are adding an option to 40 

CFR 98.34(d) and (e), allowing sources to demonstrate that 

8 hours of sampling per quarter is sufficient. The 

demonstration requires a minimum of two 8-hour tests and 

one 24-hour test, performed under normal, stable operating 

conditions. The demonstration tests must be distinct, 

i.e., no overlapping of the 8-hour and 24-hour test periods 

is permitted. If the average biogenic fraction obtained 

from the 8-hour tests is within ± 5 percent of the results 

from the 24-hour test, then, in subsequent quarters, the 

Method D7459-08 sampling time may be reduced to 8 hours. 

The results of the demonstration must be documented in the 

monitoring plan. Note that although the data provided by 

the commenters showed that the 8-hour and 24-hour sample 

results differed by no more that 3.3 percent, we believe 
Page 135 of 442 

that ± 5 percent is a more reasonable acceptance criterion. 

This is because the methodology will likely be used for the 

combustion of tires as well as MSW. Tire-derived fuel 

(TDF) has a much lower biogenic fraction than MSW 

(typically about 0.20, compared to 0.60 for MSW). An 

acceptance criterion lower than 5 percent for TDF 

combustion would require the difference between the 8-hour 

and 24-hour sample results to be less than 0.01, and would 

be overly stringent. 

Use of consensus standard methods. 

Comment: We received both supportive and adverse 

comments on the proposed amendments to remove reference to 

specific consensus standards. Commenters that objected to 

the proposal stated that elimination of the lists of 

acceptable methods and allowing the use of “industry 

standard practice” weakens the rule. According to these 

commenters, there is no way to evaluate the technical 

merits of an “industry standard practice,” and the quality 

of the reported GHG emissions data could suffer as a 

result. 

Response: We do not agree with the objections raised 

by these commenters. Subpart C covers a large range of 

industries, perhaps including some that we are not even 

aware of yet that are significant emitters of GHG emissions 
Page 136 of 442 

and therefore covered by the rule. In these early years of 

the program, we want to ensure that the methods required by 

the rule are appropriate for all facilities subject to 

subpart C of the rule. Although we attempted to assemble a 

comprehensive list of methods and provide appropriate 

alternatives in the 2009 final rule, based on questions 

received we determined that it was likely that other valid 

methods from these organizations and practices were 

overlooked. For instance, under the 2009 final rule, even 

updates to the IBR methods to reflect the latest practices 

would not have been acceptable without a rulemaking. The 

commenters did not sufficiently justify why opening up to 

industry consensus standards would compromise data quality. 

In fact, the opposite could be said where more updated 

versions of previously incorporated standards are now 

allowable. 

Further, subpart C already includes a mechanism by 

which we can evaluate the methods being used by industry. 

Sections 98.36(e)(2)(iii) and 98.36(e)(2)(v) require that 

records be kept of the methods that are used for flow meter 

calibration and for HHV and carbon content determinations, 

and 40 CFR 98.36(e)(4) requires sources to provide this 

information to EPA within 30 days of receiving a request 

for it. 
Page 137 of 442 

We note that we have not opened all subparts more 

broadly to industry consensus standards. Please see the 

responses to comments in Section II.K (Hydrogen Production) 

and Section II.M (Petrochemical Production) of this 

preamble for our response to similar comments under these 

subparts. 

Electronic data reporting and recordkeeping. 

Comment: Two commenters asked us to either remove or 

modify the proposed requirement to report the number of 

units in an aggregated group of units. One commenter 

suggested that reporting would be simplified if very small 

sources such as water heaters, space heaters, lab burners, 

etc., were lumped together and counted as one unit. The 

other commenter stated that it is burdensome to keep an 

accurate count of these small domestic units at large, 

complex industrial facilities. That same commenter also 

suggested that only units with heat input ratings of 10 

mmBtu or greater should be included in the count. A third 

commenter noted that it is also difficult to report the 

cumulative maximum heat input rating of a group of units, 

as required under 40 CFR 98.36(c)(1)(iii), when numerous 

small domestic units, some of which may not have a heat 

input rating, are included in an aggregated group. 
Page 138 of 442 

Response: We believe these comments have merit. 

After careful consideration, we have concluded that for 

verification purposes, we do not need to know either the 

exact number of units in an aggregated group or the 

combined maximum rated heat input of the group. The only 

critical data element is the maximum rated heat input 

capacity of the largest unit in the group. This 

information is needed to confirm that none of the units 

exceeds 250 mmBtu/hr, which is the condition that must be 

met to use the unit aggregation option in 40 CFR 

98.36(c)(1). Therefore, in the final rule, we are 

withdrawing the proposed requirement to report the number 

of units in an aggregated group of units, and are removing 

the requirement to report the combined maximum rated heat 

input of the group. We also are withdrawing the proposed 

requirement under 40 CFR 98.36(c)(3)(ii) to report the 

number of units served by a common fuel pipe. The issue is 

the same for the common pipe configuration as for the 

aggregated group of units, i.e., hundreds of small, 

domestic units may be served by the common pipe. To effect 

these rule changes, 40 CFR 98.36 (c)(1)(ii), (c)(1)(iii), 

and (c)(3)(ii) have been removed and reserved. 

Table C-1. 
Page 139 of 442 

Comment: Two commenters questioned the 

appropriateness of listing MSW with plastics and petroleum 

coke. Further, they noted that petroleum coke is listed 

twice in the table, first under petroleum products and then 

again under “other fuels (solid).” According to the 

commenters, petroleum coke is a petroleum derivative, and 

is more appropriately listed with the other “petroleum 

products.” 

Response: The category “other fuels (solid)” in Table 

C-1 is not intended to make any policy statement about the 

nature of the fuels included in the category. The fuels 

included in “other fuels (solid)” are miscellaneous fuels 

that do not fit into any other existing category for the 

purposes of this rule. Petroleum coke was included as a 

petroleum product in the 2009 final rule (74 FR 56409). 

However, the HHV units of measure for petroleum products 

listed in Table C-1 are in mmBtu per gallon and some 

reporters were confused about how to appropriately 

calculate CO2 emissions from petroleum coke, since it is 

actually a solid fuel, and is nominally measured in units 

of short tons. By listing petroleum coke as a solid fuel 

with a heating value in units of mmBtu/short ton, EPA 

intends to alleviate confusion about how emissions are to 

be calculated for petroleum coke. However, we also 
Page 140 of 442 

understand that some facilities report petroleum coke usage 

to the Energy Information Administration (EIA) in units of 

equivalent barrels of petroleum, and may prefer to report 

petroleum coke consumption in units of gallons under this 

rule. As such, EPA is not proposing to remove petroleum 

coke from the list of petroleum products in Table C-1. The 

two HHVs for petroleum coke differ only in units of 

measure. They will give equivalent results when CO2 mass 

emissions are calculated. 

Comment: Two commenters asserted that plastics are a 

small component of MSW and there is no reason why plastics 

should be listed as a separate fuel in Table C-1. These 

commenters stated that to the best of their knowledge, 

plastics are not combusted as a separate fuel stream, and 

they recommended that EPA delete plastics from Table C-1. 

Two other commenters, however, stated that plastics 

are, in fact, sometimes separated out from MSW as a 

separate stream. These commenters provided a suggested 

definition of “plastics” and requested that we add it to 40 

CFR 98.6. The commenters also asked us to modify the 

definition of MSW, to specifically exclude plastics that 

are recovered from MSW, processed separately, and disposed. 

Response: As mentioned in the preamble to the August 

11, 2010 proposed rule (75 FR 48764), facilities have 
Page 141 of 442 

questioned EPA as to why plastics and waste oil, two fuels 

that appeared in Table C-2 of the April 10, 2009 proposed 

rule, were left out of the October 30, 2009 final rule. 

Responding to these concerns, on August 11, 2010 we 

proposed to add both fuels to Table C-1. Today’s rule 

retains these entries, except that waste oil has been 

redesignated as “used oil.” In view of the input received 

from the commenters who brought to our attention that 

plastics (including such things as “...bottles, containers, 

bags, CD cases, sheeting, packaging, broken consumer goods, 

etc....”) are sometimes recovered from MSW and processed 

separately, we decided not to incorporate the 

recommendation of the other commenters who asked us to 

delete plastics from the table. 

 We see no need to add a definition of plastics to 40 

CFR 98.6, since plastic materials are readily identifiable. 

However, to address the commenters’ chief concern, we have 

modified the definition of MSW to clearly state that 

insofar as plastics (along with certain other materials) 

are separated out from MSW, processed and disposed of, they 

are not considered to be “municipal solid waste.” 

Comment: Two commenters argued against the inclusion 

of default factors for “fuel gas” in Table C-1. They 

argued that this would have a negative impact on chemical 
Page 142 of 442 

plant fuel gas streams that were previously exempt from 

Tier 3 requirements when the streams provide less than 10 

percent of the annual heat input to a unit rated greater 

than 250 mmBtu/hr) because Table C-1 previously had no 

factors for fuel gas. According to the commenters, the 

proposed inclusion of default factors for “fuel gas” in 

Table C-1 requires monitoring and reporting of GHG 

emissions from these gas streams. Both commenters 

suggested that Table C-1 should include default factors for 

“refinery fuel gas” rather than “fuel gas.” One commenter 

also suggested revising the definition of “fuel” and 

Footnote 2 associated with the default values for fuel gas 

in Table C-1 to clarify that fuel gas is specific to 

refineries and petrochemical plants, but excludes process 

off-gases from chemical production plants. 

Response: Default values for fuel gas in Table C-1 

are necessary to allow refineries and petrochemical plants 

to use Tier 1 or Tier 2 methods for certain small fuel gas 

streams that were proposed to be excluded from the 

requirement to use Tier 3 for fuel gas in subparts X and Y. 

In providing these factors, we did not intend to require 

chemical plants to monitor and report GHG emissions 

generated by the combustion of “fuel gas” that were 

excluded from reporting requirements in the October 30, 
Page 143 of 442 

2009, final Part 98. Therefore, we agree that some 

additional clarification of terms is needed to prevent the 

fuel gas factor from requiring measurement and reporting of 

GHG from the chemical plant vent gases. 

While changing the term used in Table C-1 to “refinery 

fuel gas” may have helped to clarify the intent, we do not 

believe, given the definition of “fuel gas” in the final 

rule, that this would adequately address the issue. “Fuel 

gas” as defined in the October 30, 2009, final Part 98 

means “gas generated at a petroleum refinery, petrochemical 

plant, or similar industrial process unit, and that is 

combusted separately or in any combination with any type of 

gas.” The inclusion of the phrase “or similar industrial 

process unit” within the definition of fuel gas expanded 

the meaning of fuel gas beyond refineries and petrochemical 

plants. Without specifically defining the term “refinery 

fuel gas” we expect that the rule language would have 

remained ambiguous, especially since refinery fuel gas was 

still intended to apply to some petrochemical processes. 

To clarify our original intent of the proposed 

inclusion of default factors for fuel gas in Table C-1, we 

are revising the definition of “fuel gas” to delete 

reference to other similar industrial process units. In 

Part 98, the term “fuel gas” is intended to apply to 
Page 144 of 442 

petroleum refineries and petrochemical plants, so this 

revision does not affect other Part 98 requirements; it 

simply clarifies that “fuel gas” and the fuel gas factors 

are specific to petroleum refineries and petrochemical 

plants. 

The commenter suggested revising the definition of 

fuel to mean “solid, liquid or gaseous combustible 

material, but excludes process waste off gases from 

chemical production plants that are not petroleum 

refineries or petrochemical plants.” We have determined 

that this change is not necessary because we have addressed 

the commenter’s concerns through the change in the 

definition of fuel gas. We are amending Footnote 2 of 

Table C-1, as requested, to clarify further that only 

reporters subject to 40 CFR 98.243(d) of subpart X or 

subpart Y are required to use Tier 3 or Tier 4 

methodologies when the specific conditions outlined in the 

footnote do not exist. 

H. Subpart D - Electricity Generation

1. Summary of Final Amendments and Major Changes Since 

Proposal.

We are amending 40 CFR 98.40(a) by adding the word 

“mass” between the words “CO2” and “emissions” to make it 

clear that subpart D applies only to units in two 
Page 145 of 442 

categories: ARP units and non-ARP electricity generating 

units (EGUs) that are required to report CO2 mass emissions 

data to EPA year-round. 

Optional reporting of biogenic CO2. For consistency 

with the amendments to subpart C, we have revised 40 CFR 

98.43 to clarify that for subpart D units, reporting of 

biogenic CO2 emissions is optional only for the 2010 

reporting year, and mandatory thereafter. We are also 

adding a new paragraph 40 CFR 98.43(b) indicating that 

biogenic CO2 emissions must be calculated and reported by 

following the applicable methods specified in 40 CFR 

98.33(e). Fossil CO2 emissions are calculated by 

subtracting the biogenic CO2 mass emissions calculated 

according to 40 CFR 98.33(e) from the cumulative annual CO2

mass emissions from paragraph (a)(1) of this section. 

Data reporting requirements. Section 98.46 of subpart 

D specified that the owner or operator of a subpart D unit 

must comply with the data reporting requirements of 40 CFR 

98.36(b) and, if applicable, 40 CFR 98.36(c)(2) or (c)(3). 

These section citations were incorrect. Subpart D units 

all use the CO2 mass emissions calculation methodologies in 

40 CFR part 75. Therefore, the applicable data reporting 

section for these units is 40 CFR 98.36(d), not 40 CFR 
Page 146 of 442 

98.36(b), 40 CFR 98.36(c)(2), or 40 CFR 98.36(c)(3). We 

are amending 40 CFR 98.46 to correct this error. 

Recordkeeping. We are amending 40 CFR 98.47 to state 

that the records kept under 40 CFR 75.57(h) for missing 

data events satisfy the recordkeeping requirements of 40 

CFR 98.3(g)(4) for those same events. We have concluded 

that, as a practical matter, the missing data records 

required to be kept under 40 CFR 75.57(h) are substantially 

equivalent to the records required under 40 CFR 98.3(g)(4). 

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 

document, “Response to Comments: Revision to Certain 

Provisions of the Mandatory Reporting of Greenhouse Gases 

Rule” (see EPA-HQ-OAR-2008-0508). 

• Making separate reporting of biogenic emissions 

optional for part 75 units in the 2010 reporting year 

and mandatory every year thereafter. See sections 

II.C and II.G of this preamble. 

• Adding a provision to subpart D to clarify how to 

calculate and report biogenic CO2 emissions, 

referencing the applicable methods in 40 CFR 98.33(e) 

and the reporting requirements in 40 CFR 98.3(c)(4) 

and (c)(12). 

2. Summary of Comments and Responses

No significant comments were received on the specific 

technical amendments to subpart D. Comments related to the 

proposed separate reporting of biogenic emissions for units 
Page 147 of 442 

subject to 40 CFR part 75 can be found in Sections II.C and 

II.G of this preamble. 

I. Subpart F - Aluminum Production

1. Summary of Final Amendments and Major Changes Since 

Proposal.

Throughout subpart F we are making corrections as 

needed for typographical errors and alphanumeric 

sequencing. We are amending 40 CFR 98.63 to clarify that 

each perfluorocarbon (PFC) compound (perfluoromethane, CF4, 

also called tetrafluoromethane, and perfluoroethane, C2F6, 

also called hexafluoroethane) must be quantified and 

reported and to clarify in 40 CFR 98.63(c) that reporters 

must use CEMS if the process CO2 emissions from anode 

consumption during electrolysis or anode baking of prebake 

cells are vented through the same stack as a combustion 

unit required to use CEMS. This requirement existed in the 

final rule, however, the cross-reference was omitted from 

the introductory language of 40 CFR 98.63(c). 

We are amending 40 CFR 98.64 to clarify the type of 

parameters that must be measured in accordance with the 

recommendations of the EPA/IAI Protocol for Measurement of 

Tetrafluoromethane (CF4) and Hexafluoroethane (C2F6) 

Emissions from Primary Aluminum Production (2008), and the 

frequency of monitoring for those parameters that are not 
Page 148 of 442 

measured annually, but are instead measured on a more or 

less frequent basis. We are also inserting dates into this 

paragraph. In inserting these dates, we have decided to 

use dates in reference to the effective date of the 2009 

final rule, as opposed to the publication date as was 

written in the final rule. It was determined to be more 

appropriate to use the effective date of the rule as the 

basis for the timing of the requirements. Therefore, we 

are amending the paragraph to read “December 31, 2010” in 

place of “one year after publication of the rule” and are 

inserting “December 31, 2012” in place of “three years 

after publication of the rule.” 

We are amending Table F-2 to clarify that default CO2

emissions from pitch volatiles combustion are relevant only 

for center work pre-bake (CWPB) and side work pre-bake 

(SWPB) technologies. 

We are also amending Table F-1 to spell out the 

acronyms for the technologies covered by that table; i.e., 

CWPB, SWPB, vertical stud Søderberg (VSS), and horizontal 

stud Søderberg (HSS). 

The comments received supported the proposed 

amendments, so the amendments to subpart F are finalized as 

proposed. 

2. Summary of Comments and Responses
Page 149 of 442 

One comment letter was received on this subpart, and 

it supported the proposed amendments. The summary and 

response to this comment letter can be found in the 

document, “Response to Comments: Revision to Certain 

Provisions of the Mandatory Reporting of Greenhouse Gases 

Rule” (see EPA-HQ-OAR-2008-0508). 

J. Subpart G - Ammonia Manufacturing

1. Summary of Final Amendments and Major Changes Since 

Proposal.

We are amending subpart G to remove reporting of the 

waste recycle stream or purge, and to make subpart G 

conform to the amendments to the calibration requirements 

in subpart A. With respect to the waste recycle stream, we 

are eliminating the calculation, monitoring and reporting 

of the emissions associated with the waste recycle stream 

or purge currently required by Equation G-6 from 40 CFR 

98.73, 98.74, 98.75, and 98.76. Carbon dioxide emissions 

from waste recycle stream or purge gas used as fuel will 

still be accounted for accurately using Equation G-5 in 

subpart G. Because total process emissions, calculated 

using Equation G-5, will also account for emissions 

associated with use of the purge gas as a fuel, we are 

amending 40 CFR 98.72(b) so that subpart C does not apply 
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to CO2 emissions resulting from the use of purge gas as a 

fuel. 

We are clarifying in 40 CFR 98.72(a) and in the 

definition of CO2 in Equation G-5 that CO2 process emissions 

reported under this subpart may include CO2 that is later 

consumed on site for urea production and therefore is not 

released to the ambient air from the ammonia manufacturing 

process unit. We have included this clarification because 

although the equations accurately reflect total CO2 that is 

generated from the ammonia manufacturing process, not all 

of that CO2 is released on site. Rather, some of the CO2

may be used for urea production and not be actually 

released to the atmosphere until use of the urea at an offsite location. 

We are amending 40 CFR 98.74(d) to limit the flow 

meter calibration accuracy requirements of 40 CFR 

98.3(i)(2) and (i)(3) to only meters that are used to 

measure liquid and gaseous feedstock volumes. In 

accordance with 40 CFR 98.3(i)(1), each measurement device 

that is not used to measure liquid and gaseous feedstock 

volumes, but is used to provide data for the GHG emissions 

calculations, will have to be calibrated to an accuracy 

within the appropriate error range for the specific 
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measurement technology, based on an applicable operating 

standard, such as the manufacturer’s specifications. 

We are amending the definition of CO2 emissions in 

Equation G-5 to indicate that the CO2 emissions estimates 

under subpart G may include CO2 that is later consumed on 

site for urea production and therefore not released to the 

atmosphere from the ammonia manufacturing process unit. 

This change does not affect the total CO2 emissions that are 

quantified and reported to EPA under the calculation 

equations in 40 CFR 98.73. Likewise, we are amending 40 

CFR 98.76(b) to require reporting of the CO2 from the 

ammonia manufacturing process unit that is then used to 

produce urea and the method used to determine that quantity 

of CO2 consumed. 

In addition, we are amending subpart G to correct 

several typographical errors and an incorrect crossreference to another subpart in 40 CFR part 98. We are 

correcting the terms and definitions for annual CO2

emissions arising from gaseous, liquid, and solid fuel 

feedstock consumption in Equations G-1, G-2, and G-3, 

respectively, in 40 CFR 98.73. We are correcting 40 CFR 

98.76(a) by changing the cross-reference from 

“§98.37(e)(2)(vi)” to “§98.37.” 
Page 152 of 442 

We are amending the data reporting requirements in 40 

CFR 98.76(b)(6) and (15) for consistency with the 

calculation procedures in 40 CFR 98.73(b)(6). We are 

amending 40 CFR 98.76(b)(6) to change “petroleum coke” to 

“feedstock” because petroleum coke is the incorrect term, 

and amending 40 CFR 98.76(b)(15) to specify that the carbon 

content analysis method being reported is for each month. 

We are also removing 40 CFR 98.76(b)(17) for the reporting 

of urea produced, if known, as well as reporting 

requirements in 40 CFR 98.76(c) for total pounds of 

synthetic fertilizer produced and total nitrogen contained 

in that fertilizer. 

No major changes have been made to the amendatory 

language since proposal. 

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 the document, “Response to 

Comments: Revision to Certain Provisions of the Mandatory 

Reporting of Greenhouse Gases Rule” (see EPA-HQ-OAR-2008-

0508). 

Comment: One commenter was supportive of all proposed 

amendments to subpart G. However, we received adverse 
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comments on the proposed amendment to remove requirements 

to report the total quantity of synthetic fertilizer 

produced and the nitrogen content of fertilizer. The 

commenter asserted that EPA does not offer a reason for the 

deletion of fertilizer reporting requirements, and noted 

that synthetic fertilizer application drives a large 

fraction of N2O emissions from agricultural soils. They 

asserted that the reporting requirements should be retained 

for several reasons, including that collecting information 

for N2O emissions, even if it is from less than one-half of 

the total fertilizer produced, is valuable. Further, the 

commenter contended that justifying removal of the 

reporting requirement because of the availability of other 

data through the Association of American Plant Food Control 

Officials is not appropriate because those other data may 

not be available reliably into the future and do not map 

emissions back to specific facilities. They argued that 

reporting of synthetic fertilizer production is a good 

first step in estimating N2O emissions from agricultural 

soils. 

Another commenter countered many of the points raised 

above, asserting that data on domestic synthetic fertilizer 

production is not a good indicator of N2O emissions from 
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farming because the rule did not capture all fertilizer 

production and not all fertilizer is applied to fields. 

Response: EPA has finalized, as proposed, the 

amendment to remove reporting requirements of the total 

amount of synthetic fertilizer produced and nitrogen 

contained in that fertilizer. EPA has concluded that the 

burden placed on fertilizer production facilities to report 

on total pounds of synthetic fertilizer and total nitrogen 

contained in that fertilizer would not be commensurate with 

the value of the data we would receive in terms of 

improving our ability to estimate N2O emissions from soils. 

Specifically, facility specific data from producers on the 

nitrogen content of synthetic fertilizer is of minimal 

value in estimating soil N2O emissions by itself. As 

explained in the proposal preamble (75 FR 48767), there are 

a variety of inputs that would be valuable to consider to 

estimate N2O emissions from agricultural soils, including 

fertilizer application rates, timing of application, and 

the use of slow release fertilizers and 

nitrification/release inhibitors, none of which would be 

provided through the provision removed from the rule. 

Given that the information required from the final rule 

would not provide sufficient information to estimate N2O 

emissions from fertilizer application to soils, we are 
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removing the reporting requirement at this time. While 

there is concern over the potential future loss of the 

Association of American Plant Food Control Officials data, 

EPA has determined that it is preferable to remove the 

incomplete reporting requirement at this time and, if 

appropriate in the future, reconsider in a comprehensive 

manner reporting of information on fertilizer production, 

import and use practices. 

K. Subpart P - Hydrogen Production

1. Summary of Final Amendments and Major Changes Since 

Proposal.

We are amending the definition of the terms for the 

average carbon content (CCn) and molecular weight (MWn) in 

Equation P-1 of 40 CFR 98.163 to clarify that, where 

measurements are taken more frequently than monthly, CCn and 

MWn should be calculated using the arithmetic average of 

measurement values within the month. 

We are amending 40 CFR 98.164(b)(1) so it is 

consistent with today’s amendments to 40 CFR 98.3(i). 

First, we are limiting the flow meter calibration accuracy 

requirements of 40 CFR 98.3(i)(2) and (i)(3) to meters that 

are used to measure liquid and gaseous feedstock volumes. 

In accordance with 40 CFR 98.3(i)(1), all other measurement 

devices that are used to provide data for the GHG emissions 
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calculations have to be calibrated only to an accuracy 

within the appropriate error range for the specific 

measurement technology, based on an applicable operating 

standard, such as the manufacturer’s specifications. 

Second, we are removing the requirements for solids 

weighing equipment and oil tank drop measurements to be 

calibrated according to 40 CFR 98.3(i), because the 

provisions of 40 CFR 98.3(i) apply only to gas and liquid 

flow meters. For oil tank drop measurements, the QA 

requirements of 40 CFR 98.34(b)(2) apply. 

As a harmonizing amendment with the amendment allowing 

the use of a gas chromatograph (described in 40 CFR 

98.164(b)(5)), we are adding the phrase “no less frequent” 

to 40 CFR 98.164(b)(2). This change indicates that when 

determining the carbon content and the molecular weight of 

“other gaseous fuels and feedstocks” (e.g., biogas, 

refinery gas, or process gas), you must undertake sampling 

and analysis no less frequently than weekly. Replacing a 

“weekly” requirement with “no less frequent than weekly” 

allows for the use of continuous, on-line equipment gas 

chromatographs. 

We are amending 40 CFR 98.164(b)(5) to allow the use 

of chromatographic analysis of the fuel, provided that the 
Page 157 of 442 

gas chromatograph is operated, maintained, and calibrated 

according to the manufacturer’s instructions. 

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 

document, “Response to Comments: Revision to Certain 

Provisions of the Mandatory Reporting of Greenhouse Gases 

Rule” (see EPA-HQ-OAR-2008-0508). 

• Modification of Equation P-1 to account for 

measurements taken more frequently than monthly to 

determine the molecular weight of the gaseous fuel and 

feedstock. 

• Inclusion of the option to use a gas chromatograph 

(both continuous and non-continuous) for determining 

the carbon content and molecular weight of gaseous 

fuels. 

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 the document, “Response to 

Comments: Revision to Certain Provisions of the Mandatory 

Reporting of Greenhouse Gases Rule” (see EPA-HQ-OAR-2008-

0508). 

Comment: One commenter noted that the fuels and 

feedstocks to a hydrogen plant subject to subpart P 

requirements are often the same fuels that are burned in 
Page 158 of 442 

combustion units subject to subpart C requirements. The 

commenter further noted that both subparts had different 

monitoring and QA/QC requirements which would pose a 

problem for a facility trying to determine which method to 

use. 

Response: No change has been made as a result of this 

comment. We did not receive sufficient information from 

the commenter as to why they would not be able to comply 

using the methods already prescribed in subpart P for 

determining carbon content and molecular weight. As noted 

by the commenter, facilities only subject to subpart C must 

use a method published by a consensus standards 

organization if such a method exits, or an industry 

consensus standard practice. Therefore, the methods in the 

2009 final rule for subpart P could be used to meet the 

requirements in subpart C. We determined that it was 

appropriate to open the methods to industry consensus 

standards or industry standard practices for facilities 

subject to subpart C only, because the industries covered 

by subpart C could be wide ranging and the specific methods 

listed may not be appropriate for certain industry types. 

Because the commenter does not provide specific concerns as 

to why the methods listed in subpart P are not appropriate, 

we have decided not to remove the applicable methods listed 
Page 159 of 442 

in subpart P and replace them with the option to use 

consensus based standards or industry consensus standards.

Comment: One commenter requested that EPA allow the 

use of gas chromatographs as an alternative method for 

determining the carbon content in gaseous fuels and 

feedstocks.

Response: EPA acknowledges the commenter’s 

recommendation to include the option to use gas 

chromatographs for measuring the carbon content and 

molecular weight of fuels and feedstocks in subpart P. As 

a result, EPA has revised the monitoring and QA/QC 

requirements to allow the use of gas chromatographs, both 

continuous and non-continuous, to determine the carbon 

content and molecular weight of fuels and feedstocks 

provided that the gas chromatograph is operated, 

maintained, and calibrated according to the manufacturer's 

instructions.

L. Subpart V - Nitric Acid Production

1. Summary of Final Amendments and Major Changes Since 

Proposal.

We are amending 40 CFR 98.226 to remove the synthetic 

fertilizer and total nitrogen reporting requirement in 40 

CFR 98.226(o). The detailed rationale for this amendment 

is provided in Section II.J of this preamble. 
Page 160 of 442 

2. Summary of Comments and Responses

Several comments were received on the proposal to 

remove the synthetic fertilizer and total nitrogen 

reporting requirement in 40 CFR 98.226(o). Please see 

section II.J (Ammonia Production) of this preamble for the 

comments and responses related to reporting of fertilizer 

production data. 

M. Subpart X - Petrochemical Production

1. Summary of Final Amendments and Major Changes Since 

Proposal.

Numerous issues have been raised by owners and 

operators in relation to the requirements in subpart X for 

petrochemical production facilities. The issues being 

addressed by the amendments include the following: 

• Distillation and recycling of waste solvent. 

• Process vent emissions monitored by CEMS. 

• Process off-gas combustion in flares. 

• CH4 and N2O emissions from combustion of process offgas. 

• Molar volume conversion (MVC) factors. 

• Methodology for small ethylene off-gas streams. 

• Monitoring and QA/QC requirements. 

• Reporting requirements under the CEMS compliance 

option. 

• Reporting requirements for the ethylene-specific 

option. 

• Reporting measurement device calibrations. 

• For the mass balance option, sampling frequency when 

receiving multiple deliveries from same supply source. 
Page 161 of 442 

Distillation and recycling of waste solvent. We are 

adding a new paragraph, as proposed, to 40 CFR 98.240(g) to 

specify that a process that distills or recycles waste 

solvent that contains a petrochemical is not part of the 

petrochemical production source category. 

Process vent emissions monitored by CEMS. We are 

adding a sentence, as proposed, to 40 CFR 98.242(a)(1) that 

specifies CO2 emissions from process vents routed to stacks 

that are not associated with stationary combustion units 

must be reported under subpart X when you comply with the 

CEMS option in 40 CFR 98.243(b). 

Process off-gas combustion in flares. We are amending 

40 CFR 98.242(b), as proposed, by removing the reference to 

flares. 

CH4 and N2O emissions from combustion of process offgas. We are amending 40 CFR 98.243(b), as proposed, to 

clarify that either the default HHV for fuel gas or a sitespecific calculated HHV may be used when using Tier 3 

procedures to calculate CH4 and N2O emissions from 

combustion units that burn petrochemical process off-gas 

and are monitored with a CO2 CEMS. 

Sampling frequency for mass balance method. We are 

amending 40 CFR 98.243(c)(3) to clarify that when multiple 

deliveries of a particular liquid or solid feedstock are 
Page 162 of 442 

received from the same supply source in a month, one 

representative sample is sufficient for the month. The 

amendment is being made in response to a comment received. 

As explained in section II.M.2 of this preamble, we are 

amending 40 CFR 98.243(c)(3)to make the language in subpart 

X consistent with a similar amendment for fuel sampling in 

40 CFR 98.34(b)(3)(ii)(B). The new language does not 

change the requirements in 40 CFR 98.243(c). 

Molar volume conversion (MVC) factors. We are 

amending Equation X-1, as proposed, to provide two 

alternative values of MVC that correspond to the two most 

common standard conditions output by the flow monitors. 

Additionally, the reporting requirements related to this 

equation are being amended, as proposed, to include 

reporting of the standard temperature at which the gaseous 

feedstock and product volumes were determined (either 60 °F 

or 68 °F) and to afford verification of the reported 

emissions. 

Methodology for small ethylene off-gas streams. We 

are finalizing amendments to 40 CFR 98.243(d), as proposed, 

to allow the use of Tier 1 or Tier 2 methods for small 

flows (in cases where a flow meter is not already 

installed). Specifically, Tier 1 or Tier 2 methods may be 
Page 163 of 442 

used for ethylene process off-gas streams that meet either 

of the following conditions: 

• The annual average flow rate of fuel gas (that 

contains ethylene process off-gas) in the fuel gas 

line to the combustion unit, prior to any split to 

individual burners or ports, does not exceed 345 

standard cubic feet per minute (scfm) at 60 °F and 

14.7 pounds per square inch absolute (psia) and a flow 

meter is not installed at any point in the line 

supplying fuel gas or at an upstream common pipe. 

• The combustion unit has a maximum rated heat input 

capacity of less than 30 mmBtu/hr, and a flow meter is 

not installed at any point in the line supplying fuel 

gas (that contains ethylene process off-gas) or an 

upstream common pipe. 

As in the proposal, this amendment also specifies how 

to calculate the annual average flow rate under the first 

condition. Specifically, the total flow obtained from 

company records is to be evenly distributed over 525,600 

minutes per year. In response to comments we are making an 

editorial change to the introductory paragraph of 40 CFR 

98.243(d) to clarify that the common pipe reporting 

alternative may be used when applicable; the intent of the 

requirements in this section are not changed by this 

editorial change. We are also making a number of other 

editorial changes to 40 CFR 98.243(d), as proposed, to 

integrate the amended option with the existing 

requirements. Finally, we are amending 40 CFR 98.246(d)(2) 

and 98.247(c), as proposed, to add reporting and 
Page 164 of 442 

recordkeeping requirements that are related to the 

amendments in 40 CFR 98.243(d)(2). 

Monitoring methods for determining carbon content and 

composition. We are finalizing the proposed addition of 

ASTM D2593-93 (Reapproved 2009), Standard Test Method for 

Butadiene Purity and Hydrocarbon Impurities by Gas 

Chromatography, to 40 CFR 98.244(b)(4). We are further 

amending 40 CFR 98.244(b)(4), as proposed, by adding a new 

paragraph that will allow the use of industry standard 

practice to determine the carbon content or composition of 

carbon black feedstock oils and carbon black products. 

We also added two more published methods to the list 

in 40 CFR 98.244(b)(4) of the final rule: ASTM D7633, 

Standard Test Method for Carbon Black—Carbon Content, and 

EPA Method 9060A in EPA publication SW-846, Test Methods 

for Evaluating Solid Waste, Physical/Chemical Methods. We 

also added an option, already proposed in subparts C and Y, 

to use results of chromatographic analysis of feedstocks 

and products, provided that the gas chromatograph is 

operated, maintained, and calibrated according to the 

manufacturer’s instructions. Finally, we added an option 

to use results of a mass spectrometer analysis of a 

feedstock or product, provided that the mass spectrometer 
Page 165 of 442 

is operated, maintained, and calibrated according to the 

manufacturer’s instructions. 

We are also amending 40 CFR 98.244(b)(4), as proposed, 

to provide facilities the option to determine carbon 

content or composition of feedstocks or products using 

modified versions of the analytical methods listed in 40 

CFR 98.244(b)(4) if the listed methods are not appropriate 

for reasons noted below. The proposed amendments in this 

section would have allowed the use of “other analytical 

methods” if methods listed in 40 CFR 98.244(b)(4) are not 

appropriate for any of the same reasons. However, in 

response to comments, we revised this provision to allow 

the use of “other methods” rather than “other analytical 

methods” so that non-analytical methods also can be used. 

The conditions under which the listed methods may be 

considered inappropriate are the same as at proposal. 

Specifically, a listed method may be considered 

inappropriate if the relevant compounds cannot be detected, 

the quality control requirements are not technically 

feasible, or use of the method will be unsafe. 

We are amending the reporting requirements in 40 CFR 

98.246(a)(11), as proposed, so that if an alternative 

method is used, facilities must include in the annual 

report the name or title of the method used and, the first 
Page 166 of 442 

time it is used, a copy of the method and an explanation of 

why the use of the alternative method is necessary. Also 

as proposed, the amendments to 40 CFR 98.244(b)(4) may be 

used for the 2010 reporting year. 

QA/QC requirements. To maintain consistency with the 

amendments to 40 CFR 98.3(i), we are amending, as proposed, 

the QA/QC provisions for weighing devices, flow meters, and 

tank level measurement devices in 40 CFR 98.244 (b)(1), 

(b)(2), and (b)(3). 

Reporting requirements under the CEMS compliance 

option. As proposed, we are making a number of changes in 

40 CFR 98.246(b)(1) through (b)(5) to clarify the reporting 

requirements under the CEMS compliance option. 

First, we are moving the requirement for reporting of 

the petrochemical process ID from 40 CFR 98.246(b)(3) to 40 

CFR 98.246(b)(1) to be consistent with the structure in 

other reporting sections, and we are renumbering the 

existing paragraphs (b)(1) and (b)(2). 

Second, we are adding a statement in the renumbered 

paragraph 40 CFR 98.246(b)(2) to specify that the reporting 

requirements in 40 CFR 98.36(b)(9)(iii) (as numbered in 

today’s action) for CH4 and N2O do not apply under subpart X 

because applicable reporting requirements are specified in 

40 CFR 98.246(b)(5). 
Page 167 of 442 

Third, in the renumbered 40 CFR 98.246(b)(3), we are 

deleting the requirement to report information required 

under 40 CFR 98.36(e)(2)(vii) because the referenced 

section specifies recordkeeping requirements, not reporting 

requirements. Note that one must still keep the applicable 

records because 40 CFR 98.247(a) references 40 CFR 98.37, 

which in turn requires you to keep all of the applicable 

records in 40 CFR 98.36(e). We are also amending the 

reference to 40 CFR 98.36(e)(2)(vii) to a more general 

reference of 40 CFR 98.36. This makes the reporting 

requirements consistent with the methodology for 

calculating emissions in 40 CFR 98.243(b). 

Fourth, we are amending 40 CFR 98.246(b)(4) to clarify 

our intent. The first sentence in 40 CFR 98.246(b)(4) 

requires reporting of the total CO2 emissions from each 

stack that is monitored with CO2 CEMS; this requirement will 

be unchanged. We are amending the second sentence in 40 

CFR 98.246(b)(4) to clarify that for each CEMS that 

monitors a combustion unit stack, you must estimate the 

fraction of the total CO2 emissions that is from combustion 

of the petrochemical process off-gas in the fuel gas. This 

estimate will give an indication of the total petrochemical 

process emissions, whereas the CEMS data alone will also 
Page 168 of 442 

include emissions from combustion of supplemental fuel (if 

any). 

Finally, as proposed, we are finalizing several 

amendments to 40 CFR 98.246(b)(5). In general, as noted 

above, the requirements in this paragraph are consistent 

with the requirements in 40 CFR 98.36(b)(9)(iii) (as 

numbered in this action). Most of the amendments to 40 CFR 

98.246(b)(5) restate requirements from 40 CFR 

98.36(b)(9)(iii); for example, the amendments clarify that 

emissions are to be reported in metric tons of each gas and 

in metric tons of CO2e. However, because 40 CFR 

98.36(b)(9)(iii) allows you to consider petrochemical 

process off-gas as a part of “fuel gas” rather than as a 

separate fuel, under 40 CFR 98.246(b)(5) you must also 

estimate the fraction of total CH4 and N2O emissions in the 

exhaust from each stack that is from combustion of the 

petrochemical process off-gas. In addition, because 40 CFR 

98.243(b) requires you to determine CH4 and N20 emissions 

using Equation C-8 in subpart C (rather than Equation C10), the amendments to 40 CFR 98.246(b)(5) require 

reporting of the HHV that you use in Equation C-8. We are 

also deleting the erroneous reference to Equation C-10 that 

was included in 40 CFR 98.246(b)(5). 
Page 169 of 442 

Reporting requirements for the ethylene-specific 

option. As proposed, we are finalizing several amendments 

to clarify the reporting requirements in 40 CFR 98.246(c) 

for the combustion-based methodology that is available to 

ethylene-specific option. First, we are adding a 

requirement to report each ethylene process ID to allow 

identification of the applicable process units at 

facilities with more than one ethylene process unit. 

Second, we are making editorial changes to clarify that you 

must estimate the fraction of total combustion emissions 

that is due to combustion of ethylene process off-gas, 

consistent with the requirements described above for 

combustion units that are monitored with CEMS. Third, we 

are replacing the requirement to report the “annual 

quantity of each type of petrochemical produced from each 

process unit” with a requirement to report the “annual 

quantity of ethylene produced from each process unit.” 

Reporting measurement device calibrations. As 

proposed in 40 CFR 98.246(a)(7) we are deleting the 

requirement for reporting of the dates and summarized 

results of calibrations of each measurement device under 

the mass balance option, and we are also adding 40 CFR 

98.247(b)(4) to require retention of these records. 
Page 170 of 442 

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 

document, “Response to Comments: Revision to Certain 

Provisions of the Mandatory Reporting of Greenhouse Gases 

Rule” (see EPA-HQ-OAR-2008-0508). 

• Additional methods for determining carbon content or 

composition of feedstocks and products were added to 

40 CFR 98.244(b)(4). 

• For the optional combustion method for ethylene 

processes, the introductory paragraph in 40 CFR 

98.243(d) was edited to require calculation of GHG 

emissions from “combustion units” rather than from 

“each combustion unit.” This change makes it clear 

that the common pipe reporting alternative specified 

in 40 CFR 98.36(c)(3) of subpart C may be used when 

applicable, and it makes 40 CFR 98.243(d) consistent 

with the reporting requirements for the ethylene 

process option as specified in 40 CFR 98.246(c). 

• For the mass balance option, 40 CFR 98.243(c)(3) was 

revised to specify that multiple deliveries of a 

particular liquid or solid feedstock in a month from 

the same supply source may be considered a single 

feedstock lot, requiring only one representative 

sample for carbon content analysis. This change makes 

the analysis requirements for feedstocks consistent 

with the amended requirements for fuels in 40 CFR 

98.34(b)(3)(ii)(B). 

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 the document, “Response to 

Comments: Revision to Certain Provisions of the Mandatory 
Page 171 of 442 

Reporting of Greenhouse Gases Rule” (see EPA-HQ-OAR-2008-

0508). 

Comment: Several commenters requested either the 

addition of specific carbon content or composition 

measurement methods in 40 CFR 98.244(b)(4) or other changes 

that would increase measurement flexibility. One commenter 

requested that EPA Method 9060 of SW-846 be added to the 

list of methods, and that the list of methods be modified 

to allow for the use of a company-specific method for 

measuring acetonitrile as an alternative to using EPA 

Method 8015 in SW-846. One commenter requested that ASTM 

D7633, Standard Test Method for Carbon Black—Carbon 

Content, be added to the list of methods because it has 

recently been accepted and approved by ASTM. This 

commenter also noted that ASTM is currently reviewing a 

method for carbon content in carbon black feedstock oils 

and requested addition of a statement indicating that once 

this method is approved and assigned an official number by 

ASTM that it is effective as of January 1, 2010. One 

commenter requested that EPA remove the reference to 

“analytical” in the phrase “other analytical methods” in 

proposed 40 CFR 98.244(b)(4)(xiii) (renumbered as paragraph 

(xv)(A) in the final amendments) so that the carbon content 

of ethylene oxide and water solutions could be measured 
Page 172 of 442 

using a densitometer. One commenter stated that 40 CFR 

98.244(b)(4) should be expanded to allow the use of an online mass spectrometer to determine the carbon content and 

molecular weights. One commenter stated that requirements 

for gas chromatography should be consistent across all 

subparts and that EPA should extend the requirements for 

the use of gas chromatographs under subpart C to subpart X. 

Specifically, the commenter requested that the use of gas 

chromatographs be allowed, “provided that the gas 

chromatograph is operated, maintained, and calibrated 

according to the manufacturer’s instructions.” One 

commenter noted that the proposed amendments to subpart C 

added flexibility to the carbon content analysis 

requirements for fuels by eliminating the list of specific 

methods and instead allowing a broader array of methods 

(i.e., industry consensus standard practice, method 

published by a consensus-based standards organization, or 

results of gas chromatographic analysis). This commenter 

stated that the same flexibility should be allowed for 

feedstock and product analysis under subpart X. 

Response: In the preamble to the proposed amendments 

we indicated that we would consider adding carbon content 

methods for carbon black and carbon black feedstock oil if 

they were approved by ASTM before publication of the final 
Page 173 of 442 

amendments. Because it has been approved by ASTM, we have 

added Method D7633, Standard Test Method for Carbon Black—

Carbon Content, to 40 CFR 98.244(b)(4). We have not added 

the requested statement regarding the method for 

determining carbon content in carbon black feedstock oil 

because we cannot cite a specific method without being able 

to incorporate it by reference, and incorporation by 

reference is possible only if a copy of the method is 

available. However, if this method is a current industry 

standard practice, its use since January 1, 2010, is 

allowed by 40 CFR 98.244(b)(4)(xv) of the final amendments. 

We have also decided to make four of the other changes 

suggested by commenters. First, we have added EPA Method 

9060A in SW-846 because a commenter indicated that it is 

much more effective at detecting organic compounds in a 

liquid waste stream than any of the listed methods. 

Because none of the currently listed methods effectively 

detect these compounds in the waste stream, an alternative 

method such as EPA Method 9060A in SW-846 would already be 

allowed under 40 CFR 98.244(b)(4)(xv)(A) of the final 

amendments. However, specifically listing the method will 

make demonstrating compliance more straightforward. 

Second, we have deleted the word “analytical” from the 

phrase “other analytical methods” in 40 CFR 
Page 174 of 442 

98.244(b)(4)(xv)(A) of the final amendments so that nonanalytical methods can be used. We agree with the 

commenter that this change is needed so that a densitometer 

can be used to determine the carbon content in an ethylene 

oxide and water solution. We also agree that a nonanalytical alternative must be available in cases where the 

carbon content of the solution cannot safely be determined 

using any of the listed analytical methods or modifications 

of them. 

Third, we have added the option from subpart C to use 

results from a gas chromatograph, provided the instrument 

is operated, maintained, and calibrated according to the 

manufacturer’s instructions. This change means there is a 

common option in both subparts C and X, which we have 

determined is important because some materials may be a 

fuel in some applications and a petrochemical feedstock in 

others (e.g., ethylene feedstocks). With this change, a 

facility would not have to use two methods to determine the 

carbon content of the same material. 

Fourth, we have added an option to use a mass 

spectrometer to determine the carbon content of a feedstock 

or product. Although a mass spectrometer would more 

commonly be used as one type of detector to determine the 

concentration of individual compounds separated in a gas 
Page 175 of 442 

chromatograph, using a mass spectrometer alone to determine 

the overall carbon content is also acceptable. 

Finally, we have decided not to delete the list of 

specified methods and replace them with a general statement 

allowing the use of any industry consensus standard 

practice or method published by a consensus-based standards 

organization. We have received considerable input from the 

industry on methods that are actually being used. We 

conclude that the existing flexibility in the final 

amendments is sufficient, and that there is no need to 

allow the use of other unspecified methods. We recognize 

that this is not consistent with the methodologies allowed 

for determining carbon content in subpart C; however we 

have concluded that this is justified given the wide 

variety of industries subject to subpart C versus the more 

narrowly-focused sources subject to subpart X. 

We are not specifically allowing the use of a companyspecific method for the determination of carbon content in 

acetonitrile because we are not convinced that it is 

necessary. The commenter indicated that they can use EPA 

Method 8015 of SW-846, and they have not indicated any 

problems with using this method. It is also possible that 

their company-specific method would qualify as a 

modification to a listed method that would be allowed if 
Page 176 of 442 

any of the criteria in 40 CFR 98.244(b)(4)(xv)(A) of the 

final amendments are met. Therefore, we have not made the 

requested change. 

Comment: One commenter requested a modification to 40 

CFR 98.243(c)(3) for carbon black production processes that 

specifies all deliveries of a fuel or feedstock oil in a 

month from the same supply source are considered to be a 

fuel lot, and carbon content must be determined for only 

one representative sample from the lot. 

Response: Although we did not propose amendments to 

the sampling and analysis requirements in 40 CFR 

98.243(c)(3), we did propose a change similar to that 

suggested by the commenter in 40 CFR 98.34(b)(3)(ii)(B) of 

subpart C for fuels. Subpart X currently requires you to 

determine the carbon content for at least one sample of 

each feedstock and product per month. In addition, if you 

make more than one valid carbon content measurement during 

the month (from separate samples), then you must average 

the results arithmetically. (Note that this language does 

not require sampling and analysis for each delivery of a 

feedstock. Furthermore, each delivery of the same 

material, even from different suppliers, is not considered 

to be a separate feedstock.) However, we agree with the 

commenter that if multiple deliveries of the same feedstock 
Page 177 of 442 

are received from the same supply source, one 

representative sample is sufficient for the month. 

Therefore, we have amended 40 CFR 98.243(c)(3) in the 

interest of improving the operating flexibility of the 

rule. We have also broadened the statement so that it 

applies for any liquid or solid feedstock. Please see the 

amended rule language to 40 CFR 98.243(c)(3). 

Comment: One commenter stated that the proposed term 

“each combustion unit” in the introductory paragraph of 40 

CFR 98.243(d) appears to preclude the use of the common 

pipe reporting alternative in 40 CFR 98.36(c)(3). 

According to the commenter, the common pipe option is 

appropriate for ethylene processes, and precluding it will 

not improve the quality of GHG emission estimates. 

Therefore, the commenter requests that “each combustion 

unit” be changed to “combustion units.” 

Response: We have made the suggested change in the 

final amendments because we agree with the commenter’s 

assessment of the proposed language. We did not intend to 

preclude the use of the common pipe option, as evidenced by 

the fact that 40 CFR 98.243(d)(2)(i) and (ii) both specify 

that the determination of when Tier 1 and Tier 2 procedures 

may be used is to be based on whether there is an existing 

flow meter either in the line to the combustion device or 
Page 178 of 442 

an upstream common pipe. Moreover, the reporting 

requirements in 40 CFR 98.246(c)(2) require reporting for 

each stationary combustion unit, or group of stationary 

sources with a common pipe. 

N. Subpart Y - Petroleum Refineries

1. Summary of Final Amendments and Major Changes Since 

Proposal.

Numerous issues have been raised by owners and 

operators in relation to the requirements in subpart Y for 

petroleum refineries. The issues being addressed by the 

amendments include the following: 

• GHG emissions from flares. 

• GHG emissions to report from combustion of fuel gas. 

• GHG emissions to report from non-merchant hydrogen 

production process units. 

• Calculating GHG emissions from fuel gas combustion. 

• Calculating combustion GHG emissions from flares and 

asphalt blowing operations controlled by thermal 

oxidizer or flare. 

• Molar volume conversion factors. 

• Combined stacks monitored by CEMS. 

• Nitrogen concentration monitoring to determine exhaust 

gas flow rate. 

• Calculating CO2 emissions from catalytic reforming 

units. 

• Calculating GHG emissions from sulfur recovery plants. 

• Calculating CO2 emissions from coke calcining units. 

• Calculating CO2 emissions from process vents. 

• Monitoring and QA/QC requirements. 

• Reporting requirements. 
Page 179 of 442 

GHG emissions from flares. We are finalizing 

corrections to 40 CFR 98.252(a) (GHGs to report) as 

proposed to clarify the required emissions methods for 

flares. We are proposing to amend the second sentence in 

40 CFR 98.252(a) to correctly require reporters to 

“Calculate and report the emissions from stationary 

combustion units under subpart C...” and we are proposing to 

add an additional sentence at the end of this section to 

clarify that reporters must “Calculate and report the 

emissions from flares under this subpart.” 

GHG emissions to report from combustion of fuel gas. 

We are finalizing amendments to 40 CFR 98.252(a) as 

proposed to clarify that reporting of CH4 and N2O emissions 

is required for the stationary combustion units fired with 

fuel gas. As described in Section II.G of this preamble, 

we are also amending the definition of fuel gas. 

GHG emissions to report from non-merchant hydrogen 

production process units. As proposed, we are amending 40 

CFR 98.252(i) to clarify that reporting of only CO2

emissions is required for non-merchant hydrogen production 

process units. 

Calculating GHG emissions from fuel gas combustion. 

We are finalizing amendments to 40 CFR 98.252(a), as 

proposed, so that petroleum refineries subject to subpart Y 
Page 180 of 442 

can use the Tier 1 or 2 methodologies in subpart C for 

combustion of fuel gas when either of the following 

conditions exists: 

• The annual average fuel gas flow rate in the fuel gas 

line to the combustion unit, prior to any split to 

individual burners or ports, does not exceed 345 scfm 

at 60 °F and 14.7 psia, and either of the following 

conditions exists: 

– A flow meter is not installed at any point in the 

line supplying fuel gas or an upstream common pipe; 

or 

– The fuel gas line contains only vapors from loading 

or unloading, waste or wastewater handling, and 

remediation activities that are combusted in a 

thermal oxidizer or thermal incinerator. 

• The combustion unit has a maximum rated heat input 

capacity of less than 30 mmBtu/hr, and either of the 

following conditions exists: 

– A flow meter is not installed at any point in the 

line supplying fuel gas or an upstream common pipe; 

or 

– The fuel gas line contains only vapors from loading 

or unloading, waste or wastewater handling, and 

remediation activities that are combusted in a 

thermal oxidizer or thermal incinerator. 

Calculating combustion GHG emissions from flares and 

asphalt blowing operations controlled by thermal oxidizer 

or flare. As proposed, we are finalizing amendments to 40 

CFR 98.253 to renumber existing Equations Y-1 and Y-16 as 

Equations Y-1a and Y-16a, and adding the more detailed 

Equations Y-1b and Y-16b that provide more detailed 

alternative methods for calculating emissions. We are also 
Page 181 of 442 

finalizing corresponding amendments in 40 CFR 98.256 as 

proposed to require reporting of which equation was used 

and, if the new equations are used, reporting of the 

additional equation parameters. 

Molar volume conversion factors. We are finalizing 

amendments to Equations Y-1, Y-3, Y-6, Y-12, Y-18, Y-19, Y20, and Y-23 in subpart Y as proposed to provide two 

alternative values of MVC depending on the standard 

conditions output by the flow monitors. For reasons 

outlined in the “Response to Comments: Revision to Certain 

Provisions of the Mandatory Reporting of Greenhouse Gases 

Rule” (see EPA-HQ-OAR-2008-0508), we are also finalizing a 

similar amendment to Equation Y-2, as a logical outgrowth 

of the proposal and comments received to provide two 

alternative values of MVC in this equation (if mass flow 

monitors are used) depending on the standard conditions at 

which the higher heating value is determined. 

Additionally, the reporting requirements related to each of 

these equations are being amended to include reporting of 

the value of MVC used to support the calculations and to 

allow verification of the reported emissions. 

Combined stacks monitored by CEMS. As proposed, we 

are amending the language in 40 CFR 98.253(c)(1)(ii) and 

also the reporting requirements in 40 CFR 98.256(f)(6) to 
Page 182 of 442 

generalize the language to include other CO2 emission 

sources, not just a CO boiler. 

Nitrogen concentration monitoring to determine exhaust 

gas flow rate. As proposed, we are amending 40 CFR 

98.253(c)(2)(ii) to renumber Equation Y-7 as Equation Y-7a 

and to add an Equation Y-7b to provide an alternative N2

concentration monitoring approach for determining the 

exhaust gas flow rate. We are also finalizing reporting 

requirements in 40 CFR 98.256(f)(9) to report the input 

parameters for Equation Y-7b if it is used. 

Calculating CO2 emissions from catalytic reforming 

units. We are finalizing amendments to the definition of 

the coke burn-off quantity, CBQ, and the term “n” in 

Equation Y-11 in 40 CFR 98.253(e)(3) as proposed to clarify 

the application of Equation Y-11 to continuously 

regenerated catalytic reforming units. 

Calculating GHG emissions from sulfur recovery plants. 

We are amending 40 CFR 98.253(f) as proposed to add “and 

for sour gas sent off site for sulfur recovery” to clarify 

that this calculation methodology applies “For on-site 

sulfur recovery plants and for sour gas sent off site for 

sulfur recovery,...” and to allow non-Claus sulfur recovery 

plants to alternatively follow the requirements in 40 CFR 

98.253(j) for process vents. We also are finalizing 
Page 183 of 442 

amendments to the reporting requirements in 40 CFR 

98.256(h) as proposed to include the type of sulfur 

recovery plant, an indication of the method used to 

calculate CO2 emissions, and reporting requirements for nonClaus sulfur recovery plants that elect to follow the 

requirements in 40 CFR 98.253(j) for process vents. 

Calculating CO2 emissions from coke calcining units. 

We are amending the definition of Mdust (the mass of dust 

collected in the dust collection system) in Equation Y-13 

in 40 CFR 98.253(g) as proposed to clarify that dust 

recycled back to the coke calciner is not included in the 

mass of dust collected in the dust collection system (Mdust). 

We also are finalizing amendments to 40 CFR 98.256(i)(5), 

as proposed, to require facilities that use Equation Y-13 

to indicate whether or not the collected dust is recycled 

to the coke calciner. 

Calculating CO2 emissions from process vents. We are 

finalizing amendments to the process vent requirements in 

40 CFR 98.253(j) as proposed to account for the additional 

sources that may elect to use Equation Y-19, specifically 

non-Claus sulfur recovery units (as previously described) 

and uncontrolled blowdown vents (inadvertently not 

referenced). We are also amending the reporting 

requirements for process vents in 40 CFR 98.256(l) as 
Page 184 of 442 

proposed to clarify that the requirements apply to each 

process vent, and 40 CFR 98.256(l)(5) to require an 

indication of the measurement or estimation method for the 

volumetric flow rate and the mole fraction of the GHG in 

the vent. 

Finally, we are finalizing amendments to 40 CFR 

98.253(n) as proposed to delete the words “equilibrium” and 

“product-specific” to clarify that the true vapor phase of 

the loading operation system should be used when 

determining whether the vapor-phase concentration of 

methane is 0.5 volume percent or more. 

Monitoring and QA/QC requirements. We are finalizing 

amendments to the monitoring and QA/QC requirements in 

subpart Y, 40 CFR 98.254 as proposed, except as provided 

below. We proposed amendments to require all gas flow 

meters on process vents subject to reporting under 40 CFR 

98.253(j) to comply with the monitoring requirements in 40 

CFR 98.254(f). However, for the reasons set forth in the 

Response to Comments (Section N.2. of this preamble), we 

are finalizing amendments for gas flow meters on process 

vents subject to reporting under 40 CFR 98.253(j) to comply 

with the monitoring requirements in 40 CFR 98.254(c). 

A summary of the amendments to the monitoring and 

QA/QC requirements that we are finalizing as proposed is 
Page 185 of 442 

below. Paragraph (a) of 40 CFR 98.254 is amended to 

include also the phrase “sources that use a CEMS to measure 

CO2 emissions according to subpart C of this part...” to 

separate further these sources from those that are covered 

by 40 CFR 98.254(b). We also are re-wording the phrase 

“follow the monitoring and QA/QC requirements in §98.34” 

with “meet the applicable monitoring and QA/QC requirements 

in §98.34” to clarify that the monitors must meet the 

requirements for the specific tier for which monitoring was 

required (Tier 3 sources will comply with the Tier 3 

requirements; Tier 4 sources will comply with the Tier 4 

requirements; etc.). 

Because the QA/QC requirements for CO2 CEMS that were 

formerly included in 40 CFR 98.254(l) will be included in 

the amended paragraph 40 CFR 98.254(a), we are removing 40 

CFR 98.254(l). 

Paragraph (b) of 40 CFR 98.254 is amended to clarify 

that these requirements apply to gas flow meters, gas 

composition monitors, and heating value monitors other than 

those subject to 40 CFR 98.254(a). We are correcting the 

reference to “paragraphs (c) through (e)” to correctly 

reference “paragraphs (c) through (g)” as gas monitoring 

system requirements are specified in 40 CFR 98.254(c) 

through (g). We are also clarifying that the calibration 
Page 186 of 442 

requirements in 40 CFR 98.3(i) only apply to gas flow 

meters and allowing recalibration of gas flow meters 

biennially (every two years), at the minimum frequency 

specified by the manufacturer, or at the interval specified 

by the industry consensus standard practice used. 

Paragraph (b) of 40 CFR 98.254 is also amended to clarify 

that gas composition and heating value monitors must be 

recalibrated either annually, at the minimum frequency 

specified by the manufacturer, or at the interval specified 

by the industry consensus standard practice used. 

Paragraph (c) of 40 CFR 98.254 is amended to clarify 

that the flare or sour gas flow meters must be calibrated 

(in addition to operated and maintained) using either a 

method published by a consensus-based standards 

organization (e.g., ASTM, API, etc.) or the procedures 

specified by the flow meter manufacturer. The ± 5 percent 

accuracy specification is being removed from 40 CFR 

98.254(c). We are also amending 40 CFR 98.254(c) by 

removing the list of methods as this is redundant to the 

existing phrase, “a method published by a consensus-based 

standards organization.” 

Paragraphs (d) and (e) of 40 CFR 98.254 are amended to 

allow the use of any chromatographic analysis to determine 

flare gas composition and high heat value, as an 
Page 187 of 442 

alternative to the methods listed in 40 CFR 98.254(d) and 

(e), provided that the gas chromatograph is operated, 

maintained, and calibrated according to the manufacturer’s 

instructions. The methods used for operation, maintenance, 

and calibration of the gas chromatograph must be documented 

in the written monitoring plan for the unit under 40 CFR 

98.3(g)(5). Paragraph (d) in 40 CFR 98.254 is also amended 

to apply to all gas composition monitors, other than those 

included in 40 CFR 98.254(g), and not just flare gas 

composition monitors. 

We are also amending 40 CFR 98.254(d) to specify that 

the methods in this paragraph are also to be used for 

determining average molecular weight of the gas, which is 

needed in Equations Y-1a and Y-3. We are also adding an 

additional method (ASTM D2503-92) to this section for 

determining average molecular weight. 

We are making a number of amendments to 40 CFR 

98.254(f). The term “exhaust gas flow meter” is replaced 

with the term “gas flow meter,” as proposed. 

We are retaining 40 CFR 98.254(f)(3) and portions of 

40 CFR 98.254(f)(1) but only as general, supplementary 

guidelines for flow monitor installation and operation. 

Thus, we are amending 40 CFR 98.254 to require that 

reporters must do all of the following: 
Page 188 of 442 

• Install, operate, calibrate, and maintain each stack 

gas flow meter according to the requirements in 40 CFR 

63.1572(c); 

• Locate the flow monitor at a site that provides 

representative flow rates (avoiding locations where 

there is swirling flow or abnormal velocity 

distributions); and 

• Use a monitoring system capable of correcting for the 

temperature, pressure, and moisture content to output 

flow in dry standard cubic feet (standard conditions 

as defined in 40 CFR 98.6). 

We are making a technical correction to 40 CFR 

98.254(g) to correct the cross-reference from 40 CFR 

63.1572(a) to 40 CFR 63.1572(c). 

We are amending 40 CFR 98.254(h) to require 

calibration of mass measurement equipment according to the 

procedures specified by National Institute of Standards and 

Technology (NIST) Handbook 44 or the procedures specified 

by the manufacturer, and removing reference to the 

calibration requirements in 40 CFR 98.3(i). 

Reporting requirements. This section covers reporting 

requirements that have not been described in previous 

sections of this preamble. 

We are amending the reporting requirements in 40 CFR 

98.256(e)(6) and (8) for Equations Y-1 (renumbered to Y-1a) 

and Y-2, respectively, to require reporting of whether 

daily or weekly measurement periods are used, for 

verification purposes. 
Page 189 of 442 

In 40 CFR 98.256(f)(6), 40 CFR 98.256(h)(6), and 40 

CFR 98.256(i)(6), we are amending the references to 40 CFR 

98.36(e)(2)(vi) to reference 40 CFR 98.36 more generally. 

This will make the references consistent with the 

associated requirements in 40 CFR 98.253. 

We are amending 40 CFR 98.256(f) to require reporting 

of the unit-specific emission factor for CH4 and N2O, if 

used, in the newly designated 40 CFR 98.256(f)(11) and 

(12), respectively. 

We are amending 40 CFR 98.256(i)(8) to make it 

consistent with the information collected in 40 CFR 

98.245(i)(7). 

We are also amending 40 CFR 98.256(j)(2) to clarify 

that the reporting requirements for asphalt blowing apply 

at the unit level. 

We are also amending 40 CFR 98.256(o) to re-organize 

the reporting requirements to separate and clarify the 

reporting requirement for storage tanks used for processing 

unstabilized crude oil from those reporting requirements 

for other types of storage tanks. 

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 

document, “Response to Comments: Revision to Certain 
Page 190 of 442 

Provisions of the Mandatory Reporting of Greenhouse Gases 

Rule” (see EPA-HQ-OAR-2008-0508). 

• Amending Equation Y-2 in subpart Y to provide two 

alternative values of MVC in this equation (if mass 

flow monitors are used) depending on the standard 

conditions at which the higher heating value is 

determined. 

• Amending requirements for gas flow meters on process 

vents subject to reporting under 40 CFR 98.253(j) to 

comply with the monitoring requirements in 40 CFR 

98.254(c) rather than 40 CFR 98.254(f). 

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 comments received 

can be found in the document, “Response to Comments: 

Revision to Certain Provisions of the Mandatory Reporting 

of Greenhouse Gases Rule” (see EPA-HQ-OAR-2008-0508). 

Comment: One commenter stated that they have 

identified gas streams that would otherwise fit the 

requirements for the use of the Tier 1 or Tier 2 

methodologies, as proposed in 40 CFR 98.252(a)(1) and (2), 

if it were not for the fact that they are equipped with 

flow meters. According to the commenter, these streams are 

not what industry would define as “refinery fuel gas” but 

would fall under the realm of “fuel gas” as originally 

defined in 40 CFR 98.6 in the October 30, 2009, final Part 

98, and in the amended definition. These can include 
Page 191 of 442 

streams that are process off-gas or vent gases with 

properties much different from traditional “refinery fuel 

gas” streams and are not part of the refinery’s fuel gas 

system. According to the commenter, these off-gas streams 

may not be sampled currently. The commenter asserted that 

many of these streams are difficult to sample (for example, 

because of low pressure) or may present hazardous sampling 

conditions. According to the commenter, the added rigor 

associated with Tier 3 requirements is not justified for 

the increased safety risk, considering the very small 

contribution of emissions (on the order of 0.1 percent of a 

refinery’s total greenhouse gas emissions as estimated by 

the commenter). 

Response: The proposed amendments provided limited 

exclusions to the Tier 3 requirement for very small fuel 

gas lines or combustion units that are not equipped with a 

flow meter. As noted in the preamble of the August 11, 

2010, proposed amendments, the exclusion was specifically 

targeted to prevent the need to install flow meters for 

these small fuel gas lines. EPA noted that “[i]f flow 

meters are in place at the process heater or at a common 

pipe location, we consider that the Tier 3 monitoring 

requirements are reasonable and justified.” (See 75 FR 

48772.) The commenter indicated that these gas streams 
Page 192 of 442 

could have a significantly different composition than 

typical refinery fuel gas, which suggests the default fuel 

gas factor would have considerable uncertainty for these 

gas streams, further indicating that Tier 3 sampling is 

necessary. While we recognize that there are inherent 

safety issues with sampling any fuel gas streams, the 

commenter has not provided any supporting information for 

the assertion that sampling these “process off-gas or vent 

gases” is more hazardous than other fuel gas streams at the 

refinery. Therefore, we are not expanding the proposed 

exclusion to the Tier 3 methodology for fuel gas lines that 

have a flow meter already installed in the line or upstream 

common pipe. We also note that today’s final amendments 

are not imposing new requirements to sample these fuel gas 

streams; the October 30, 2009, final Part 98 already 

required these fuel gas streams to be sampled for carbon 

content no less than once per calendar week. 

Comment: One commenter objected to the proposed 

revision of 40 CFR 98.254(f) to also require exhaust gas 

flow meters associated with process vents (i.e., subject to 

40 CFR 98.253(j) requirements) to be installed, operated, 

calibrated and maintained according the Petroleum 

Refineries NESHAP (40 CFR part 63, subpart UUU) 

requirements in 40 CFR 63.1572(c). According to the 
Page 193 of 442 

commenter, the Petroleum Refineries NESHAP requirements in 

40 CFR 63.1572(c) contain provisions that are more 

stringent than the monitoring and QA/QC requirements 

throughout Part 98. For example, 40 CFR 63.1572(c) 

requires each monitoring system to have valid hourly 

average data from at least 75 percent of the hours during 

which the process operated and to complete a minimum of one 

cycle of operation for each successive 15-minute period 

with a minimum of four successive cycles of operation to 

have a valid hour of data (or at least two if a calibration 

check is performed during that hour or if the continuous 

parameter monitoring system is out-of-control). The 

commenter stated that, since the flow monitoring 

requirements for the Petroleum Refineries NESHAP in 40 CFR 

63.1572(c) were established to demonstrate compliance with 

emission limits, they should not be used as a template for 

requirements of flow metering for GHG reporting. The 

commenter recommended that the process vent exhaust flow 

meter requirements should be consistent with the 

requirements in 40 CFR 98.254(c) for flare and sour gas 

flow meters. 

Response: We proposed to include the requirements for 

flow meters used to comply with the 40 CFR 98.253(j) for 

process vents within the monitoring provisions of 40 CFR 
Page 194 of 442 

98.254(f) because these meters are exhaust gas flow meters 

rather than fuel gas flow meters. However, we agree with 

the commenter that the inclusion of flow meters used to 

comply with the 40 CFR 98.253(j) within the monitoring 

provisions of 40 CFR 98.254(f) added new requirements to 

these flow meters. While we believe that the flow meter 

requirements in 40 CFR 63.1572(c) of the Petroleum 

Refineries NESHAP are reasonable requirements for exhaust 

gas flow meters in general (40 CFR 63.1572(c) are 

requirements for parameter monitoring systems, not 

continuous emission monitoring systems), we agree with the 

commenter that it is inappropriate to add these 

requirements to process vent flow meters at this juncture. 

Furthermore, the provisions in 40 CFR 98.253(j) allow use 

of process knowledge or engineering calculations as an 

alternative to direct flow measurement. As such, it is 

incongruous to subject facilities that have flow meters on 

these process vents to additional requirements when 

facilities that do not have flow meters on these process 

vents may use process knowledge or engineering 

calculations. Therefore, we are finalizing requirements 

for flow meters used to comply with 40 CFR 98.253(j) for 

process vents to meet the monitoring provisions of 40 CFR 
Page 195 of 442 

98.254(c) rather than 40 CFR 98.254(f) as was required per 

the October 30, 2009 final Part 98. 

O. Subpart AA - Pulp and Paper Manufacturing

1. Summary of Final Amendments and Major Changes Since 

Proposal.

We are amending 40 CFR 98.273(a)(1), (b)(1) and (c)(1) 

to clarify that owners and operators may choose to use a 

tier other than Tier 1 from 40 CFR 98.33 to calculate 

fossil-fuel based CO2 emissions. 

We have removed the CO2 emission factors from Table AA2 and revised 40 CFR 98.273(c)(1) to direct owners and 

operators to use the CO2 emission factors from Table C-1 of 

subpart C to calculate CO2 emissions from lime kilns. 

With respect to calculating CH4 and N2O emissions from 

fossil fuel combustion at lime kilns, and consistent with 

the amendments to allow use of higher tiers than Tier 1 for 

units subject to subpart AA, we are amending 40 CFR 

98.273(a)(2), (b)(2), and (c)(2) to allow reporters to also 

use site-specific high heating values, as opposed to 

default values, when calculating CH4 and N2O emissions. We 

are making harmonizing amendments to the definition of EF 

under Equation AA-1 to clarify that default or sitespecific emission factors may be used. Similarly, we are 
Page 196 of 442 

amending 40 CFR 98.276(e) to reflect the option to use 

default or site-specific values. 

We are clarifying through this final rule that 

emissions from the combustion of wastewater treatment 

sludge are calculated using the emission factors included 

in Table C-1. We have determined that this sludge falls 

within the definition of “Wood and Wood Residuals” included 

in Table C-1. Therefore, per 40 CFR 98.33(b)(1)(iii), 

emissions from the combustion of this type of sludge may be 

determined using Tier 1 in subpart C. In order to further 

clarify this, we are adding the definition of “Wood and 

Wood Residuals” to 40 CFR 98.6 and including wastewater 

process sludge from paper mills in this definition, as 

further described in Section II.F of this preamble. 

We are adding solid petroleum coke to both Table C-1 

and Table AA-2. We have concluded that it is not necessary 

to have emission factors for petroleum coke specific to 

kraft calciners in Table AA-2 because we do not believe 

that any kraft calciners are combusting this fuel, nor were 

any comments received suggesting this was not the case. 

There were no comments received specifically on 

subpart AA, therefore the amendments are being finalized as 

proposed. 
Page 197 of 442 

P. Subpart NN - Suppliers of Natural Gas and Natural Gas 

Liquids

1. Summary of Final Amendments and Major Changes Since 

Proposal.

Threshold for natural gas local distribution 

companies. We are amending 40 CFR Table A-5 of subpart A 

of 40 CFR part 98 to establish an applicability threshold 

so that only local distribution companies (LDCs) that 

deliver 460,000 thousand standard cubic feet (mscf) or more 

of natural gas per year are subject to the reporting rule. 

No major changes have been made since proposal. 

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 the document, “Response to 

Comments: Revision to Certain Provisions of the Mandatory 

Reporting of Greenhouse Gases Rule” (see EPA-HQ-OAR-2008-

0508). 

Comment: Two commenters requested that EPA apply the 

460,000 thousand standard cubic feet (mscf) applicability 

threshold throughout 40 CFR part 98 wherever a threshold is 

expressed in mtCO2e. Specifically, they contended that 40 

CFR 98.2(i)(1) and (2) should be changed to allow LDCs to 
Page 198 of 442 

stop reporting if they deliver less than 460 million cubic 

feet (mmcf) for 5 consecutive years or less than 276 mmcf 

for 3 consecutive years (25,000 mtCO2e is approximately 

equivalent to the CO2 emissions from the combustion of 460 

mmcf of natural gas and 15,000 mtCO2e is approximately 

equivalent to 276 mmcf of natural gas). The commenters 

urged EPA to clarify that the threshold for natural gas 

distributors (460,000 mscf) is equivalent to the threshold 

of 25,000 mtCO2e wherever that metric ton threshold appears 

in the rule. 

Response: EPA has finalized an applicability 

threshold for LDCs of 460,000 mscf or more of natural gas 

delivered per year. As noted by the commenters, we decided 

that it would be easier for LDCs to determine whether or 

not they were above a reporting threshold expressed in mscf 

than if that threshold were expressed in metric tons of 

carbon dioxide equivalent for the first year of this 

reporting program. 

However, we have not changed the conditions for 

ceasing reporting. In the 2009 final rule, 40 CFR 98.2(i) 

states, “Except as provided in this paragraph, once a 

facility or supplier is subject to the requirements of this 

part, the owner or operator must continue for each year 

thereafter to comply with all requirements of this part, 
Page 199 of 442 

including the requirement to submit annual GHG reports, 

even if the facility or supplier does not meet the 

applicability requirements in paragraph (a) of this section 

in a future year.” As noted by the commenter, facilities 

and suppliers can cease reporting when reported emissions 

are below 25,000 mtCO2e for five consecutive years or below 

15,000 mtCO2e for three consecutive years, as specified in 

40 CFR 98.2(i)(1) and (i)(2), respectively. It is clear in 

the final rule that other than these two exceptions, a 

facility or supplier must continue to report even if the 

facility or supplier no longer meets the threshold for 

reporting 

EPA has concluded that applying a consistent 

threshold, expressed in mtCO2e, in 98.2(i)(1) and 98.2(i)(2) 

for all reporters levels the playing field for all 

reporters and is most logical. EPA does not intend to 

provide equivalent thresholds under 40 CFR 98.2(i) for 

various categories because it becomes too cumbersome. LDCs 

are required to report, under 40 CFR 98.406(b)(8), the 

total annual CO2 mass emissions that would result from 

complete combustion of the natural gas delivered to endusers. By performing this required calculation, LDCs have 

the necessary data to determine whether they may cease 

reporting. 
Page 200 of 442 

Q. Subpart OO - Suppliers of Industrial Greenhouse Gases

1. Summary of Final Amendments and Major Changes Since 

Proposal.

We are making several changes to subpart OO to respond 

to concerns raised by producers of fluorinated GHGs 

regarding the scope of the monitoring and reporting 

requirements, and clarify the scope and due dates for 

certain reporting and recordkeeping requirements. 

Producers of fluorinated GHGs requested that EPA 

clarify that subpart OO does not apply to fluorinated GHGs 

that are either emitted or destroyed at the facility before 

the fluorinated GHG product is packaged for sale or for 

shipment to another facility for destruction; are produced 

and transformed at the same facility; or occur as lowconcentration constituents (e.g., impurities) in 

fluorinated GHG products. The producers also requested 

that EPA amend the rule to account for the fact that some 

fluorinated GHGs do not have global warming potential 

values (GWPs) listed in Table A-1 of subpart A. For 

fluorinated GHGs without GWPs in Table A-1, facilities 

cannot calculate CO2-equivalent production as required by 

subpart A, and importers and exporters cannot take 

advantage of the reporting exemptions for small shipments 
Page 201 of 442 

under 40 CFR 98.416(c) and (d), which are expressed in CO2-

equivalents. 

In response to the concern regarding fluorinated GHGs 

that are emitted or destroyed before the product is 

packaged for sale, we are amending the definition of 

“produce a fluorinated GHG” at 40 CFR 98.410(b) to 

explicitly exclude the “creation of fluorinated GHGs that 

are released or destroyed at the production facility before 

the production measurement at §98.414(a).” We are also 

removing the requirements at 40 CFR 98.414(j) and 

98.416(a)(4) to monitor and report the destruction of 

fluorinated GHGs “that are not included in the calculation 

of the mass produced in §98.413(a) because they are removed 

from the production process as by-products or wastes.” 

Finally, we are modifying the requirements at 40 CFR 

98.414(h), 98.416(a)(3), and 98.416(a)(11) to limit them to 

the mass of each fluorinated GHG that is fed into the 

destruction device (or “destroyed” in the case of 40 CFR 

98.416(a)(3)) and that was previously produced as defined 

at 40 CFR 98.410(b). 

These amendments will clarify that the scope of 

subpart OO is that which EPA has always intended, and they 

will modify the destruction monitoring and reporting 

requirements to be fully consistent with that scope. As 
Page 202 of 442 

noted in the preamble to the final Part 98 (74 FR 56259), 

and in the response to comments document, the intent of 

subpart OO is to track the quantities of fluorinated GHGs 

entering and leaving the U.S. supply of fluorinated GHGs. 

Specifically, subpart OO is intended to address production 

of fluorinated GHGs, not emissions or destruction of 

fluorinated GHGs that occur during the production process. 

As noted in the proposed Part 98 (74 FR 16580), the 

production measurement at 40 CFR 98.414(a) could occur 

wherever it traditionally occurs, e.g., at the inlet to the 

day tank or at the shipping dock, as long as the subpart OO 

monitoring requirements were met (e.g., one-percent 

precision and accuracy for the mass produced and for 

container heels, if applicable). Emissions upstream of the 

production measurement will be subject to the recently 

promulgated subpart L, which was signed by EPA 

Administrator Lisa Jackson on November 8, 2010 and are not 

part of the subpart OO source category. 

We are also amending 40 CFR 98.416(a)(3) and (a)(11) 

to limit the monitoring and reporting of destroyed 

fluorinated GHGs to those destroyed fluorinated GHGs that 

were previously “produced” under today’s revised 
Page 203 of 442 

definition.6 Such fluorinated GHGs include but are not 

limited to quantities that are shipped to the facility by 

another facility for destruction, and quantities that are 

returned to the facility for reclamation but are found to 

be irretrievably contaminated. While monitoring of some 

destroyed streams appears to pose significant technical 

challenges,7 monitoring of quantities of fluorinated GHGs 

that were previously produced does not. These quantities 

can be weighed and analyzed by the facility upon receipt or 

upon the facility’s conclusion that they cannot be brought 

back to the specifications for new or reusable product. 

In response to the concern regarding fluorinated GHGs 

that are produced and transformed at the same facility, we 

are amending the definition of “produce a fluorinated GHG” 

to exclude “the creation of intermediates that are created 

 

6 In Part 98, EPA required the monitoring of all streams being destroyed 

because it was our understanding, based on conversations with 

fluorinated GHG producers, that the mass flow of destroyed fluorinated 

GHG streams was routinely monitored. To arrive at the quantities being 

removed from the supply, EPA required facilities to estimate the share 

of the total quantity of fluorinated GHGs destroyed that consisted of 

fluorinated GHGs that were not included in the calculation of the mass 

produced. This share could then be subtracted from the total to arrive 

at the amounts destroyed that were removed from the supply. In other 

words, monitoring and reporting of the destruction of fluorinated GHGs 

that were not included in the mass produced was required in order to 

estimate the destruction of fluorinated GHGs that had been produced. 

7 These include (1) low-pressure conditions that make it challenging to 

achieve good accuracies and precisions and under which the installation 

of a flowmeter may lead to low- or no-flow conditions, interfering with 

operations upstream of the meter, (2) corrosive conditions that require 

the use of Tefzel-lined flow meters, which are currently available in a 

limited range of sizes and precisions, and (3) variations in stream 

flow rates and compositions that are associated with purging of vessels 

and columns and that make it difficult to select a meter that will 

measure the full range of flows to the required accuracy and precision. 
Page 204 of 442 

and transformed in a single process with no storage of the 

intermediates.” We are also amending the definition of 

“produce a fluorinated GHG” in 40 CFR 98.410(b) to 

explicitly include “the manufacture of a fluorinated GHG as 

an isolated intermediate for use in a process that will 

result in its transformation either at or outside of the 

production facility.” We are also adding a definition of 

“isolated intermediate” to 40 CFR 98.418. Finally, we are 

adding provisions to 40 CFR 98.414, 98.416, and 98.417 to 

clarify that isolated intermediates that are produced and 

transformed at the same facility are exempt from subpart OO 

monitoring, reporting, and recordkeeping requirements 

respectively. 

As noted by the producers, fluorinated GHGs that are 

produced and transformed at the same facility never enter 

the U.S. supply of industrial greenhouse gases; thus, they 

do not need to be reported under subpart OO. This is true 

both of isolated intermediates and of intermediates that 

are created and transformed in a single process with no 

storage of the intermediate. However, while we are 

excluding the latter from the definition of “produce a 

fluorinated GHG,” we are including the former in that 

definition. This is because the manufacture of isolated 

intermediates, which can lead to emissions of those 
Page 205 of 442 

intermediates, will be of interest under the recently 

promulgated subpart L and it is desirable to use the same 

definition of “produce a fluorinated GHG” for subpart L as 

for subpart OO for consistency and clarity. Thus, instead 

of excluding the manufacture of isolated intermediates that 

are transformed at the same facility from the definition of 

“produce a fluorinated GHG,” we are adding provisions to 

exclude it from the subpart OO monitoring, reporting, and 

recordkeeping requirements. We are also adding a 

definition of “isolated intermediate” that is the same as 

that for the recently promulgated subpart L. 

In response to the concern regarding fluorinated GHGs 

that occur as low-concentration constituents of fluorinated 

GHG products, we are defining and excluding lowconcentration constituents from the monitoring, reporting, 

and recordkeeping requirements for fluorinated GHG 

production, exports, and imports. For purposes of 

production and export, we are defining a low-concentration 

constituent in 40 CFR 98.418 as a fluorinated GHG 

constituent of a fluorinated GHG product that occurs in the 

product in concentrations below 0.1 percent by mass. This 

concentration is the same as that used in the definition of 

“trace concentration” used elsewhere in subpart OO. It is 

also consistent with industry purity standards for HFC 
Page 206 of 442 

refrigerants (Air-Conditioning, Heating, and Refrigeration 

Institute (AHRI) 700), for SF6 used as an insulator in 

electrical equipment (International Electrotechnical 

Commission (IEC) 60376), and for perfluorocarbons and other 

fluorinated GHGs used in electronics manufacturing 

(Semiconductor Equipment and Materials International (SEMI) 

C3 series). To meet these standards, which set limits that 

range from less than 0.1 percent to 0.5 percent for all 

fluorinated GHG impurities combined, fluorinated GHG 

producers are likely to have identified and quantified the 

concentrations of impurities at concentrations at or above 

0.1 percent for the products subject to the standards. 

Finally, below concentrations of 0.1 percent, fluorinated 

GHG impurities are not likely to have a significant impact 

on the GWP of the product. For example, if a lowconcentration constituent occurs in concentrations of just 

less than 0.1 percent and has a GWP that is ten times as 

large as the GWP of the main constituent of the product, it 

will increase the weighted GWP of the product by just less 

than one percent. 

To ensure that fluorinated GHG production facilities 

rely on data of known and acceptable quality when 

determining whether or not to report a minor fluorinated 

GHG constituent of a product, we are adding product 
Page 207 of 442 

sampling and analytical requirements at 40 CFR 98.414(n), 

corresponding calibration requirements at 40 CFR 98.414(o), 

and a corresponding reporting requirement at 40 CFR 

98.416(f). We are also clarifying in 40 CFR 98.414(a) how 

to calculate production of each fluorinated GHG constituent 

of a product. 

For purposes of fluorinated GHG imports, we are 

defining a “low-concentration constituent” in 40 CFR 98.418 

as a fluorinated GHG constituent of a fluorinated GHG 

product that occurs in the product in concentrations below 

0.5 percent by mass. We are defining a higher 

concentration for fluorinated GHG imports than for 

fluorinated GHG production and exports because importers 

are less likely than producers to have detailed information 

on the identities and concentrations of minor fluorinated 

GHG constituents in their products. 

In response to the concerns regarding fluorinated GHGs 

that do not have GWPs listed in Table A-1, we are amending 

subpart A to exempt such compounds from the general subpart 

A requirement to report supply flows in terms of CO2

equivalents and revising the reporting exemptions for 

import and export of small shipments to be in terms of 

kilograms of fluorinated GHGs or N2O, rather than tons of 

CO2-equivalents. The amendment to subpart A is discussed in 
Page 208 of 442 

more detail in Section II.F of this preamble. The 

exemptions for import and export will be applied to 

shipments of less than 25 kilograms of fluorinated GHGs or 

N2O rather than to shipments of less than 250 metric tons of 

CO2e. This will enable small shipments of fluorinated GHGs 

to be exempt from reporting regardless of whether or not 

the fluorinated GHG has a GWP listed in Table A-1. 

Other corrections. We are also amending the reporting 

and recordkeeping provisions in subpart OO to clarify those 

requirements and to correct internal inconsistencies in the 

subpart. 

We are amending the reporting requirements in 40 CFR 

98.416(a)(15) and (c)(10) to remove N2O from the list of 

GHGs that must be reported when they are transferred off 

site for destruction, because N2O transferred off site for 

destruction is not required to be monitored. 

We are amending 40 CFR 98.416(b) and (e) to clarify 

the due dates of the one-time reports required by those 

paragraphs. The due date for the one-time reports is March 

31, 2011, or within 60 days of commencing fluorinated GHG 

destruction or production (as applicable). The due date in 

40 CFR 98.416(e) in subpart OO was originally April 1, 

2011, and there was no provision for fluorinated GHG 

destruction or production commenced after that date. 
Page 209 of 442 

We are amending the recordkeeping requirements in 40 

CFR 98.417(a)(2) to correct and update an internal 

reference. The correct reference is to “§98.414(m) and 

(o),” instead of “§98.417(j) and (k).” We are amending 40 

CFR 98.417(b) to remove the reference to the “annual 

destruction device outlet reports” in 40 CFR 98.416(e) 

since no such reporting requirement exists. 

Finally, we are amending 40 CFR 98.417(d)(2) to 

correct a typographical error; that paragraph should refer 

to “the invoice for the export,” rather than for the 

“import.” 

EPA is making one clarifying editorial change in the 

final rule amendments that was not in the proposed 

amendments. As discussed above and in the preamble to the 

proposed amendments, 40 CFR 98.414(h) requires facilities 

to measure the mass of each fluorinated GHG that is fed 

into the destruction device and that was previously 

produced. If the mass being fed into the destruction 

device includes more than trace concentrations of materials 

other than the fluorinated GHG being destroyed, facilities 

must estimate the concentrations of the fluorinated GHGs 

being destroyed. They must then multiply these 

concentrations by the mass measurement to obtain the mass 

of the fluorinated GHGs fed into the destruction device. 
Page 210 of 442 

In the proposed paragraph (h), the final sentence read, 

“You must multiply this concentration (mass fraction) by 

the mass measurement to obtain the mass of the fluorinated 

GHG destroyed.” To be consistent with the beginning of the 

paragraph and to be mathematically correct, this sentence 

has been corrected in the final rule to read, “You must 

multiply this concentration (mass fraction) by the mass 

measurement to obtain the mass of the fluorinated GHG fed 

into the destruction device.” As specified in Equation OO4 of 40 CFR 98.413(d), the mass of the fluorinated GHG 

destroyed is obtained by multiplying the mass of the 

fluorinated GHG fed into the destruction device by the 

destruction efficiency of the destruction device. 

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 the document, “Response to 

Comments: Revision to Certain Provisions of the Mandatory 

Reporting of Greenhouse Gases Rule” (see EPA-HQ-OAR-2008-

0508). 

Comment: Two commenters expressed concerns that 

exempting low-concentration constituents of products from 

monitoring and reporting would exempt a significant amount 
Page 211 of 442 

of emissions from reporting. These commenters requested 

additional information on the GWPs of these lowconcentration constituents and on the emissions affected by 

the exemption. 

Response: We analyzed the potential impact of lowconcentration constituents on the total calculated flows of 

fluorinated GHGs into the U.S. economy, considering both 

the possible masses of the low-concentration constituents 

and their CO2-equivalents. We concluded that at a level of 

0.1 percent of production and 0.5 percent of imports, 

identification of such constituents would have a negligible 

impact on the total calculated flows of fluorinated GHGs 

into the U.S. supply. It is important to note that, under 

the exemption for low-concentration constituents, the 

masses and CO2e of low-concentration constituents are not 

equated to zero. Instead, the mass of the lowconcentration constituent is assigned to the main 

constituent of the product, and the GWP is assumed to be 

that of the main constituent of the product. Only if the 

GWP or atmospheric lifetime of the low-concentration 

constituent is significantly higher than that of the main 

constituent is there a potential concern associated with 

these assumptions. 
Page 212 of 442 

As noted in the preamble to the proposed rule, lowconcentration constituents are generally by-products of the 

reaction used to produce the fluorinated GHG product. 

Although we do not have information on every product and 

by-product combination, we believe, based on the examples 

of which we are aware, that by-products rarely have GWPs 

that are more than ten times as large as that of the 

product. We analyzed the potential impact of a by-product 

that had ten times the GWP of the product on the weighted 

GWP of the combination of the two. At a concentration of 

0.1 percent, the by-product would raise the weighted GWP 

(and CO2e) above that of the product by just under one 

percent. Given that the impacts of most low-concentration 

constituents are likely to fall below this level, we do not 

consider them significant. 

We also performed an analysis in which we 

conservatively assumed that every HFC, PFC, and SF6 product 

had a PFC by-product that was shipped along with it at a 

concentration of 0.1 percent. This was intended to address 

the possibility that low-concentration constituents had 

very long atmospheric lifetimes. Based on this worst-case 

assumption, the quantity of PFCs flowing into the U.S. 

fluorinated GHG supply was increased by less than 10 

percent. It is extremely unlikely that every HFC, PFC, and 
Page 213 of 442 

SF6 product has a PFC by-product; in fact, the highestvolume products, the HFCs, are unlikely to have PFC byproducts. Therefore, in consideration of this analysis and 

the GWP analysis, we have concluded that the exemption for 

low-concentration constituents is very unlikely to lead to 

significant errors in our understanding of potential 

emissions of fluorinated GHGs from the U.S. supply. 

Comment: Two commenters expressed concerns regarding 

the proposal to exclude from subpart OO fluorinated GHGs 

that are emitted or destroyed before the fluorinated 

product is packaged for sale. They requested that EPA 

ensure that these emissions were fully captured under the 

reporting rule (e.g., subpart L) and requested that EPA 

document the magnitude of these emissions and the 

identities and GWPs of the compounds emitted. 

Response: As proposed, we are excluding from the 

definition of “produce a fluorinated GHG” the creation of 

fluorinated GHGs that are released or destroyed at the 

production facility before the production measurement. As 

discussed in the preamble to the proposed amendments, such 

fluorinated GHGs never enter the U.S. supply of fluorinated 

GHGs, and the goal of subpart OO is to monitor fluorinated 

GHG flows into and out of this supply. However, the 

recently promulgated subpart L requires monitoring and 
Page 214 of 442 

reporting of emissions that occur before the production 

measurement. We have worked to ensure that no fluorinated 

GHG emissions from fluorinated GHG production are “missed” 

under the combined oversight of these two subparts. The 

magnitudes, identities, and GWPs of the emissions that will 

be reported under subpart L of 40 CFR part 98 are discussed 

in the preamble to the proposed rule including subpart L 

(75 FR 18652, April 12, 2010) and in the Technical Support 

Document for subpart L.

R. Subpart PP - Suppliers of Carbon Dioxide

1. Summary of Final Amendments and Major Changes Since 

Proposal.

We are removing the words “each” from 40 CFR 98.422(a) 

and (b). This change will align this section with the 

requirements of the rest of subpart PP, which allow for 

monitoring of an aggregated flow of CO2, versus monitoring 

at each production well or process unit, if the monitoring 

is done at a gathering point downstream of individual 

production wells or production process units. 

We are allowing suppliers to calculate the annual mass 

of CO2 supplied in containers by using weigh bills, scales, 

load cells, or loaded container volume readings as an 

alternative to flow meters. We are making multiple 

amendments to the regulatory text to accommodate this 
Page 215 of 442 

provision. First, we are redesignating 40 CFR 98.423(b) as 

40 CFR 98.423(c) and adding a new 40 CFR 98.423(b) with 

calculation procedures for CO2 supplied in containers. 

Second, we are amending the first sentence of 40 CFR 

98.423(a) to allow use of the alternative procedures in 40 

CFR 98.423(b). Third, we are adding new QA/QC procedures 

for suppliers of CO2 in containers to 40 CFR 98.424(a)(2). 

Fourth, we are adding missing data procedures for suppliers 

of CO2 in containers to 40 CFR 98.425(d) and specifying that 

the missing data procedures in 40 CFR 98.425(a) are for 

suppliers using flow meters. Finally, we are making 

multiple amendments to regulatory text in 40 CFR 98.426 so 

that all data collected with weigh bills, scales, load 

cells, or loaded container volume readings must be reported 

just as for all data collected with flow meters. 

We are removing the requirement that CO2 measurement 

must be made prior to subsequent purification, processing, 

or compression at 40 CFR 98.423(a)(1), (a)(2), and (b) 

(which we are redesignating as 40 CFR 98.423(c)). Because 

the purpose of subpart PP is to collect accurate data on CO2

supplied to the economy, we have concluded that 

measurements made after purification, compression, or 

processing will continue to meet the level of data quality 

and accuracy needed with respect to subpart PP, while 
Page 216 of 442 

minimizing the burden on industry and providing greater 

flexibility in measuring CO2 streams. 

To ensure that all reporters account for the 

appropriate quantity of CO2 in situations where a CO2 stream 

is segregated such that only a portion is captured for 

commercial application or for injection and where a flow 

meter is used, we are making a number of amendments. 

First, we are adding language at 40 CFR 98.424(a) regarding 

flow meter location. Reporters who have a flow meter(s) on 

the main, captured CO2 stream(s) only must locate the flow 

meter(s) after the point(s) of segregation. Reporters who 

have a flow meter(s) on the main, captured CO2 stream and a 

subsequent flow meter(s) on the CO2 stream(s) diverted for 

on-site use and who choose to use the subsequent flow 

meter(s) to calculate CO2 supply (i.e. the two meter method) 

must locate the main flow meter(s) prior to the point(s) of 

segregation and the subsequent flow meter(s) on the CO2

stream(s) for on-site use after the point(s) of 

segregation. We are also amending existing language in 40 

CFR 98.424(a) to reference this new requirement. Second, 

we are amending 40 CFR 98.423(a)(3) to provide reporters 

using the two meter approach a new equation (Equation PP3b) to calculate total CO2 supplied. As a harmonizing 

change, we are redesignating Equation PP-3 as Equation PP-
Page 217 of 442 

3a. Third, we are amending 40 CFR 98.426(c) so that 

reporters using the new Equation PP-3b are required to 

report the equation inputs and output and the location of 

flow meters with respect to the point of segregation.. 

Because the amendments will allow flow meters to be 

located after purification, compression, or processing, we 

are adding data reporting requirements in 40 CFR 98.426 to 

collect additional information on flow meter location. 

Specifically, we are adding that facilities will report 

information on the placement of each flow meter used in 

relation to the points of CO2 stream capture, dehydration, 

compression, and other processing. Knowing where in the 

production process the flow meter is located will enable 

EPA to effectively compare data across reporters and learn 

about the efficacy of various CO2 stream capture processes. 

We are specifying standard conditions under subpart PP 

as a temperature and an absolute pressure of 60°F and 1 

atmosphere. It is our understanding that 60°F and 1 

atmosphere (which is equivalent to 14.7 psia) are more 

commonly used by the industries covered by subpart PP. 

We are making several amendments to allow the reporter 

to determine the mass of a CO2 stream by converting the 

volumetric flow of the CO2 stream from operating conditions 

to standard conditions and then applying the density value 
Page 218 of 442 

for CO2 at standard conditions and the measured 

concentration of CO2 in the flow as a volume percent. 

First, we are specifying that, at the revised standard 

conditions, the density of CO2 is 0.001868 metric tons per 

standard cubic meter. This is slightly different than the 

density value proposed (0.018704) as the result of 

additional research we have conducted. We are specifying 

that a reporter who applies the density value for CO2 at 

standard conditions must use this specified value. 

Second, we are revising the definitions of two of the 

input variables to Equation PP-2 in paragraph (a)(2). 

Since it was finalized (74 FR 56260, October 30, 2009), 

Equation PP-2 allows a reporter to calculate annual mass of 

CO2 with an input for CO2 concentration in weight percent

and an input for density of the CO2 stream. So that 

reporters can avail themselves of the density value for CO2

being finalized in this action, however, Equation PP-2 can 

now also be used to calculate annual mass of CO2 with an 

input for CO2 concentration in volume percent and an input 

for density of CO2. We note that when we proposed this 

action, we did not propose to revise the definitions of the 

input variables because we erroneously overlooked the 

mismatch between the density value we were providing (CO2) 

and the density value required by Equation PP-2 (the CO2
Page 219 of 442 

stream). In order to provide all reporters with lower 

burden calculation procedures, as intended by proposing a 

density value for CO2, we are correcting this omission and 

harmonizing Equation PP-2 with the finalized density value. 

We note that the revision to the two input variables is 

being applied for both reporters using flow meters and 

reporters using containers. 

Third, we are amending 40 CFR 98.426(b)(3) and (b)(4) 

to require that for volumetric flow meters, the reporter 

must report quarterly concentration either in volume or 

weight percent and a density value for either CO2 or the CO2

stream, depending on which of the two equation input 

descriptions provided the reporter uses. 

Fourth, we are amending language in 40 CFR 

98.424(a)(5), (a)(5)(i) and (a)(5)(ii) to allow reporters 

to choose either a method published by a consensus-based 

standards organization or an industry standard practice to 

determine the density of the CO2 stream. We are also 

replacing the word “measure” with the word “determine.” 

Previously, subpart PP required a reporter to use an 

appropriate method published by a consensus-based standards 

organization to measure density for CO2 at standard 

conditions, if such a method existed. Only where no such 

method existed could an industry standard practice be used. 
Page 220 of 442 

However, we have been unable to identify any method 

published by a consensus-based standards organization for 

measuring the density of the CO2 stream. Therefore, we are 

providing reporters with more flexibility on this 

requirement so that they can use an industry standard 

practice to calculate the density of the CO2 stream rather 

than directly measure density with an instrument, if 

preferred. 

Finally, we are amending the reference to the U.S. 

Food and Drug Administration food-grade specifications for 

CO2 in 40 CFR 98.424(b)(2) to correct a typographical error. 

The correct reference is 21 CFR 184.1240, not 21 CFR 

184.1250.

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 

document, “Response to Comments: Revision to Certain 

Provisions of the Mandatory Reporting of Greenhouse Gases 

Rule” (see EPA-HQ-OAR-2008-0508). 

• We are adding a second aggregation equation (Equation 

PP-3b) with appropriate flow meter location 

requirements so that a reporter can select either the 

one-meter or two-meter approach for calculating total 

annual mass of CO2. 

• We are revising the definitions of two of the input 

variables to Equation PP-2 in paragraphs 40 CFR 

98.423(a)(2) and (b)(2) so that the equation can be 
Page 221 of 442 

used to calculate annual mass of CO2 with an input for 

CO2 concentration in either volume percent and an input 

for density of CO2, or weight percent CO2 and the 

density of the whole stream. 

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 the document, “Response to 

Comments: Revision to Certain Provisions of the Mandatory 

Reporting of Greenhouse Gases Rule” (see EPA-HQ-OAR-2008-

0508). 

Comment: One commenter asserted that one of their 

facilities has already installed a CO2 meter prior to 

purification, processing, or compression – as was required 

by 40 CFR 98.424 when Part 98 was finalized (74 FR 56260, 

October 30, 2009) – and because this facility has 

segregation, this results in a flow meter location prior to 

segregation. The commenter suggested that this facility 

and others like it should be allowed to keep their flow 

meters in place rather than be required to move them to a 

location after segregation, as was proposed in the 

amendments of August 11, 2010. The commenter suggested a 

two-meter approach, whereby a facility locates a main flow 

meter prior to segregation on the main, captured CO2 stream 

and a subsequent flow meter after segregation on the 
Page 222 of 442 

diverted CO2 stream and then calculates the CO2 for off-site 

commercial use as the difference between the two. The 

commenter stated that this two-meter approach should be 

equally acceptable to the approach proposed. 

Response: EPA agrees that a reporter can calculate CO2

supplied for commercial transaction or injection with 

sufficient accuracy with the two-meter approach suggested 

by the commenter, as long as the CO2 stream diverted for on 

site use is the only CO2 stream diversion after the location 

of the main flow meter. If any of the main CO2 stream 

remaining after on-site diversion is further diverted (to a 

vent for emission, for example) then the difference between 

the captured CO2 stream and the CO2 stream diverted for onsite use will not be an accurate reflection of the CO2

supplied for commercial transaction or injection. 

Therefore, EPA is finalizing two approaches for calculating 

CO2 supplied, including aggregation equations with flow 

meter location requirements, so that a reporter can select 

either the one-meter or two-meter approach. However, we 

are specifying in the monitoring and QA/QC requirements (40 

CFR 98.424) that a reporter may only follow the two-meter 

approach if the CO2 stream(s) for on-site use is/are the 

only diversion(s) from the main, captured CO2 stream after 

the main flow meter(s) location. 
Page 223 of 442 

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 

substantive changes to the reporting requirements in any of 

the amended subparts. In many cases, the amendments to the 

reporting requirements reduce the reporting burden by 

making the reporting requirements conform more closely to 

current industry practices. While the final rule results 

in a net decrease in collection burden, there a new 

reporting requirement for facilities with part 75 units. 

Previously, facilities with these units had the option of 

reporting biogenic CO2 emissions separately. This final 

rule requires separate reporting of biogenic CO2 emissions 

beginning in 2011; however facilities may use simplified 

methods based on available information. 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 
Page 224 of 442 

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 Revisions Cost Memo (EPA-HQOAR-2008-0508). 

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 
Page 225 of 442 

governmental jurisdiction that is a government of a city, 

county, town, school district or special district with a 

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

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

independently owned and operated and is not dominant in its 

field. 

After considering the economic impacts of these rule 

amendments on small entities, I certify that this action 

will not have a significant economic impact on a 

substantial number of small entities. 

The rule amendments will not impose any new 

significant requirements on small entities that are not 

currently required by the rules promulgated on October 30, 

2009 (i.e., calculating and reporting annual GHG 

emissions). 

Broadly, in developing the 2009 final rule 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 
Page 226 of 442 

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 the 

rule 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 section 

203 of the UMRA. 

E. Executive Order 13132: Federalism
Page 227 of 442 

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 preamble for the proposed GHG reporting rule (74 FR 

16457 to 16461, April 10, 2009). 

These amendments apply directly to facilities that 

supply fuel that when used emit greenhouse gases or 

facilities that directly emit greenhouses gases. They do 

not apply to governmental entities unless the government 

entity owns a facility that directly emits greenhouse gases 

above threshold levels (such as a landfill or stationary 

combustion source), 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 
Page 228 of 442 

in developing the 2009 final rule. A summary of EPA’s 

consultations with State and local governments is provided 

in Section VIII.E of the preamble to the 2009 final rule 

(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 final 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 
Page 229 of 442 

analysis required under section 5-501 of the Executive 

Order has the potential to influence the regulation. This 

action is not subject to Executive Order 13045 because it 

does not establish an environmental standard intended to 

mitigate health or safety risks. 

H. Executive Order 13211: Actions that Significantly 

Affect Energy Supply, Distribution, or Use

This action is not subject to Executive Order 13211 

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

significant regulatory action under Executive Order 12866. 

I. National Technology Transfer and Advancement Act

Section 12(d) of the National Technology Transfer and 

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

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

standards in its regulatory activities unless to do so 

would be inconsistent with applicable law or otherwise 

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. 
Page 230 of 442 

This rulemaking involves the use of two new voluntary 

consensus standards from ASTM International. Specifically, 

EPA will allow facilities in the petroleum refining and 

petrochemical production industries to use ASTM D2593-

93(2009) Standard Test Method for Butadiene Purity and 

Hydrocarbon Impurities by Gas Chromatography, and ASTM 

D7633-10 Standard Test Method for Carbon Black—Carbon 

Content, in addition to the methods incorporated by 

reference in Part 98. These additional voluntary consensus 

standards will provide alternative method that owners or 

operators in these industries can use to monitor GHG 

emissions. 

This rulemaking also involves the use of several 

standard methods that are in EPA publications. These 

include the following: 

• Protocol for Measurement of Tetrafluoromethane (CF4) 

and Hexafluoroethane (C2F6) Emissions from Primary 

Aluminum Production (April 2008); IBR approved for 40 

CFR 98.64(a). 

• AP 42, Section 5.2, Transportation and Marketing of 

Petroleum Liquids, July 2008,(AP 42, Section 5.2); 

http://www.epa.gov/ttn/chief/ap42/ch05/final/c05s02.pd

f; in Chapter 5, Petroleum Industry, of AP 42, 

Compilation of Air Pollutant Emission Factors, 5th 

Edition, Volume I; IBR approved for 40 CFR 98.253(n). 

• AP 42, Section 7.1, Organic Liquid Storage Tanks, 

November 2006 (AP 42, Section 7.1), 

http://www.epa.gov/ttn/chief/ap42/ch07/final/c07s01.pd

f; in Chapter 7, Liquid Storage Tanks, of AP 42, 

Compilation of Air Pollutant Emission Factors, 5th 
Page 231 of 442 

Edition, Volume 1; IBR approved for 40 CFR 

98.243(m)(1) and 40 CFR 98.256(o)(2)(i). 

• Method 8015C, Nonhalogenated Organics By Gas 

Chromatography, Revision 3, February 2007 (Method 

8015C), 

http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/8

015c.pdf; in EPA Publication No. SW-846, “Test Methods 

for Evaluating Solid Waste, Physical/Chemical 

Methods,” Third Edition; IBR approved for 40 CFR 

98.244(b)(4)(viii). 

• Method 8021B, Aromatic And Halogenated Volatiles By 

Gas Chromatography Using Photoionization And/Or 

Electrolytic Conductivity Detectors, Revision 2, 

December 1996 (Method 8021B ). 

http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/8

021b.pdf; in EPA Publication No. SW-846, “Test Methods 

for Evaluating Solid Waste, Physical/Chemical 

Methods,” Third Edition; IBR approved for 40 CFR 

98.244(b)(4)(viii). 

• Method 8031, Acrylonitrile By Gas Chromatography, 

Revision 0, September 1994 (Method 8031), 

http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/8

031.pdf; in EPA Publication No. SW-846, “Test Methods 

for Evaluating Solid Waste, Physical/Chemical 

Methods,” Third Edition; IBR approved for 40 CFR 

98.244(b)(4)(viii). 

• Method 9060A, Total Organic Carbon, Revision 1, 

November 2004 (Method 9060A), 

http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/9

060a.pdf; in EPA Publication No. SW-846, “Test Methods 

for Evaluating Solid Waste, Physical/Chemical 

Methods,” Third Edition; IBR approved for 40 CFR 

98.244(b)(4)(viii). 

These methods are being added by the final rule 

amendments as a result of working with affected industries 

to identify existing methods that can be used to provide 

the data needed to calculate GHG emissions, proposing the 

addition of the methods, and considering the public 
Page 232 of 442 

comments on the addition of the methods in the final rule 

making. 

No new test methods were developed for this action. 

J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and LowIncome Populations

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

establishes federal executive policy on environmental 

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
Page 233 of 442 

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 December 

31, 2010. 
Mandatory Reporting of Greenhouse Gases 

Page 234 of 442 

List of Subjects 

Environmental protection, Administrative practice and 

procedure, Greenhouse gases, Incorporation by reference, 

Suppliers, Reporting and recordkeeping requirements. 

Date: 

Lisa P. Jackson, 

Administrator.
Page 235 of 442 

For the reasons stated in the preamble, title 40, 

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

follows: 

Part 98—[AMENDED] 

1. The authority citation for part 98 continues to 

read as follows: 

Authority: 42 U.S.C. 7401-7671q. 

Subpart A—[Amended] 

2. Section 98.3 is amended by: 

a. Revising paragraphs (c)(1), (c)(4) introductory 

text, (c)(4)(i), (c)(4)(ii), and (c)(4)(iii) introductory 

text. 

b. Adding paragraph (c)(4)(vi). 

c. Revising paragraph (c)(5)(i). 

d. Adding paragraph (c)(12). 

e. Revising the third sentence of paragraph (d)(3) 

introductory text. 

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

g. Revising paragraphs (g)(4) and (g)(5)(iii). 

h. Revising paragraph (h). 

i. Revising paragraph (i). 

j. Adding paragraph (j). 

§98.3 What are the general monitoring, reporting, 

recordkeeping and verification requirements of this part?
Page 236 of 442 

* * * * * 

(c) * * * 

(1) Facility name or supplier name (as appropriate), 

and physical street address of the facility or supplier, 

including the city, State, and zip code. 

* * * * * 

(4) For facilities, except as otherwise provided in 

paragraph (c)(12) of this section, report annual emissions 

of CO2, CH4, N2O, and each fluorinated GHG (as defined in 

§98.6) as follows. 

(i) Annual emissions (excluding biogenic CO2) 

aggregated for all GHG from all applicable source 

categories, expressed in metric tons of CO2e calculated 

using Equation A-1 of this subpart. 

(ii) Annual emissions of biogenic CO2 aggregated for 

all applicable source categories, expressed in metric tons. 

(iii) Annual emissions from each applicable source 

category, expressed in metric tons of each applicable GHG 

listed in paragraphs (c)(4)(iii)(A) through (c)(4)(iii)(E) 

of this section. 

* * * * * 

(vi) Applicable source categories means stationary 

fuel combustion sources (subpart C of this part), 

miscellaneous use of carbonates (subpart U of this part), 
Page 237 of 442 

and all of the source categories listed in Table A-3 and 

Table A-4 of this subpart present at the facility. 

(5) * * * 

(i) * * * For fluorinated GHGs, calculate and 

report CO2e for only those fluorinated GHGs listed in Table 

A-1 of this subpart. 

* * * * * 

(12) For the 2010 reporting year only, facilities 

that have “part 75 units” (i.e. units that are subject to 

subpart D of this part or units that use the methods in 

part 75 of this chapter to quantify CO2 mass emissions in 

accordance with §98.33(a)(5)) must report annual GHG 

emissions either in full accordance with paragraphs 

(c)(4)(i) through (c)(4)(iii) of this section or in full 

accordance with paragraphs (c)(12)(i) through (c)(12)(iii) 

of this section. If the latter reporting option is chosen, 

you must report: 

(i) Annual emissions aggregated for all GHG from all 

applicable source categories, expressed in metric tons of 

CO2e calculated using Equation A-1 of this subpart. You 

must include biogenic CO2 emissions from part 75 units in 

these annual emissions, but exclude biogenic CO2 emissions 

from any non-part 75 units and other source categories. 
Page 238 of 442 

(ii) Annual emissions of biogenic CO2, expressed in 

metric tons (excluding biogenic CO2 emissions from part 75 

units), aggregated for all applicable source categories. 

(iii) Annual emissions from each applicable source 

category, expressed in metric tons of each applicable GHG 

listed in paragraphs (c)(12)(iii)(A) through 

(c)(12)(iii)(E) of this section. 

(A) Biogenic CO2 (excluding biogenic CO2 emissions 

from part 75 units). 

(B) CO2 . You must include biogenic CO2 emissions 

from part 75 units in these totals and exclude biogenic CO2

emissions from other non-part 75 units and other source 

categories. 

(C) CH4. 

(D) N2O. 

(E) Each fluorinated GHG (including those not listed 

in Table A-1 of this subpart). 

(d) * * * 

(3) * * * An owner or operator that submits an 

abbreviated report must submit a full GHG report according 

to the requirements of paragraph (c) of this section 

beginning in calendar year 2012. * * * 

* * * * * 
Page 239 of 442 

(f) Verification. To verify the completeness and 

accuracy of reported GHG emissions, the Administrator may 

review the certification statements described in paragraphs 

(c)(9) and (d)(3)(vi) of this section and any other 

credible evidence, in conjunction with a comprehensive 

review of the GHG reports and periodic audits of selected 

reporting facilities. * * * 

(g) * * * 

(4) Missing data computations. For each missing data 

event, also retain a record of the cause of the event and 

the corrective actions taken to restore malfunctioning 

monitoring equipment. 

(5) * * * 

(iii) The owner or operator shall revise the GHG 

Monitoring Plan as needed to reflect changes in production 

processes, monitoring instrumentation, and quality 

assurance procedures; or to improve procedures for the 

maintenance and repair of monitoring systems to reduce the 

frequency of monitoring equipment downtime. 

* * * * * 

(h) Annual GHG report revisions. 

(1) The owner or operator shall submit a revised 

annual GHG report within 45 days of discovering that an 

annual GHG report that the owner or operator previously 
Page 240 of 442 

submitted contains one or more substantive errors. The 

revised report must correct all substantive errors. 

(2) The Administrator may notify the owner or 

operator in writing that an annual GHG report previously 

submitted by the owner or operator contains one or more 

substantive errors. Such notification will identify each 

such substantive error. The owner or operator shall, 

within 45 days of receipt of the notification, either 

resubmit the report that, for each identified substantive 

error, corrects the identified substantive error (in 

accordance with the applicable requirements of this part) 

or provide information demonstrating that the previously 

submitted report does not contain the identified 

substantive error or that the identified error is not a 

substantive error. 

(3) A substantive error is an error that impacts the 

quantity of GHG emissions reported or otherwise prevents 

the reported data from being validated or verified. 

(4) Notwithstanding paragraphs (h)(1) and (h)(2) of 

this section, upon request by the owner or operator, the 

Administrator may provide reasonable extensions of the 45-

day period for submission of the revised report or 

information under paragraphs (h)(1) and (h)(2) of this 

section. If the Administrator receives a request for 
Page 241 of 442 

extension of the 45-day period, by e-mail to an address 

prescribed by the Administrator, at least two business days 

prior to the expiration of the 45-day period, and the 

Administrator does not respond to the request by the end of 

such period, the extension request is deemed to be 

automatically granted for 30 more days. During the 

automatic 30-day extension, the Administrator will 

determine what extension, if any, beyond the automatic 

extension is reasonable and will provide any such 

additional extension. 

(5) The owner or operator shall retain documentation 

for 3 years to support any revision made to an annual GHG 

report. 

(i) Calibration Accuracy Requirements. The owner or 

operator of a facility or supplier that is subject to the 

requirements of this part must meet the applicable flow 

meter calibration and accuracy requirements of this 

paragraph (i). The accuracy specifications in this 

paragraph (i) do not apply where either the use of company 

records (as defined in §98.6) or the use of “best available 

information” is specified in an applicable subpart of this 

part to quantify fuel usage and/or other parameters. 

Further, the provisions of this paragraph (i) do not apply 

to stationary fuel combustion units that use the 
Page 242 of 442 

methodologies in part 75 of this chapter to calculate CO2

mass emissions. 

(1) Except as otherwise provided in paragraphs (i)(4) 

through (i)(6) of this section, flow meters that measure 

liquid and gaseous fuel feed rates, process stream flow 

rates, or feedstock flow rates and provide data for the GHG 

emissions calculations shall be calibrated prior to April 

1, 2010 using the procedures specified in this paragraph 

(i) when such calibration is specified in a relevant 

subpart of this part. Each of these flow meters shall meet 

the applicable accuracy specification in paragraph (i)(2) 

or (i)(3) of this section. All other measurement devices 

(e.g., weighing devices) that are required by a relevant 

subpart of this part, and that are used to provide data for 

the GHG emissions calculations, shall also be calibrated 

prior to April 1, 2010; however, the accuracy 

specifications in paragraphs (i)(2) and (i)(3) of this 

section do not apply to these devices. Rather, each of 

these measurement devices shall be calibrated to meet the 

accuracy requirement specified for the device in the 

applicable subpart of this part, or, in the absence of such 

accuracy requirement, the device must be calibrated to an 

accuracy within the appropriate error range for the 

specific measurement technology, based on an applicable 
Page 243 of 442 

operating standard, including but not limited to 

manufacturer’s specifications and industry standards. The 

procedures and methods used to quality-assure the data from 

each measurement device shall be documented in the written 

monitoring plan, pursuant to paragraph (g)(5)(i)(C) of this 

section. 

(i) All flow meters and other measurement devices 

that are subject to the provisions of this paragraph (i) 

must be calibrated according to one of the following: You 

may use the manufacturer’s recommended procedures; an 

appropriate industry consensus standard method; or a method 

specified in a relevant subpart of this part. The 

calibration method(s) used shall be documented in the 

monitoring plan required under paragraph (g) of this 

section. 

(ii) For facilities and suppliers that become subject 

to this part after April 1, 2010, all flow meters and other 

measurement devices (if any) that are required by the 

relevant subpart(s) of this part to provide data for the 

GHG emissions calculations shall be installed no later than 

the date on which data collection is required to begin 

using the measurement device, and the initial 

calibration(s) required by this paragraph (i) (if any) 

shall be performed no later than that date. 
Page 244 of 442 

(iii) Except as otherwise provided in paragraphs 

(i)(4) through (i)(6) of this section, subsequent 

recalibrations of the flow meters and other measurement 

devices subject to the requirements of this paragraph (i) 

shall be performed at one of the following frequencies: 

(A) You may use the frequency specified in each 

applicable subpart of this part. 

(B) You may use the frequency recommended by the 

manufacturer or by an industry consensus standard practice, 

if no recalibration frequency is specified in an applicable 

subpart. 

(2) Perform all flow meter calibration at measurement 

points that are representative of the normal operating 

range of the meter. Except for the orifice, nozzle, and 

venturi flow meters described in paragraph (i)(3) of this 

section, calculate the calibration error at each 

measurement point using Equation A-2 of this section. The 

terms “R” and “A” in Equation A-2 must be expressed in 

consistent units of measure (e.g., gallons/minute, ft3/min). 

The calibration error at each measurement point shall not 

exceed 5.0 percent of the reference value. 

x 100

R

R A

CE

−

= (Eq. A-2) 

Where: 
Page 245 of 442 

CE = Calibration error (%). 

R = Reference value. 

A = Flow meter response to the reference value. 

(3) For orifice, nozzle, and venturi flow meters, the 

initial quality assurance consists of in-situ calibration 

of the differential pressure (delta-P), total pressure, and 

temperature transmitters. 

(i) Calibrate each transmitter at a zero point and at 

least one upscale point. Fixed reference points, such as 

the freezing point of water, may be used for temperature 

transmitter calibrations. Calculate the calibration error 

of each transmitter at each measurement point, using 

Equation A-3 of this subpart. The terms “R,” “A,” and “FS” 

in Equation A-3 of this subpart must be in consistent units 

of measure (e.g., milliamperes, inches of water, psi, 

degrees). For each transmitter, the CE value at each 

measurement point shall not exceed 2.0 percent of fullscale. Alternatively, the results are acceptable if the 

sum of the calculated CE values for the three transmitters 

at each calibration level (i.e., at the zero level and at 

each upscale level) does not exceed 6.0 percent. 

x 100

FS

R A

CE

−

= (Eq. A-3) 

Where: 
Page 246 of 442 

CE = Calibration error (%). 

R = Reference value. 

A = Transmitter response to the reference value. 

FS = Full-scale value of the transmitter. 

(ii) In cases where there are only two transmitters 

(i.e., differential pressure and either temperature or 

total pressure) in the immediate vicinity of the flow 

meter’s primary element (e.g., the orifice plate), or when 

there is only a differential pressure transmitter in close 

proximity to the primary element, calibration of these 

existing transmitters to a CE of 2.0 percent or less at 

each measurement point is still required, in accordance 

with paragraph (i)(3)(i) of this section; alternatively, 

when two transmitters are calibrated, the results are 

acceptable if the sum of the CE values for the two 

transmitters at each calibration level does not exceed 4.0 

percent. However, note that installation and calibration 

of an additional transmitter (or transmitters) at the flow 

monitor location to measure temperature or total pressure 

or both is not required in these cases. Instead, you may 

use assumed values for temperature and/or total pressure, 

based on measurements of these parameters at a remote 

location (or locations), provided that the following 

conditions are met: 
Page 247 of 442 

(A) You must demonstrate that measurements at the 

remote location(s) can, when appropriate correction factors 

are applied, reliably and accurately represent the actual 

temperature or total pressure at the flow meter under all 

expected ambient conditions. 

(B) You must make all temperature and/or total 

pressure measurements in the demonstration described in 

paragraph (i)(3)(ii)(A) of this section with calibrated 

gauges, sensors, transmitters, or other appropriate 

measurement devices. At a minimum, calibrate each of these 

devices to an accuracy within the appropriate error range 

for the specific measurement technology, according to one 

of the following. You may calibrate using a manufacturer’s 

specification or an industry consensus standard. 

(C) You must document the methods used for the 

demonstration described in paragraph (i)(3)(ii)(A) of this 

section in the written GHG Monitoring Plan under paragraph 

(g)(5)(i)(C) of this section. You must also include the 

data from the demonstration, the mathematical 

correlation(s) between the remote readings and actual flow 

meter conditions derived from the data, and any supporting 

engineering calculations in the GHG Monitoring Plan. You 

must maintain all of this information in a format suitable 

for auditing and inspection. 
Page 248 of 442 

(D) You must use the mathematical correlation(s)

derived from the demonstration described in paragraph 

(i)(3)(ii)(A) of this section to convert the remote 

temperature or the total pressure readings, or both, to the 

actual temperature or total pressure at the flow meter, or 

both, on a daily basis. You shall then use the actual 

temperature and total pressure values to correct the 

measured flow rates to standard conditions. 

(E) You shall periodically check the correlation(s) 

between the remote and actual readings (at least once a 

year), and make any necessary adjustments to the 

mathematical relationship(s). 

(4) Fuel billing meters are exempted from the 

calibration requirements of this section and from the GHG 

Monitoring Plan and recordkeeping provisions of paragraphs 

(g)(5)(i)(C), (g)(6), and (g)(7) of this section, provided 

that the fuel supplier and any unit combusting the fuel do 

not have any common owners and are not owned by 

subsidiaries or affiliates of the same company. Meters 

used exclusively to measure the flow rates of fuels that 

are used for unit startup are also exempted from the 

calibration requirements of this section. 

(5) For a flow meter that has been previously 

calibrated in accordance with paragraph (i)(1) of this 
Page 249 of 442 

section, an additional calibration is not required by the 

date specified in paragraph (i)(1) of this section if, as 

of that date, the previous calibration is still active 

(i.e., the device is not yet due for recalibration because 

the time interval between successive calibrations has not 

elapsed). In this case, the deadline for the successive 

calibrations of the flow meter shall be set according to 

one of the following. You may use either the 

manufacturer’s recommended calibration schedule or you may 

use the industry consensus calibration schedule. 

(6) For units and processes that operate continuously 

with infrequent outages, it may not be possible to meet the 

April 1, 2010 deadline for the initial calibration of a 

flow meter or other measurement device without disrupting 

normal process operation. In such cases, the owner or 

operator may postpone the initial calibration until the 

next scheduled maintenance outage. The best available 

information from company records may be used in the 

interim. The subsequent required recalibrations of the 

flow meters may be similarly postponed. Such postponements 

shall be documented in the monitoring plan that is required 

under paragraph (g)(5) of this section. 

(7) If the results of an initial calibration or a 

recalibration fail to meet the required accuracy 
Page 250 of 442 

specification, data from the flow meter shall be considered 

invalid, beginning with the hour of the failed calibration 

and continuing until a successful calibration is completed. 

You shall follow the missing data provisions provided in 

the relevant missing data sections during the period of 

data invalidation. 

(j) Measurement Device Installation. 

(1) General. If an owner or operator required to 

report under subpart P, subpart X or subpart Y of this part 

has process equipment or units that operate continuously 

and it is not possible to install a required flow meter or 

other measurement device by April 1, 2010, (or by any later 

date in 2010 approved by the Administrator as part of an 

extension of best available monitoring methods per 

paragraph (d) of this section) without process equipment or 

unit shutdown, or through a hot tap, the owner or operator 

may request an extension from the Administrator to delay 

installing the measurement device until the next scheduled 

process equipment or unit shutdown. If approval for such 

an extension is granted by the Administrator, the owner or 

operator must use best available monitoring methods during 

the extension period. 

(2) Requests for extension of the use of best 

available monitoring methods for measurement device 
Page 251 of 442 

installation. The owner or operator must first provide the 

Administrator an initial notification of the intent to 

submit an extension request for use of best available 

monitoring methods beyond December 31, 2010 (or an earlier 

date approved by EPA) in cases where measurement device 

installation would require a process equipment or unit 

shutdown, or could only be done through a hot tap. The 

owner or operator must follow-up this initial notification 

with the complete extension request containing the 

information specified in paragraph (j)(4) of this section. 

(3) Timing of request. 

(i) The initial notice of intent must be submitted no 

later than January 1, 2011, or by the end of the approved 

use of best available monitoring methods extension in 2010, 

whichever is earlier. The completed extension request must 

be submitted to the Administrator no later than February 

15, 2011. 

(ii) Any subsequent extensions to the original 

request must be submitted to the Administrator within 4 

weeks of the owner or operator identifying the need to 

extend the request, but in any event no later than 4 weeks 

before the date for the planned process equipment or unit 

shutdown that was provided in the original request. 
Page 252 of 442 

(4) Content of the request. Requests must contain 

the following information: 

(i) Specific measurement device for which the request 

is being made and the location where each measurement 

device will be installed. 

(ii) Identification of the specific rule requirements 

(by rule subpart, section, and paragraph numbers) requiring 

the measurement device. 

(iii) A description of the reasons why the needed 

equipment could not be installed before April 1, 2010, or 

by the expiration date for the use of best available 

monitoring methods, in cases where an extension has been 

granted under §98.3(d). 

(iv) Supporting documentation showing that it is not 

practicable to isolate the process equipment or unit and 

install the measurement device without a full shutdown or a 

hot tap, and that there was no opportunity during 2010 to 

install the device. Include the date of the three most 

recent shutdowns for each relevant process equipment or 

unit, the frequency of shutdowns for each relevant process 

equipment or unit, and the date of the next planned process 

equipment or unit shutdown. 
Page 253 of 442 

(v) Include a description of the proposed best 

available monitoring method for estimating GHG emissions 

during the time prior to installation of the meter. 

(5) Approval criteria. The owner or operator must 

demonstrate to the Administrator’s satisfaction that it is 

not reasonably feasible to install the measurement device 

before April 1, 2010 (or by the expiration date for the use 

of best available monitoring methods, in cases where an 

extension has been granted under paragraph(d) of this 

section) without a process equipment or unit shutdown, or 

through a hot tap, and that the proposed method for 

estimating GHG emissions during the time before which the 

measurement device will be installed is appropriate. The 

Administrator will not initially approve the use of the 

proposed best available monitoring method past December 31, 

2013. 

(6) Measurement device installation deadline. Any 

owner or operator that submits both a timely initial notice 

of intent and a timely completed extension request under 

paragraph (j)(3) of this section to extend use of best 

available monitoring methods for measurement device 

installation must install all such devices by July 1, 2011 

unless the extension request under this paragraph (j) is 

approved by the Administrator before July 1, 2011. 
Page 254 of 442 

(7) One time extension past December 31, 2013. If an 

owner or operator determines that a scheduled process 

equipment or unit shutdown will not occur by December 31, 

2013, the owner or operator may re-apply to use best 

available monitoring methods for one additional time 

period, not to extend beyond December 31, 2015. To extend 

use of best available monitoring methods past December 31, 

2013, the owner or operator must submit a new extension 

request by June 1, 2013 that contains the information 

required in paragraph (j)(4) of this section. The owner or 

operator must demonstrate to the Administrator’s 

satisfaction that it continues to not be reasonably 

feasible to install the measurement device before December 

31, 2013 without a process equipment or unit shutdown, or 

that installation of the measurement device could only be 

done through a hot tap, and that the proposed method for 

estimating GHG emissions during the time before which the 

measurement device will be installed is appropriate. An 

owner or operator that submits a request under this 

paragraph to extend use of best available monitoring 

methods for measurement device installation must install 

all such devices by December 31, 2013, unless the extension 

request under this paragraph is approved by the 

Administrator. 
Page 255 of 442 

3. Section 98.4 is amended by revising paragraphs 

(i)(2) and (m)(2)(i) to read as follows: 

§98.4 Authorization and Responsibilities of the Designated 

Representative.

* * * * * 

(i) * * * 

(2) The name, organization name (company affiliationemployer), address, e-mail address (if any), telephone 

number, and facsimile transmission number (if any) of the 

designated representative and any alternate designated 

representative. 

* * * * * 

(m) * * * 

(2) * * * 

(i) The name, organization name (company affiliationemployer) address, e-mail address (if any), telephone 

number, and facsimile transmission number (if any) of such 

designated representative or alternate designated 

representative. 

* * * * * 

4. Section 98.6 is amended by: 

a. Adding in alphabetical order definitions for 

“Agricultural by-products,” “Primary fuel,” “Solid byproducts,” “Used oil,” and “Wood residuals.” 
Page 256 of 442 

b. Revising the definitions for “Bulk natural gas 

liquid or NGL,” “Distillate Fuel Oil,” “Fossil fuel,” “Fuel 

gas,” “Municipal solid waste or MSW,” “Natural gas,” 

“Natural gas liquids (NGLs) and “Standard conditions or 

standard temperature and pressure (STP).” 

c. Removing the definition for “Fossil fuel-fired.” 

§98.6 Definitions.

* * * * * 

Agricultural by-products means those parts of arable 

crops that are not used for the primary purpose of 

producing food. Agricultural by-products include, but are 

not limited to, oat, corn and wheat straws, bagasse, peanut 

shells, rice and coconut husks, soybean hulls, palm kernel 

cake, cottonseed and sunflower seed cake, and pomace. 

* * * * * 

Bulk natural gas liquid or NGL refers to mixtures of 

hydrocarbons that have been separated from natural gas as 

liquids through the process of absorption, condensation, 

adsorption, or other methods. Generally, such liquids 

consist of ethane, propane, butanes, and pentanes plus. 

Bulk NGL is sold to fractionators or to refineries and 

petrochemical plants where the fractionation takes place. 

* * * * * 
Page 257 of 442 

Distillate fuel oil means a classification for one of 

the petroleum fractions produced in conventional 

distillation operations and from crackers and hydrotreating 

process units. The generic term distillate fuel oil 

includes kerosene, kerosene-type jet fuel, diesel fuels 

(Diesel Fuels No. 1, No. 2, and No. 4), and fuel oils (Fuel 

Oils No. 1, No. 2, and No. 4). 

* * * * * 

Fossil fuel means natural gas, petroleum, coal, or any 

form of solid, liquid, or gaseous fuel derived from such 

material, for purpose of creating useful heat. 

* * * * * 

Fuel gas means gas generated at a petroleum refinery 

or petrochemical plant and that is combusted separately or 

in any combination with any type of gas. 

* * * * * 

Municipal solid waste or MSW means solid phase 

household, commercial/retail, and/or institutional waste. 

Household waste includes material discarded by single and 

multiple residential dwellings, hotels, motels, and other 

similar permanent or temporary housing establishments or 

facilities. Commercial/retail waste includes material 

discarded by stores, offices, restaurants, warehouses, nonmanufacturing activities at industrial facilities, and 
Page 258 of 442 

other similar establishments or facilities. Institutional 

waste includes material discarded by schools, nonmedical 

waste discarded by hospitals, material discarded by nonmanufacturing activities at prisons and government 

facilities, and material discarded by other similar 

establishments or facilities. Household, 

commercial/retail, and institutional wastes include yard 

waste, refuse-derived fuel, and motor vehicle maintenance 

materials. Insofar as there is separate collection, 

processing and disposal of industrial source waste streams 

consisting of used oil, wood pallets, construction, 

renovation, and demolition wastes (which includes, but is 

not limited to, railroad ties and telephone poles), paper, 

clean wood, plastics, industrial process or manufacturing 

wastes, medical waste, motor vehicle parts or vehicle 

fluff, or used tires that do not contain hazardous waste 

identified or listed under 42 U.S.C. §6921, such wastes are 

not municipal solid waste. However, such wastes qualify as 

municipal solid waste where they are collected with other 

municipal solid waste or are otherwise combined with other 

municipal solid waste for processing and/or disposal. 

* * * * * 

Natural gas means a naturally occurring mixture of 

hydrocarbon and non-hydrocarbon gases found in geologic 
Page 259 of 442 

formations beneath the earth’s surface, of which the 

principal constituent is methane. Natural gas may be field 

quality or pipeline quality. 

* * * * * 

Natural gas liquids (NGLs) means those hydrocarbons in 

natural gas that are separated from the gas as liquids 

through the process of absorption, condensation, 

adsorption, or other methods. Generally, such liquids 

consist of ethane, propane, butanes, and pentanes plus. 

Bulk NGLs refers to mixtures of NGLs that are sold or 

delivered as undifferentiated product from natural gas 

processing plants. 

* * * * * 

Primary fuel means the fuel that provides the greatest 

percentage of the annual heat input to a stationary fuel 

combustion unit. 

* * * * * 

Solid by-products means plant matter such as vegetable 

waste, animal materials/wastes, and other solid biomass, 

except for wood, wood waste, and sulphite lyes (black 

liquor). 

* * * * * 

Standard conditions or standard temperature and 

pressure (STP), for the purposes of this part, means either 
Page 260 of 442 

60 or 68 degrees Fahrenheit and 14.7 pounds per square inch 

absolute. 

* * * * * 

Used oil means a petroleum-derived or syntheticallyderived oil whose physical properties have changed as a 

result of handling or use, such that the oil cannot be used 

for its original purpose. Used oil consists primarily of 

automotive oils (e.g., used motor oil, transmission oil, 

hydraulic fluids, brake fluid, etc.) and industrial oils 

(e.g., industrial engine oils, metalworking oils, process 

oils, industrial grease, etc). 

* * * * * 

Wood residuals means materials recovered from three 

principal sources: municipal solid waste (MSW); 

construction and demolition debris; and primary timber 

processing. Wood residuals recovered from MSW include 

wooden furniture, cabinets, pallets and containers, scrap 

lumber (from sources other than construction and demolition 

activities), and urban tree and landscape residues. Wood 

residuals from construction and demolition debris originate 

from the construction, repair, remodeling and demolition of 

houses and non-residential structures. Wood residuals from 

primary timber processing include bark, sawmill slabs and 

edgings, sawdust, and peeler log cores. Other sources of 
Page 261 of 442 

wood residuals include, but are not limited to, railroad 

ties, telephone and utility poles, pier and dock timbers, 

wastewater process sludge from paper mills, trim, sander 

dust, and sawdust from wood products manufacturing 

(including resinated wood product residuals), and logging 

residues. 

* * * * * 

5. Section 98.7 is amended by: 

a. Removing and reserving paragraph (b). 

b. Revising paragraphs (d)(1) through (d)(10). 

c. Removing paragraph (d)(11). 

d. Revising paragraph (e)(4). 

e. Removing and reserving paragraph (e)(7). 

f. Revising paragraphs (e)(8), (e)(10), (e)(11), 

(e)(14) and (e)(15). 

g. Revising paragraphs (e)(19) and (e)(20). 

h. Revising paragraphs (e)(24) through (e)(27). 

i. Removing and reserving paragraph (e)(28). 

j. Revising paragraph (e)(30). 

k. Revising paragraph (e)(33). 

l. Revising paragraph (e)(36). 

m. Removing and reserving paragraph (e)(39). 

n. Adding paragraphs (e)(48) and (e)(49). 

o. Removing and reserving paragraph (f)(1). 
Page 262 of 442 

p. Revising paragraph (f)(2) 

q. Removing and reserving paragraph (g)(3). 

r. Revising paragraph (m)(3). 

s. Adding paragraphs (m)(8) through (m)(14). 

§98.7 What standardized methods are incorporated by 

reference into this part?

* * * * * 

(d) * * * 

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

Pipes Using Orifice, Nozzle, and Venturi, incorporation by 

reference (IBR) approved for §98.124(m)(1), §98.324(e), 

§98.354(d), §98.354(h), §98.344(c) and §98.364(e). 

(2) ASME MFC-4M–1986 (Reaffirmed 1997) Measurement of 

Gas Flow by Turbine Meters, IBR approved for §98.124(m)(2), 

§98.324(e), §98.344(c), §98.354(h), and §98.364(e). 

(3) ASME MFC-5M-1985 (Reaffirmed 1994) Measurement of 

Liquid Flow in Closed Conduits Using Transit-Time 

Ultrasonic Flow Meters, IBR approved for §98.124(m)(3) and 

§98.354(d). 

(4) ASME MFC-6M–1998 Measurement of Fluid Flow in 

Pipes Using Vortex Flowmeters, IBR approved for 

§98.124(m)(4), §98.324(e), §98.344(c), §98.354(h), and 

§98.364(e). 
Page 263 of 442 

(5) ASME MFC-7M–1987 (Reaffirmed 1992) Measurement of 

Gas Flow by Means of Critical Flow Venturi Nozzles, IBR 

approved for §98.124(m)(5), §98.324(e), §98.344(c), 

§98.354(h), and §98.364(e). 

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

Liquid Flow in Closed Conduits by Weighing Method, IBR 

approved for §98.124(m)(6). 

(7) ASME MFC-11M-2006 Measurement of Fluid Flow by 

Means of Coriolis Mass Flowmeters, IBR approved for 

§98.124(m)(7), §98.324(e), §98.344(c), and §98.354(h). 

(8) ASME MFC-14M-2003 Measurement of Fluid Flow Using 

Small Bore Precision Orifice Meters, IBR approved for 

§98.124(m)(8), §98.324(e), §98.344(c), §98.354(h), and 

§98.364(e). 

(9) ASME MFC-16-2007 Measurement of Liquid Flow in 

Closed Conduits with Electromagnetic Flow Meters, IBR 

approved for §98.354(d). 

(10) ASME MFC-18M-2001 Measurement of Fluid Flow 

Using Variable Area Meters, IBR approved for §98.324(e), 

§98.344(c), §98.354(h), and §98.364(e). 

(e) * * * 

(4) ASTM D240-02 (Reapproved 2007) Standard Test 

Method for Heat of Combustion of Liquid Hydrocarbon Fuels 

by Bomb Calorimeter, IBR approved for §98.254(e). 
Page 264 of 442 

* * * * * 

(8) ASTM D1826-94 (Reapproved 2003) Standard Test 

Method for Calorific (Heating) Value of Gases in Natural 

Gas Range by Continuous Recording Calorimeter, IBR approved 

for §98.254(e). 

* * * * * 

(10) ASTM D1945-03 Standard Test Method for Analysis 

of Natural Gas by Gas Chromatography, IBR approved for 

§98.74(c), §98.164(b), §98.244(b), §98.254(d), §98.324(d), 

§98.354(g), and §98.344(b). 

(11) ASTM D1946-90 (Reapproved 2006) Standard 

Practice for Analysis of Reformed Gas by Gas 

Chromatography, IBR approved for §98.74(c), §98.164(b), 

§98.254(d), §98.324(d), §98.344(b), §98.354(g), and 

§98.364(c). 

* * * * * 

(14) ASTM D2502–04 Standard Test Method for 

Estimation of Mean Relative Molecular Mass of Petroleum 

Oils From Viscosity Measurements, IBR approved for § 

98.74(c). 

(15) ASTM D2503-92 (Reapproved 2007) Standard Test 

Method for Relative Molecular Mass (Molecular Weight) of 

Hydrocarbons by Thermoelectric Measurement of Vapor 

Pressure, IBR approved for §98.74(c) and §98.254(d)(6). 
Page 265 of 442 

* * * * * 

(19) ASTM D3238-95 (Reapproved 2005) Standard Test 

Method for Calculation of Carbon Distribution and 

Structural Group Analysis of Petroleum Oils by the n-d-M 

Method, IBR approved for §98.74(c) and §98.164(b). 

(20) ASTM D3588-98 (Reapproved 2003) Standard 

Practice for Calculating Heat Value, Compressibility 

Factor, and Relative Density of Gaseous Fuels, IBR approved 

for §98.254(e). 

* * * * * 

(24) ASTM D4809-06 Standard Test Method for Heat of 

Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter 

(Precision Method), IBR approved for §98.254(e). 

(25) ASTM D4891-89 (Reapproved 2006) Standard Test 

Method for Heating Value of Gases in Natural Gas Range by 

Stoichiometric Combustion, IBR approved for §98.254(e) and 

§98.324(d). 

(26) ASTM D5291-02 (Reapproved 2007) Standard Test 

Methods for Instrumental Determination of Carbon, Hydrogen, 

and Nitrogen in Petroleum Products and Lubricants, IBR 

approved for §98.74(c), §98.164(b), §98.244(b), and 

§98.254(i). 

(27) ASTM D5373-08 Standard Test Methods for 

Instrumental Determination of Carbon, Hydrogen, and 
Page 266 of 442 

Nitrogen in Laboratory Samples of Coal, IBR approved for 

§98.74(c), §98.114(b), §98.164(b), §98.174(b), §98.184(b), 

§98.244(b), §98.254(i), §98.274(b), §98.284(c), §98.284(d), 

§98.314(c), §98.314(d), §98.314(f), and §98.334(b). 

* * * * * 

(30) ASTM D6348-03 Standard Test Method for 

Determination of Gaseous Compounds by Extractive Direct 

Interface Fourier Transform Infrared (FTIR) Spectroscopy, 

IBR approved for §98.54(b), §98.124(e)(2), §98.224(b), and 

§98.414(n). 

* * * * *

(33) ASTM D6866–08 Standard Test Methods for 

Determining the Biobased Content of Solid, Liquid, and 

Gaseous Samples Using Radiocarbon Analysis, IBR approved 

for § 98.34(d), § 98.34(e), and § 98.36(e). 

* * * * *

(36) ASTM D7459–08 Standard Practice for Collection 

of Integrated Samples for the Speciation of Biomass 

(Biogenic) and Fossil-Derived Carbon Dioxide Emitted from 

Stationary Emissions Sources, IBR approved for § 98.34(d), 

§ 98.34(e), and § 98.36(e). 

* * * * * 

(48) ASTM D2593-93(2009) Standard Test Method for 

Butadiene Purity and Hydrocarbon Impurities by Gas 
Page 267 of 442 

Chromatography, approved July 1, 2009, IBR approved for 

§98.244(b)(4)(xi). 

(49) ASTM D7633-10 Standard Test Method for Carbon 

Black—Carbon Content, approved May 15, 2010, IBR approved 

for §98.244(b)(4)(xii). 

* * * * * 

(f) * * * 

(1) [Reserved] 

(2) GPA 2261-00 Analysis for Natural Gas and Similar 

Gaseous Mixtures by Gas Chromatography, IBR approved for 

§98.164(b), §98.254(d), §98.344(b), and §98.354(g). 

* * * * * 

(m) * * * 

(3) Protocol for Measuring Destruction or Removal 

Efficiency (DRE) of Fluorinated Greenhouse Gas Abatement 

Equipment in Electronics Manufacturing, Version 1, EPA-430-

R-10-003, March 2010 (EPA 430-R-10-003), 

http://www.epa.gov/semiconductorpfc/documents/dre_protocol.pdf, IBR approved for 

§98.94(f)(4)(i), §98.94(g)(3), §98.97(d)(4), §98.98, 

§98.124(e)(2), and §98.414(n)(1). 

* * * * * 

(8) Protocol for Measurement of Tetrafluoromethane 

(CF4) and Hexafluoroethane (C2F6) Emissions from Primary 
Page 268 of 442 

Aluminum Production (2008), 

http://www.epa.gov/highgwp/aluminumpfc/documents/measureprotocol.pdf, IBR approved for 

§98.64(a). 

(9) AP 42, Section 5.2, Transportation And Marketing 

Of Petroleum Liquids, July 2008, (AP 42, Section 5.2); 

http://www.epa.gov/ttn/chief/ap42/ch05/final/c05s02.pdf; in 

Chapter 5, Petroleum Industry, of AP 42, Compilation of Air 

Pollutant Emission Factors, 5th Edition, Volume I, IBR 

approved for §98.253(n). 

(10) Method 9060A, Total Organic Carbon, Revision 1, 

November 2004 (Method 9060A), 

http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/9060a.

pdf; in EPA Publication No. SW-846, “Test Methods for 

Evaluating Solid Waste, Physical/Chemical Methods,” Third 

Edition, IBR approved for §98.244(b)(4)(viii). 

(11) Method 8031, Acrylonitrile By Gas 

Chromatography, Revision 0, September 1994 (Method 8031), 

http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/8031.p

df; in EPA Publication No. SW-846, “Test Methods for 

Evaluating Solid Waste, Physical/Chemical Methods,” Third 

Edition, IBR approved for §98.244(b)(4)(viii). 

(12) Method 8021B, Aromatic And Halogenated Volatiles 

By Gas Chromatography Using Photoionization And/Or 
Page 269 of 442 

Electrolytic Conductivity Detectors, Revision 2, December 

1996 (Method 8021B). 

http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/8021b.

pdf; in EPA Publication No. SW-846, “Test Methods for 

Evaluating Solid Waste, Physical/Chemical Methods,” Third 

Edition, IBR approved for §98.244(b)(4)(viii). 

(13) Method 8015C, Nonhalogenated Organics By Gas 

Chromatography, Revision 3, February 2007 (Method 8015C). 

http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/8015c.

pdf; in EPA Publication No. SW-846, “Test Methods for 

Evaluating Solid Waste, Physical/Chemical Methods,” Third 

Edition, IBR approved for §98.244(b)(4)(viii). 

(14) AP 42, Section 7.1, Organic Liquid Storage 

Tanks, November 2006 (AP 42, Section 7.1), 

http://www.epa.gov/ttn/chief/ap42/ch07/final/c07s01.pdf; in 

Chapter 7, Liquid Storage Tanks, of AP 42, Compilation of 

Air Pollutant Emission Factors, 5th Edition, Volume I, IBR 

approved for §98.243(m)(1) and §98.256(o)(2)(i). 

6. Table A-5 to subpart A of part 98 is amended by 

revising the entry for “(B) All local natural gas 

distribution companies” to read as follows: 
Page 270 of 442 

Table A-5 to Subpart A of Part 98—Supplier Category List 

for §98.2(a)(4) 

Supplier Categoriesa Applicable in 2010 and Future Years

* * * * * * *

(B) Local natural gas distribution companies that 

deliver 460,000 thousand standard cubic feet or more of 

natural gas per year. 

* * * * * * *

Subpart C—[Amended] 

7. Section 98.30 is amended by: 

a. Revising paragraph (b)(4). 

b. Revising paragraph (c) introductory text. 

c. Adding paragraph (d). 

§98.30 Definition of the source category. 

(b) * * * 

(4) Flares, unless otherwise required by provisions 

of another subpart of this part to use methodologies in 

this subpart. 

* * * * * 

(c) For a unit that combusts hazardous waste (as 

defined in §261.3 of this chapter), reporting of GHG 

emissions is not required unless either of the following 

conditions apply: 

* * * * * 
Page 271 of 442 

(d) You are not required to report GHG emissions from 

pilot lights. A pilot light is a small auxiliary flame 

that ignites the burner of a combustion device when the 

control valve opens. 

8. Section 98.32 is revised to read as follows: 

§98.32 GHGs to report.

You must report CO2, CH4, and N2O mass emissions from 

each stationary fuel combustion unit, except as otherwise 

indicated in this subpart. 

9. Section 98.33 is amended by: 

a. Revising paragraph (a) introductory text and 

paragraph (a)(1). 

b. Revising the definition of “HHV” in Equation C-2a 

of paragraph (a)(2)(i). 

c. Revising the first two sentences of paragraph 

(a)(2)(ii) introductory text. 

d. In paragraph (a)(2)(ii)(A), revising the first 

sentence and the definitions of “(HHV)i,” “(Fuel)i,” and “n” 

in Equation C-2b. 

e. Revising paragraph (a)(2)(ii)(B). 

f. Revising the definitions of “CC”, “MW”, and “MVC” 

in Equation C-5 of paragraph (a)(3)(iii). 

g. Revising paragraphs (a)(3)(iv), (a)(3)(v), 

(a)(4)(iii), and (a)(4)(iv). 
Page 272 of 442 

h. Adding paragraph (a)(4)(viii). 

i. Revising paragraphs (a)(5) introductory text, 

(a)(5)(i) introductory text, (a)(5)(i)(A), (a)(5)(i)(B), 

(a)(5)(ii) introductory text, (a)(5)(ii)(A), (a)(5)(iii) 

introductory text, (a)(5)(iii)(A), and (a)(5)(iii)(B). 

j. Redesignating paragraph (a)(5)(iii)(D) as 

paragraph (a)(5)(iv), and revising newly designated 

paragraph (a)(5)(iv). 

k. Revising paragraph (b)(1)(iv). 

l. Adding paragraphs (b)(1)(v), (b)(1)(vi) and 

(b)(1)(vii). 

m. Revising paragraphs (b)(2)(ii), (b)(3)(ii)(A), 

(b)(3)(iii) introductory text, and (b)(3)(iii)(B). 

n. Adding paragraph (b)(3)(iv). 

o. Adding a second sentence to paragraph (b)(4)(i). 

p. Revising paragraphs (b)(4)(ii)(A), (b)(4)(ii)(B), 

(b)(4)(ii)(E), (b)(4)(ii)(F), and (b)(4)(iii) introductory 

text. 

q. Adding paragraph (b)(4)(iv). 

r. Revising paragraph (b)(5) and the third sentence 

of paragraph (b)(6). 

s. Revising paragraph (c)(1) introductory text and 

the definition of “HHV” in Equation C-8. 

t. Adding paragraphs (c)(1)(i) and (c)(1)(ii). 
Page 273 of 442 

u. Revising the second sentence of paragraph (c)(2). 

v. In paragraph (c)(4) introductory text, revising 

the only sentence and revising the definition of “(HI)A” in 

Equation C-10. 

w. Revising paragraphs (c)(4)(i) and (c)(4)(ii). 

x. Revising paragraph (c)(5). 

y. Adding paragraph (c)(6). 

z. In paragraph (d)(1), revising the first sentence, 

adding a second sentence, and revising the definition of 

“R” in Equation C-11. 

aa. Revising paragraphs (d)(2), paragraph (e) 

introductory text, paragraph (e)(1), and paragraph (e)(2) 

introductory text. 

bb. Revising the definition of “Fc” in Equation C-13 

of paragraph (e)(2)(iii). 

cc. Revising paragraphs (e)(2)(iv), (e)(2)(vi)(C), 

and (e)(3). 

dd. Removing paragraph (e)(4). 

ee. Redesignating paragraph (e)(5) as (e)(4). 

ff. Revising the first sentence of newly designated 

paragraph (e)(4). 

gg. Adding paragraph (e)(5). 

§98.33 Calculating GHG emissions. 

* * * * * 
Page 274 of 442 

(a) CO2 emissions from fuel combustion. Calculate CO2

mass emissions by using one of the four calculation 

methodologies in paragraphs (a)(1) through (a)(4) of this 

section, subject to the applicable conditions, 

requirements, and restrictions set forth in paragraph (b) 

of this section. Alternatively, for units that meet the 

conditions of paragraph (a)(5) of this section, you may use 

CO2 mass emissions calculation methods from part 75 of this 

chapter, as described in paragraph (a)(5) of this section. 

For units that combust both biomass and fossil fuels, you 

must calculate and report CO2 emissions from the combustion 

of biomass separately using the methods in paragraph (e) of 

this section, except as otherwise provided in paragraphs 

(a)(5)(iv) and (e) of this section and in §98.36(d). 

(1) Tier 1 Calculation Methodology. Calculate the 

annual CO2 mass emissions for each type of fuel by using 

Equation C-1, C-1a, or C-1b of this section (as 

applicable). 

(i) Use Equation C-1 except when natural gas billing 

records are used to quantify fuel usage and gas consumption 

is expressed in units of therms or million Btu. In that 

case, use Equation C-1a or C-1b, as applicable. 

CO 1x 10 * Fuel *HHV *EF 3

2

−

= (Eq. C-1) 

Where: 
Page 275 of 442 

CO2 = Annual CO2 mass emissions for the specific fuel 

type (metric tons). 

Fuel = Mass or volume of fuel combusted per year, from 

company records as defined in §98.6 (express mass 

in short tons for solid fuel, volume in standard 

cubic feet for gaseous fuel, and volume in 

gallons for liquid fuel). 

HHV = Default high heat value of the fuel, from Table 

C-1 of this subpart (mmBtu per mass or mmBtu per 

volume, as applicable). 

EF = Fuel-specific default CO2 emission factor, from 

Table C-1 of this subpart (kg CO2/mmBtu). 

1 x 10-3 = Conversion factor from kilograms to metric tons. 

(ii) If natural gas consumption is obtained from 

billing records and fuel usage is expressed in therms, use 

Equation C-1a. 

CO 1 x 10 [0.1* Gas * EF]

3

2

−

= (Eq. C-1a) 

Where: 

CO2 = Annual CO2 mass emissions from natural gas 

combustion (metric tons). 

Gas = Annual natural gas usage, from billing records 

(therms). 

EF = Fuel-specific default CO2 emission factor for 

natural gas, from Table C-1 of this subpart (kg 

CO2/mmBtu). 

0.1 = Conversion factor from therms to mmBtu 

1 x 10-3 = Conversion factor from kilograms to metric tons. 
Page 276 of 442 

(iii) If natural gas consumption is obtained from 

billing records and fuel usage is expressed in mmBtu, use 

Equation C-1b. 

CO 1 x 10 * Gas * EF 3

2

−

= (Eq. C-1b) 

Where: 

CO2 = Annual CO2 mass emissions from natural gas 

combustion (metric tons). 

Gas = Annual natural gas usage, from billing records 

(mmBtu). 

EF = Fuel-specific default CO2 emission factor for 

natural gas, from Table C-1 of this subpart (kg 

CO2/mmBtu). 

1 x 10-3 = Conversion factor from kilograms to metric tons. 

(2) * * * 

(i) * * * * * 

HHV = Annual average high heat value of the fuel 

(mmBtu per mass or volume). The average HHV 

shall be calculated according to the 

requirements of paragraph (a)(2)(ii) of this 

section. 

* * * * * 

(ii) The minimum required sampling frequency for 

determining the annual average HHV (e.g., monthly, 

quarterly, semi-annually, or by lot) is specified in 

§98.34. The method for computing the annual average HHV is 

a function of unit size and how frequently you perform or 
Page 277 of 442 

receive from the fuel supplier the results of fuel sampling 

for HHV. * * * 

(A) If the results of fuel sampling are received 

monthly or more frequently, then for each unit with a 

maximum rated heat input capacity greater than or equal to 

100 mmBtu/hr (or for a group of units that includes at 

least one unit of that size), the annual average HHV shall 

be calculated using Equation C-2b of this section. * * * 

* * * * * 

(HHV)I = Measured high heat value of the fuel, for month 

“i” (which may be the arithmetic average of 

multiple determinations), or, if applicable, an 

appropriate substitute data value (mmBtu per 

mass or volume). 

(Fuel)I = Mass or volume of the fuel combusted during 

month “i,” from company records (express mass 

in short tons for solid fuel, volume in 

standard cubic feet for gaseous fuel, and 

volume in gallons for liquid fuel). 

n = Number of months in the year that the fuel is 

burned in the unit. 

(B) If the results of fuel sampling are received less 

frequently than monthly, or, for a unit with a maximum 

rated heat input capacity less than 100 mmBtu/hr (or a 

group of such units) regardless of the HHV sampling 

frequency, the annual average HHV shall either be computed 

according to paragraph (a)(2)(ii)(A) of this section or as 

the arithmetic average HHV for all values for the year 
Page 278 of 442 

(including valid samples and substitute data values under 

§98.35). 

* * * * * 

(3) * * * 

(iii) * * * * * 

CC = Annual average carbon content of the gaseous 

fuel (kg C per kg of fuel). The annual average 

carbon content shall be determined using the 

same procedures as specified for HHV in 

paragraph (a)(2)(ii) of this section. 

MW = Annual average molecular weight of the gaseous 

fuel (kg/kg-mole). The annual average molecular 

weight shall be determined using the same 

procedures as specified for HHV in paragraph 

(a)(2)(ii) of this section. 

MVC = Molar volume conversion factor at standard 

conditions, as defined in §98.6. Use 849.5 scf 

per kg mole if you select 68 oF as standard 

temperature and 836.6 scf per kg mole if you 

select 60 oF as standard temperature. 

* * * * * 

(iv) Fuel flow meters that measure mass flow rates 

may be used for liquid or gaseous fuels, provided that the 

fuel density is used to convert the readings to volumetric 

flow rates. The density shall be measured at the same 

frequency as the carbon content. You must measure the 

density using one of the following appropriate methods. 

You may use a method published by a consensus-based 

standards organization, if such a method exists, or you may 

use industry standard practice. Consensus-based standards 
Page 279 of 442 

organizations include, but are not limited to, the 

following: ASTM International (100 Barr Harbor Drive, P.O. 

Box CB700, West Conshohocken, Pennsylvania 19428-B2959, 

(800) 262-1373, http://www.astm.org), the American National 

Standards Institute (ANSI, 1819 L Street, N.W., 6th floor, 

Washington, DC 20036, (202) 293-8020, http://www.ansi.org), 

the American Gas Association (AGA), 400 North Capitol 

Street, N.W., 4th Floor, Washington, DC 20001, (202) 824-

7000, http://www.aga.org), the American Society of 

Mechanical Engineers (ASME, Three Park Avenue, New York, NY 

10016-5990, (800) 843-2763, http://www.asme.org), the 

American Petroleum Institute (API, 1220 L Street, N.W., 

Washington, DC 20005-4070, (202) 682-8000, 

http://www.api.org), and the North American Energy 

Standards Board (NAESB, 801 Travis Street, Suite 1675, 

Houston, TX 77002, (713) 356-0060, http://www.api.org). 

The method(s) used shall be documented in the GHG 

Monitoring Plan required under §98.3(g)(5). 

(v) The following default density values may be used 

for fuel oil, in lieu of using the methods in paragraph 

(a)(3)(iv) of this section: 6.8 lb/gal for No. 1 oil; 7.2 

lb/gal for No. 2 oil; 8.1 lb/gal for No. 6 oil. 

* * * * * 

(4) * * * 
Page 280 of 442 

(iii) If the CO2 concentration is measured on a dry 

basis, a correction for the stack gas moisture content is 

required. You shall either continuously monitor the stack 

gas moisture content using a method described in 

§75.11(b)(2) of this chapter or use an appropriate default 

moisture percentage. For coal, wood, and natural gas 

combustion, you may use the default moisture values 

specified in §75.11(b)(1) of this chapter. Alternatively, 

for any type of fuel, you may determine an appropriate 

site-specific default moisture value (or values), using 

measurements made with EPA Method 4 - Determination Of 

Moisture Content In Stack Gases, in appendix A-3 to part 60 

of this chapter. Moisture data from the relative accuracy 

test audit (RATA) of a CEMS may be used for this purpose. 

If this option is selected, the site-specific moisture 

default value(s) must represent the fuel(s) or fuel blends 

that are combusted in the unit during normal, stable 

operation, and must account for any distinct difference(s) 

in the stack gas moisture content associated with different 

process operating conditions. For each site-specific 

default moisture percentage, at least nine Method 4 runs 

are required, except where the option to use moisture data 

from a RATA is selected, and the applicable regulation 

allows a single moisture determination to represent two or 
Page 281 of 442 

more RATA runs. In that case, you may base the sitespecific moisture percentage on the number of moisture runs 

allowed by the RATA regulation. Calculate each sitespecific default moisture value by taking the arithmetic 

average of the Method 4 runs. Each site-specific moisture 

default value shall be updated whenever the owner or 

operator believes the current value is non-representative, 

due to changes in unit or process operation, but in any 

event no less frequently than annually. Use the updated 

moisture value in the subsequent CO2 emissions calculations. 

For each unit operating hour, a moisture correction must be 

applied to Equation C-6 of this section as follows: 











 −

=

100

100 % 2

2

*

2

H O

CO CO (Eq. C-7) 

Where: 

CO2

* = Hourly CO2 mass emission rate, corrected for 

moisture (metric tons/hr). 

CO2 = Hourly CO2 mass emission rate from Equation C-6 of 

this section, uncorrected (metric tons/hr). 

%H2O = Hourly moisture percentage in the stack gas 

(measured or default value, as appropriate). 

(iv) An oxygen (O2) concentration monitor may be used 

in lieu of a CO2 concentration monitor to determine the 

hourly CO2 concentrations, in accordance with Equation F-14a 

or F-14b (as applicable) in appendix F to part 75 of this 

chapter, if the effluent gas stream monitored by the CEMS 
Page 282 of 442 

consists solely of combustion products (i.e., no process CO2

emissions or CO2 emissions from sorbent are mixed with the 

combustion products) and if only fuels that are listed in 

Table 1 in section 3.3.5 of appendix F to part 75 of this 

chapter are combusted in the unit. If the O2 monitoring 

option is selected, the F-factors used in Equations F-14a 

and F-14b shall be determined according to section 3.3.5 or 

section 3.3.6 of appendix F to part 75 of this chapter, as 

applicable. If Equation F-14b is used, the hourly moisture 

percentage in the stack gas shall be determined in 

accordance with paragraph (a)(4)(iii) of this section. 

* * * * * 

(viii) If a portion of the flue gases generated by a 

unit subject to Tier 4 (e.g., a slip stream) is 

continuously diverted from the main flue gas exhaust system 

for the purpose of heat recovery or some other similar 

process, and then exhausts through a stack that is not 

equipped with the continuous emission monitors to measure 

CO2 mass emissions, CO2 emissions shall be determined as 

follows: 

(A) At least once a year, use EPA Methods 2 and 3A, 

and (if necessary) Method 4 in appendices A-2 and A-3 to 

part 60 of this chapter to perform emissions testing at a 

set point that best represents normal, stable process 
Page 283 of 442 

operating conditions. A minimum of three one-hour Method 

3A tests are required, to determine the CO2 concentration. 

A Method 2 test shall be performed during each Method 3A 

run, to determine the stack gas volumetric flow rate. If 

moisture correction is necessary, a Method 4 run shall also 

be performed during each Method 3A run. Important 

parametric information related to the stack gas flow rate 

(e.g., damper positions, fan settings, etc.) shall also be 

recorded during the test. 

(B) Calculate a CO2 mass emission rate (in metric 

tons/hr) from the stack test data, using a version of 

Equation C-6 in paragraph (a)(4)(ii) of this section, 

modified as follows. In the Equation C-6 nomenclature, 

replace the words “Hourly average” in the definitions of 

“CCO2“ and “Q“ with the words “3-run average”. Substitute 

the arithmetic average values of CO2 concentration and stack 

gas flow rate from the emission testing into modified 

Equation C-6. If CO2 is measured on a dry basis, a 

moisture correction of the calculated CO2 mass emission rate 

is required. Use Equation C-7 in paragraph (a)(4)(ii) of 

this section to make this correction; replace the word 

“Hourly” with the words “3-run average” in the equation 

nomenclature. 
Page 284 of 442 

(C) The results of each annual stack test shall be 

used in the GHG emissions calculations for the year of the 

test. 

(D) If, for the majority of the operating hours 

during the year, the diverted stream is withdrawn at a 

steady rate at or near the tested set point (as evidenced 

by fan and damper settings and/or other parameters), you 

may use the calculated CO2 mass emission rate from paragraph 

(a)(4)(viii)(B) of this section to estimate the CO2 mass 

emissions for all operating hours in which flue gas is 

diverted from the main exhaust system. Otherwise, you must 

account for the variation in the flow rate of the diverted 

stream, as described in paragraph (c)(4)(viii)(E) of this 

section. 

(E) If the flow rate of the diverted stream varies 

significantly throughout the year, except as provided 

below, repeat the stack test and emission rate calculation 

procedures described in paragraphs (c)(4)(viii)(A) and 

(c)(4)(viii)(B) of this section at a minimum of two more 

set points across the range of typical operating conditions 

to develop a correlation between CO2 mass emission rate and 

the parametric data. If additional testing is not 

feasible, use the following approach to develop the 

necessary correlation. Assume that the average CO2
Page 285 of 442 

concentration obtained in the annual stack test is the same 

at all operating set points. Then, beginning with the 

measured flow rate from the stack test and the associated 

parametric data, perform an engineering analysis to 

estimate the stack gas flow rate at two or more additional 

set points. Calculate the CO2 mass emission rate at each 

set point. 

(F) Calculate the annual CO2 mass emissions for the 

diverted stream as follows. For a steady-state process, 

multiply the number of hours in which flue gas was diverted 

from the main exhaust system by the CO2 mass emission rate 

from the stack test. Otherwise, using the best available 

information and engineering judgment, apply the most 

representative CO2 mass emission rate from the correlation 

in paragraph (c)(4)(viii)(E) of this section to determine 

the CO2 mass emissions for each hour in which flue gas was 

diverted, and sum the results. To simplify the 

calculations, you may count partial operating hours as full 

hours. 

(G) Finally, add the CO2 mass emissions from 

paragraph(c)(4)(viii)(F) of this section to the annual CO2

mass emissions measured by the CEMS at the main stack. 

Report this sum as the total annual CO2 mass emissions for 

the unit. 
Page 286 of 442 

(H) The exact method and procedures used to estimate 

the CO2 mass emissions for the diverted portion of the flue 

gas exhaust stream shall be documented in the Monitoring 

Plan required under §98.3(g)(5). 

(5) Alternative methods for certain units subject to 

Part 75 of this chapter. Certain units that are not 

subject to subpart D of this part and that report data to 

EPA according to part 75 of this chapter may qualify to use 

the alternative methods in this paragraph (a)(5), in lieu 

of using any of the four calculation methodology tiers. 

(i) For a unit that combusts only natural gas and/or 

fuel oil, is not subject to subpart D of this part, 

monitors and reports heat input data year-round according 

to appendix D to part 75 of this chapter, but is not 

required by the applicable part 75 program to report CO2

mass emissions data, calculate the annual CO2 mass emissions 

for the purposes of this part as follows: 

(A) Use the hourly heat input data from appendix D to 

part 75 of this chapter, together with Equation G-4 in 

appendix G to part 75 of this chapter to determine the 

hourly CO2 mass emission rates, in units of tons/hr; 

(B) Use Equations F-12 and F-13 in appendix F to part 

75 of this chapter to calculate the quarterly and 
Page 287 of 442 

cumulative annual CO2 mass emissions, respectively, in units 

of short tons; and 

* * * * * 

(ii) For a unit that combusts only natural gas and/or 

fuel oil, is not subject to subpart D of this part, 

monitors and reports heat input data year-round according 

to §75.19 of this chapter but is not required by the 

applicable part 75 program to report CO2 mass emissions 

data, calculate the annual CO2 mass emissions for the 

purposes of this part as follows: 

(A) Calculate the hourly CO2 mass emissions, in units 

of short tons, using Equation LM-11 in §75.19(c)(4)(iii) of 

this chapter. 

* * * * * 

(iii) For a unit that is not subject to subpart D of 

this part, uses flow rate and CO2 (or O2) CEMS to report 

heat input data year-round according to part 75 of this 

chapter, but is not required by the applicable part 75 

program to report CO2 mass emissions data, calculate the 

annual CO2 mass emissions as follows: 

(A) Use Equation F-11 or F-2 (as applicable) in 

appendix F to part 75 of this chapter to calculate the 

hourly CO2 mass emission rates from the CEMS data. If an O2

monitor is used, convert the hourly average O2 readings to 
Page 288 of 442 

CO2 using Equation F-14a or F-14b in appendix F to part 75 

of this chapter (as applicable), before applying Equation 

F-11 or F-2. 

(B) Use Equations F-12 and F-13 in appendix F to part 

75 of this chapter to calculate the quarterly and 

cumulative annual CO2 mass emissions, respectively, in units 

of short tons. 

* * * * * 

(iv) For units that qualify to use the alternative CO2

emissions calculation methods in paragraphs (a)(5)(i) 

through (a)(5)(iii) of this section, if both biomass and 

fossil fuel are combusted during the year, separate 

calculation and reporting of the biogenic CO2 mass emissions 

(as described in paragraph (e) of this section) is 

optional, only for the 2010 reporting year, as provided in 

§98.3(c)(12). 

(b) * * * 

(1) * * * 

(iv) May not be used if you routinely perform fuel 

sampling and analysis for the fuel high heat value (HHV) or 

routinely receive the results of HHV sampling and analysis 

from the fuel supplier at the minimum frequency specified 

in §98.34(a), or at a greater frequency. In such cases, 

Tier 2 shall be used. This restriction does not apply to 
Page 289 of 442 

paragraphs (b)(1)(ii), (b)(1)(v), (b)(1)(vi), and 

(b)(1)(vii) of this section. 

(v) May be used for natural gas combustion in a unit 

of any size, in cases where the annual natural gas 

consumption is obtained from fuel billing records in units 

of therms or mmBtu. 

(vi) May be used for MSW combustion in a small, batch 

incinerator that burns no more than 1,000 tons per year of 

MSW. 

(vii) May be used for the combustion of MSW and/or 

tires in a unit, provided that no more than 10 percent of 

the unit’s annual heat input is derived from those fuels, 

combined. Notwithstanding this requirement, if a unit 

combusts both MSW and tires and the reporter elects not to 

separately calculate and report biogenic CO2 emissions from 

the combustion of tires, Tier 1 may be used for the MSW 

combustion, provided that no more than 10 percent of the 

unit’s annual heat input is derived from MSW. 

(2) * * * 

(ii) May be used in a unit with a maximum rated heat 

input capacity greater than 250 mmBtu/hr for the combustion 

of natural gas and/or distillate fuel oil. 

* * * * * 

(3) * * * 
Page 290 of 442 

(ii) * * * 

(A) The use of Tier 1 or 2 is permitted, as described 

in paragraphs (b)(1)(iii), (b)(1)(v), and (b)(2)(ii) of 

this section. 

* * * * * 

(iii) Shall be used for a fuel not listed in Table C1 of this subpart if the fuel is combusted in a unit with a 

maximum rated heat input capacity greater than 250 mmBtu/hr 

(or, pursuant to §98.36(c)(3), in a group of units served 

by a common supply pipe, having at least one unit with a 

maximum rated heat input capacity greater than 250 

mmBtu/hr), provided that both of the following conditions 

apply: 

* * * * * 

(B) The fuel provides 10% or more of the annual heat 

input to the unit or, if §98.36(c)(3)applies, to the group 

of units served by a common supply pipe. 

(iv) Shall be used when specified in another 

applicable subpart of this part, regardless of unit size. 

(4) * * * 

(i) * * * Tier 4 may also be used for any 

group of stationary fuel combustion units, process units, 

or manufacturing units that share a common stack or duct. 

(ii) * * * 
Page 291 of 442 

(A) The unit has a maximum rated heat input capacity 

greater than 250 mmBtu/hr, or if the unit combusts 

municipal solid waste and has a maximum rated input 

capacity greater than 600 tons per day of MSW. 

(B) The unit combusts solid fossil fuel or MSW as the 

primary fuel. 

* * * * * 

(E) The installed CEMS include a gas monitor of any 

kind or a stack gas volumetric flow rate monitor, or both 

and the monitors have been certified, either in accordance 

with the requirements of part 75 of this chapter, part 60 

of this chapter, or an applicable State continuous 

monitoring program. 

(F) The installed gas or stack gas volumetric flow 

rate monitors are required, either by an applicable Federal 

or State regulation or by the unit’s operating permit, to 

undergo periodic quality assurance testing in accordance 

with either appendix B to part 75 of this chapter, appendix 

F to part 60 of this chapter, or an applicable State 

continuous monitoring program. 

(iii) Shall be used for a unit with a maximum rated 

heat input capacity of 250 mmBtu/hr or less and for a unit 

that combusts municipal solid waste with a maximum rated 
Page 292 of 442 

input capacity of 600 tons of MSW per day or less, if the 

unit meets all of the following three conditions: 

* * * * * 

(iv) May apply to common stack or duct configurations 

where: 

(A) The combined effluent gas streams from two or 

more stationary fuel combustion units are vented through a 

monitored common stack or duct. In this case, Tier 4 shall 

be used if all of the conditions in paragraph 

(b)(4)(iv)(A)(1) of this section or if the conditions in 

paragraph (b)(4)(iv)(A)(2) of this section are met. 

(1) At least one of the units meets the requirements 

of paragraphs (b)(4)(ii)(A) through (b)(4)(ii)(C) of this 

section, and the CEMS installed at the common stack (or 

duct) meet the requirements of paragraphs (b)(4)(ii)(D) 

through (b)(4)(ii)(F) of this section. 

(2) At least one of the units and the monitors 

installed at the common stack or duct meet the requirements 

of paragraph (b)(4)(iii) of this section. 

(B) The combined effluent gas streams from a process 

or manufacturing unit and a stationary fuel combustion unit 

are vented through a monitored common stack or duct. In 

this case, Tier 4 shall be used if the combustion unit and 

the monitors installed at the common stack or duct meet the 
Page 293 of 442 

applicability criteria specified in paragraph 

(b)(4)(iv)(A)(1), or (b)(4)(iv)(A)(2) of this section. 

(C) The combined effluent gas streams from two or 

more manufacturing or process units are vented through a 

common stack or duct. In this case, if any of the units is 

required by an applicable subpart of this part to use Tier 

4, the CO2 mass emissions may be monitored at each 

individual unit, or the combined CO2 mass emissions may be 

monitored at the common stack or duct. However, if it is 

not feasible to monitor the individual units, the combined 

CO2 mass emissions shall be monitored at the common stack or 

duct. 

(5) The Tier 4 Calculation Methodology shall be used: 

(i) Starting on January 1, 2010, for a unit that is 

required to report CO2 mass emissions beginning on that 

date, if all of the monitors needed to measure CO2 mass 

emissions have been installed and certified by that date. 

(ii) No later than January 1, 2011, for a unit that 

is required to report CO2 mass emissions beginning on 

January 1, 2010, if all of the monitors needed to measure 

CO2 mass emissions have not been installed and certified by 

January 1, 2010. In this case, you may use Tier 2 or Tier 

3 to report GHG emissions for 2010. However, if the 

required CEMS are certified some time in 2010, you need not 
Page 294 of 442 

wait until January 1, 2011 to begin using Tier 4. Rather, 

you may switch from Tier 2 or Tier 3 to Tier 4 as soon as 

CEMS certification testing is successfully completed. If 

this reporting option is chosen, you must document the 

change in CO2 calculation methodology in the Monitoring Plan 

required under §98.3(g)(5) and in the GHG emissions report 

under §98.3(c). Data recorded by the CEMS during a 

certification test period in 2010 may be used for reporting 

under this part, provided that the following two conditions 

are met: 

(A) The certification tests are passed in sequence, 

with no test failures. 

(B) No unscheduled maintenance or repair of the CEMS 

is performed during the certification test period. 

(iii) No later than 180 days following the date on 

which a change is made that triggers Tier 4 applicability 

under paragraph (b)(4)(ii) or (b)(4)(iii) of this section 

(e.g., a change in the primary fuel, manner of unit 

operation, or installed continuous monitoring equipment). 

(6) * * * However, for units that use either 

the Tier 4 or the alternative calculation methodology 

specified in paragraph (a)(5)(iii) of this section, CO2

emissions from the combustion of all fuels shall be based 

solely on CEMS measurements. 
Page 295 of 442 

(c) * * * 

(1) Use Equation C-8 of this section to estimate CH4

and N2O emissions for any fuels for which you use the Tier 1 

or Tier 3 calculation methodologies for CO2, except when 

natural gas usage in units of therms or mmBtu is obtained 

from gas billing records. In that case, use Equation C-8a 

in paragraph (c)(1)(i) of this section or Equation C-8b in 

paragraph (c)(1)(ii) of this section (as applicable). For 

Equation C-8, use the same values for fuel consumption that 

you use for the Tier 1 or Tier 3 calculation. 

* * * * * 

HHV = Default high heat value of the fuel from Table 

C-1 of this subpart; alternatively, for Tier 3, 

if actual HHV data are available for the 

reporting year, you may average these data using 

the procedures specified in paragraph (a)(2)(ii) 

of this section, and use the average value in 

Equation C-8 (mmBtu per mass or volume). 

* * * * * 

(i) Use Equation C-8a to calculate CH4 and N2O 

emissions when natural gas usage is obtained from gas 

billing records in units of therms. 

CH or N O 1 x 10 * Fuel * 0.1* EF 3

4 2

−

= (Eq. C-8a) 

Where: 

CH4 or N2O = Annual CH4 or N2O emissions from the 

combustion of natural gas (metric tons). 

Fuel = Annual natural gas usage, from gas billing 

records (therms). 
Page 296 of 442 

EF = Fuel-specific default emission factor for CH4

or N2O, from Table C-2 of this subpart (kg CH4

or N2O per mmBtu). 

0.1 = Conversion factor from therms to mmBtu 

1 x 10-3 = Conversion factor from kilograms to metric 

tons. 

(ii) Use Equation C-8b to calculate CH4 and N2O 

emissions when natural gas usage is obtained from gas 

billing records in units of mmBtu. 

CH or N O 1 x 10 * Fuel * EF 3

4 2

−

= (Eq. C-8b) 

Where: 

CH4 or N2O = Annual CH4 or N2O emissions from the 

combustion of natural gas (metric tons). 

Fuel = Annual natural gas usage, from gas billing 

records (mmBtu). 

EF = Fuel-specific default emission factor for CH4

or N2O, from Table C-2 of this subpart (kg CH4

or N2O per mmBtu). 

1 x 10-3 = Conversion factor from kilograms to metric 

tons. 

(2) * * * Use the same values for fuel 

consumption and HHV that you use for the Tier 2 

calculation. 

* * * * * 

(4) Use Equation C-10 of this section for: units 

subject to subpart D of this part; units that qualify for 

and elect to use the alternative CO2 mass emissions 

calculation methodologies described in paragraph (a)(5) of 
Page 297 of 442 

this section; and units that use the Tier 4 Calculation 

Methodology. 

* * * * * 

(HI)A = Cumulative annual heat input from combustion 

of the fuel (mmBtu). 

* * * * * 

(i) If only one type of fuel listed in Table C-2 of 

this subpart is combusted during the reporting year, 

substitute the cumulative annual heat input from combustion 

of the fuel into Equation C-10 of this section to calculate 

the annual CH4 or N2O emissions. For units in the Acid Rain 

Program and units that report heat input data to EPA yearround according to part 75 of this chapter, obtain the 

cumulative annual heat input directly from the electronic 

data reports required under §75.64 of this chapter. For 

Tier 4 units, use the best available information, as 

described in paragraph (c)(4)(ii)(C) of this section, to 

estimate the cumulative annual heat input (HI)A. 

(ii) If more than one type of fuel listed in Table C2 of this subpart is combusted during the reporting year, 

use Equation C-10 of this section separately for each type 

of fuel, except as provided in paragraph (c)(4)(ii)(B) of 

this section. Determine the appropriate values of (HI)A as 

follows: 
Page 298 of 442 

(A) For units in the Acid Rain Program and other 

units that report heat input data to EPA year-round 

according to part 75 of this chapter, obtain (HI)A for each 

type of fuel from the electronic data reports required 

under §75.64 of this chapter, except as otherwise provided 

in paragraphs (c)(4)(ii)(B) and (c)(4)(ii)(D) of this 

section. 

(B) For a unit that uses CEMS to monitor hourly heat 

input according to part 75 of this chapter, the value of 

(HI)A obtained from the electronic data reports under §75.64 

of this chapter may be attributed exclusively to the fuel 

with the highest F-factor, when the reporting option in 

3.3.6.5 of appendix F to part 75 of this chapter is 

selected and implemented. 

(C) For Tier 4 units, use the best available 

information (e.g., fuel feed rate measurements, fuel 

heating values, engineering analysis) to estimate the value 

of (HI)A for each type of fuel. Instrumentation used to 

make these estimates is not subject to the calibration 

requirements of §98.3(i) or to the QA requirements of 

§98.34. 

(D) Units in the Acid Rain Program and other units 

that report heat input data to EPA year-round according to 

part 75 of this chapter may use the best available 
Page 299 of 442 

information described in paragraph (c)(4)(ii)(C) of this 

section, to estimate (HI)A for each fuel type, whenever 

fuel-specific heat input values cannot be directly obtained 

from the electronic data reports under §75.64 of this 

chapter. 

(5) When multiple fuels are combusted during the 

reporting year, sum the fuel-specific results from 

Equations C-8, C-8a, C-8b, C-9a, C-9b, or C-10 of this 

section (as applicable) to obtain the total annual CH4 and 

N2O emissions, in metric tons. 

(6) Calculate the annual CH4 and N2O mass emissions 

from the combustion of blended fuels as follows: 

(i) If the mass or volume of each component fuel in 

the blend is measured before the fuels are mixed and 

combusted, calculate and report CH4 and N2O emissions 

separately for each component fuel, using the applicable 

procedures in this paragraph (c). 

(ii) If the mass or volume of each component fuel in 

the blend is not measured before the fuels are mixed and 

combusted, a reasonable estimate of the percentage 

composition of the blend, based on best available 

information, is required. Perform the following 

calculations for each component fuel “i” that is listed in 

Table C-2: 
Page 300 of 442 

(A) Multiply (% Fuel)i, the estimated mass or volume 

percentage (decimal fraction) of component fuel “i”, by the 

total annual mass or volume of the blended fuel combusted 

during the reporting year, to obtain an estimate of the 

annual consumption of component “i”; 

(B) Multiply the result from paragraph (c)(6)(ii)(A) 

of this section by the HHV of the fuel (default value or, 

if available, the measured annual average value), to obtain 

an estimate of the annual heat input from component “i”; 

(C) Calculate the annual CH4 and N2O emissions from 

component “i”, using Equation C-8, C-8a, C-8b, C-9a, or C10 of this section, as applicable; 

(D) Sum the annual CH4 emissions across all component 

fuels to obtain the annual CH4 emissions for the blend. 

Similarly sum the annual N2O emissions across all component 

fuels to obtain the annual N2O emissions for the blend. 

Report these annual emissions totals. 

(d) * * * 

(1) When a unit is a fluidized bed boiler, is 

equipped with a wet flue gas desulfurization system, or 

uses other acid gas emission controls with sorbent 

injection to remove acid gases, if the chemical reaction 

between the acid gas and the sorbent produces CO2 emissions, 

use Equation C-11 of this section to calculate the CO2
Page 301 of 442 

emissions from the sorbent, except when those CO2 emissions 

are monitored by CEMS. When a sorbent other than CaCO3 is 

used, determine site-specific values of R and MWS. 

* * * * * 

R = The number of moles of CO2 released upon capture of 

one mole of the acid gas species being removed (R = 

1.00 when the sorbent is CaCO3 and the targeted 

acid gas species is SO2). 

* * * * * 

(2) The total annual CO2 mass emissions reported for 

the unit shall include the CO2 emissions from the combustion 

process and the CO2 emissions from the sorbent. 

(e) Biogenic CO2 emissions from combustion of biomass 

with other fuels. Use the applicable procedures of this 

paragraph (e) to estimate biogenic CO2 emissions from units 

that combust a combination of biomass and fossil fuels 

(i.e., either co-fired or blended fuels). Separate 

reporting of biogenic CO2 emissions from the combined 

combustion of biomass and fossil fuels is required for 

those biomass fuels listed in Table C-1 of this section and 

for municipal solid waste. In addition, when a biomass 

fuel that is not listed in Table C-1 is combusted in a unit 

that has a maximum rated heat input greater than 250 

mmBtu/hr, if the biomass fuel accounts for 10% or more of 

the annual heat input to the unit, and if the unit does not 
Page 302 of 442 

use CEMS to quantify its annual CO2 mass emissions, then, 

pursuant to §98.33(b)(3)(iii), Tier 3 must be used to 

determine the carbon content of the biomass fuel and to 

calculate the biogenic CO2 emissions from combustion of the 

fuel. Notwithstanding these requirements, in accordance 

with §98.3(c)(12), separate reporting of biogenic CO2

emissions is optional for the 2010 reporting year for units 

subject to subpart D of this part and for units that use 

the CO2 mass emissions calculation methodologies in part 75 

of this chapter, pursuant to paragraph (a)(5) of this 

section. However, if the owner or operator opts to report 

biogenic CO2 emissions separately for these units, the 

appropriate method(s) in this paragraph (e) shall be used. 

Separate reporting of biogenic CO2 emissions from the 

combustion of tires is also optional, but may be reported 

by following the provisions of paragraph (e)(3) of this 

section. 

(1) You may use Equation C-1 of this subpart to 

calculate the annual CO2 mass emissions from the combustion 

of the biomass fuels listed in Table C-1 of this subpart 

(except MSW and tires), in a unit of any size, including 

units equipped with a CO2 CEMS, except when the use of Tier 

2 is required as specified in paragraph (b)(1)(iv) of this 

section. Determine the quantity of biomass combusted using 
Page 303 of 442 

one of the following procedures in this paragraph (e)(1), 

as appropriate, and document the selected procedures in the 

Monitoring Plan under §98.3(g): 

(i) Company records. 

(ii) The procedures in paragraph (e)(5) of this 

section. 

(iii) The best available information for premixed 

fuels that contain biomass and fossil fuels (e.g., liquid 

fuel mixtures containing biodiesel). 

(2) You may use the procedures of this paragraph if 

the following three conditions are met: first, a CO2 CEMS 

(or a surrogate O2 monitor) and a stack gas flow rate 

monitor are used to determine the annual CO2 mass emissions 

(either according to part 75 of this chapter, the Tier 4 

Calculation Methodology, or the alternative calculation 

methodology specified in paragraph (a)(5)(iii) of this 

section); second, neither MSW nor tires is combusted in 

the unit during the reporting year; and third, the CO2

emissions consist solely of combustion products (i.e., no 

process or sorbent emissions included). 

* * * * * 

(iii) * * * * * 

Fc = Fuel-specific carbon based F-factor, either a 

default value from Table 1 in section 3.3.5 of 

appendix F to part 75 of this chapter, or a site-
Page 304 of 442 

specific value determined under section 3.3.6 of 

appendix F to part 75 (scf CO2/mmBtu). 

* * * * * 

(iv) Subtract Vff from Vtotal to obtain Vbio, the annual 

volume of CO2 from the combustion of biomass. 

* * * * * 

(vi) * * * 

(C) From the electronic data report required under 

§75.64 of this chapter, for units in the Acid Rain Program 

and other units using CEMS to monitor and report CO2 mass 

emissions according to part 75 of this chapter. However, 

before calculating the annual biogenic CO2 mass emissions, 

multiply the cumulative annual CO2 mass emissions by 0.91 to 

convert from short tons to metric tons. 

(3) You must use the procedures in paragraphs 

(e)(3)(i) through (e)(3)(iii) of this section to determine 

the annual biogenic CO2 emissions from the combustion of 

MSW, except as otherwise provided in paragraph (e)(3)(iv) 

of this section. These procedures also may be used for any 

unit that co-fires biomass and fossil fuels, including 

units equipped with a CO2 CEMS, and units for which optional 

separate reporting of biogenic CO2 emissions from the 

combustion of tires is selected. 
Page 305 of 442 

(i) Use an applicable CO2 emissions calculation method 

in this section to quantify the total annual CO2 mass 

emissions from the unit. 

(ii) Determine the relative proportions of biogenic 

and non-biogenic CO2 emissions in the flue gas on a 

quarterly basis using the method specified in §98.34(d) 

(for units that combust MSW as the primary fuel or as the 

only fuel with a biogenic component) or in §98.34(e) (for 

other units, including units that combust tires). 

(iii) Determine the annual biogenic CO2 mass emissions 

from the unit by multiplying the total annual CO2 mass 

emissions by the annual average biogenic decimal fraction 

obtained from §98.34(d) or §98.34(e), as applicable. 

(iv) If the combustion of MSW and/or tires provides 

no more than 10 percent of the annual heat input to a unit, 

or if a small, batch incinerator combusts no more than 

1,000 tons per year of MSW, you may estimate the annual 

biogenic CO2 emissions as follows, in lieu of following the 

procedures in paragraphs (e)(3)(i) through (e)(3)(iii) of 

this section: 

(A) Calculate the total annual CO2 emissions from 

combustion of MSW and/or tires in the unit, using the Tier 

1 calculation methodology in paragraph (a)(1) of this 

section. 
Page 306 of 442 

(B) Multiply the result from paragraph (e)(3)(iv)(A) 

of this section by the appropriate default factor to 

determine the annual biogenic CO2 emissions, in metric tons. 

For MSW, use a default factor of 0.60 and for tires, use a 

default factor of 0.20. 

(4) If Equation C-1 or Equation C-2a of this section 

is selected to calculate the annual biogenic mass emissions 

for wood, wood waste, or other solid biomass-derived fuel, 

Equation C-15 of this section may be used to quantify 

biogenic fuel consumption, provided that all of the 

required input parameters are accurately quantified. *

* * 

(5) For units subject to subpart D of this part and 

for units that use the methods in part 75 of this chapter 

to quantify CO2 mass emissions in accordance with paragraph 

(a)(5) of this section, you may calculate biogenic CO2

emissions from the combustion of biomass fuels listed in 

Table C-1 of this subpart using Equation C-15a. This 

equation may not be used to calculate biogenic CO2 emissions 

from the combustion of tires or MSW; the methods described 

in paragraph (e)(3) of this section must be used for those 

fuels. Whenever (HI)A, the annual heat input from 

combustion of biomass fuel in Equation C-15a, cannot be 

determined solely from the information in the electronic 
Page 307 of 442 

emissions reports under §75.64 of this chapter (e.g., in 

cases where a unit uses CEMS in combination with multiple 

F-factors, a worst-case F-factor, or a prorated F-factor to 

report heat input rather than reporting heat input based on 

fuel type), use the best available information (as 

described in §§98.33(c)(4)(ii)(C) and (c)(4)(ii)(D)) to 

determine (HI)A. 

CO2 = 0.001* (HI) A* EF (Eq. C-15a) 

Where: 

CO2 = Annual CO2 mass emissions from the combustion of a 

particular type of biomass fuel listed in Table 

C-1 (metric tons) 

(HI)A = Annual heat input from the biomass fuel, 

obtained, where feasible, from the electronic 

emissions reports required under §75.64 of this 

chapter. Where this is not feasible use best 

available information, as described in 

§§98.33(c)(4)(ii)(C) and (c)(4)(ii)(D) (mmBtu) 

EF = CO2 emission factor for the biomass fuel, from 

Table C-1 (kg CO2/mmBtu) 

0.001 = Conversion factor from kg to metric tons 

* * * * * 

10. Section 98.34 is amended by: 

a. Revising paragraphs (a)(2), (a)(3), (a)(6), (b)(1) 

introductory text, (b)(1)(i), (b)(1)(ii), (b)(1)(iii), 

(b)(1)(vi), (b)(3)(ii), and (b)(3)(v). 

b. Removing paragraph (b)(4). 

c. Redesignating paragraph (b)(5) as (b)(4). 
Page 308 of 442 

d. Revising newly designated paragraph (b)(4). 

e. Revising paragraphs (c) introductory text, 

(c)(1)(i), (c)(1)(ii), (c)(2), (c)(3), and (c)(4). 

f. Adding paragraphs (c)(6) and (c)(7). 

g. Revising paragraphs (d), (e), (f) introductory 

text, (f)(1), (f)(3), (f)(5), and (f)(6). 

h. Adding paragraphs (f)(7) and (f)(8). 

i. Removing paragraph (g). 

§98.34 Monitoring and QA/QC requirements.

* * * * * 

(a) * * * 

(2) The minimum required frequency of the HHV 

sampling and analysis for each type of fuel or fuel mixture 

(blend) is specified in this paragraph. When the specified 

frequency for a particular fuel or blend is based on a 

specified time period (e.g., week, month, quarter, or halfyear), fuel sampling and analysis is required only for 

those time periods in which the fuel or blend is combusted. 

The owner or operator may perform fuel sampling and 

analysis more often than the minimum required frequency, in 

order to obtain a more representative annual average HHV. 
Page 309 of 442 

(i) For natural gas, semiannual sampling and analysis 

is required (i.e., twice in a calendar year, with 

consecutive samples taken at least four months apart). 

(ii) For coal and fuel oil, and for any other solid 

or liquid fuel that is delivered in lots, analysis of at 

least one representative sample from each fuel lot is 

required. For fuel oil, as an alternative to sampling each 

fuel lot, a sample may be taken upon each addition of oil 

to the unit’s storage tank. Flow proportional sampling, 

continuous drip sampling, or daily manual oil sampling may 

also be used, in lieu of sampling each fuel lot. If the 

daily manual oil sampling option is selected, sampling from 

a particular tank is required only on days when oil from 

the tank is combusted by the unit (or units) served by the 

tank. If you elect to sample from the storage tank upon 

each addition of oil to the tank, you must take at least 

one sample from each tank that is currently in service and 

whenever oil is added to the tank, for as long as the tank 

remains in service. You need not take any samples from a 

storage tank while it is out of service. Rather, take a 

sample when the tank is brought into service and whenever 

oil is added to the tank, for as long as the tank remains 

in service. If multiple additions of oil are made to a 

particular in-service tank on a given day (e.g., from 
Page 310 of 442 

multiple deliveries), one sample taken after the final 

addition of oil is sufficient. For the purposes of this 

section, a fuel lot is defined as a shipment or delivery of 

a single type of fuel (e.g., ship load, barge load, group 

of trucks, group of railroad cars, oil delivery via 

pipeline from a tank farm, etc.). However, if multiple 

deliveries of a particular type of fuel are received from 

the same supply source in a given calendar month, the 

deliveries for that month may be considered, collectively, 

to comprise a fuel lot, requiring only one representative 

sample, subject to the following conditions: 

(A) For coal, the “type” of fuel means the rank of 

the coal (i.e., anthracite, bituminous, sub-bituminous, or 

lignite). For fuel oil, the “type” of fuel means the grade 

number or classification of the oil (e.g., No. 1 oil, No. 2 

oil, kerosene, Jet A fuel, etc.). 

(B) The owner or operator shall document in the 

monitoring plan under §98.3(g)(5) how the monthly sampling 

of each type of fuel is performed. 

(iii) For liquid fuels other than fuel oil, and for 

gaseous fuels other than natural gas (including biogas), 

sampling and analysis is required at least once per 

calendar quarter. To the extent practicable, consecutive 

quarterly samples shall be taken at least 30 days apart. 
Page 311 of 442 

(iv) For other solid fuels (except MSW), weekly 

sampling is required to obtain composite samples, which are 

then analyzed monthly. 

(v) For fuel blends that are received already mixed, 

or that are mixed on-site without measuring the exact 

amount of each component, as described in paragraph 

(a)(3)(ii) of this section, determine the HHV of the blend 

as follows. For blends of solid fuels (except MSW), weekly 

sampling is required to obtain composite samples, which are 

analyzed monthly. For blends of liquid or gaseous fuels, 

sampling and analysis is required at least once per 

calendar quarter. More frequent sampling is recommended if 

the composition of the blend varies significantly during 

the year. 

(3) Special considerations for blending of fuels. In 

situations where different types of fuel listed in Table C1 of this subpart (for example, different ranks of coal or 

different grades of fuel oil) are in the same state of 

matter (i.e., solid, liquid, or gas), and are blended prior 

to combustion, use the following procedures to determine 

the appropriate CO2 emission factor and HHV for the blend. 

(i) If the fuels to be blended are received 

separately, and if the quantity (mass or volume) of each 

fuel is measured before the fuels are mixed and combusted, 
Page 312 of 442 

then, for each component of the blend, calculate the CO2

mass emissions separately. Substitute into Equation C-2a 

of this subpart the total measured mass or volume of the 

component fuel (from company records), together with the 

appropriate default CO2 emission factor from Table C-1, and 

the annual average HHV, calculated according to 

§98.33(a)(2)(ii). In this case, the fact that the fuels 

are blended prior to combustion is of no consequence. 

(ii) If the fuel is received as a blend (i.e., 

already mixed) or if the components are mixed on site 

without precisely measuring the mass or volume of each one 

individually, a reasonable estimate of the relative 

proportions of the components of the blend must be made, 

using the best available information (e.g., the approximate 

annual average mass or volume percentage of each fuel, 

based on the typical or expected range of values). 

Determine the appropriate CO2 emission factor and HHV for 

use in Equation C-2a of this subpart, as follows: 

(A) Consider the blend to be the “fuel type,” measure 

its HHV at the frequency prescribed in paragraph (a)(2)(v) 

of this section, and determine the annual average HHV value 

for the blend according to §98.33(a)(2)(ii). 

(B) Calculate a heat-weighted CO2 emission factor, 

(EF)B, for the blend, using Equation C-16 of this section. 
Page 313 of 442 

The heat-weighting in Equation C-16 is provided by the 

default HHVs (from Table C-1) and the estimated mass or 

volume percentages of the components of the blend. 

(C) Substitute into Equation C-2a of this subpart, 

the annual average HHV for the blend (from paragraph 

(a)(3)(ii)(A) of this section) and the calculated value of 

(EF)B, along with the total mass or volume of the blend 

combusted during the reporting year, to determine the 

annual CO2 mass emissions from combustion of the blend. 

[ ( ) ]

B

n

i

i i i

B HHV

HHV Fuel EF

EF

( )

( ) % ( )

( )

1

∑= =

(Eq. C-16) 

Where: 

(EF)B = Heat-weighted CO2 emission factor for the blend 

(kg CO2/mmBtu) 

(HHV)i = Default high heat value for fuel “i” in the 

blend, from Table C-1 (mmBtu per mass or 

volume) 

(%Fuel)i = Estimated mass or volume percentage of fuel “i” 

(mass % or volume %, as applicable, expressed 

as a decimal fraction; e.g., 25% = 0.25) 

(EF)i = Default CO2 emission factor for fuel “i” from 

Table C-1 (mmBtu per mass or volume) 

(HHV)B = Annual average high heat value for the blend, 

calculated according to §98.33(a)(2)(ii) (mmBtu 

per mass or volume) 

(iii) Note that for the case described in paragraph 

(a)(3)(ii) of this section, if measured HHV values for the 
Page 314 of 442 

individual fuels in the blend or for the blend itself are 

not routinely received at the minimum frequency prescribed 

in paragraph (a)(2) of this section (or at a greater 

frequency), and if the unit qualifies to use Tier 1, 

calculate (HHV)B

*, the heat-weighted default HHV for the 

blend, using Equation C-17 of this section. Then, use 

Equation C-16 of this section, replacing the term (HHV)B

with (HHV)B

* in the denominator, to determine the heatweighted CO2 emission factor for the blend. Finally, 

substitute into Equation C-1 of this subpart, the 

calculated values of (HHV)B

* and (EF)B, along with the total 

mass or volume of the blend combusted during the reporting 

year, to determine the annual CO2 mass emissions from 

combustion of the blend. 

∑[ ( ) ]

=

=

n

i

B i F i HHV HHV uel

1

*

( ) %

(Eq. C-17) 

Where: 

(HHV)B

* = Heat-weighted default high heat value for the 

blend (mmBtu per mass or Volume) 

(HHV)i = Default high heat value for fuel “i” in the 

blend, from Table C-1 (mmBtu per mass or 

volume) 

(%Fuel)i = Estimated mass or volume percentage of fuel “i” 

in the blend (mass % or volume %, as 

applicable, expressed as a decimal fraction) 
Page 315 of 442 

(iv) If the fuel blend described in paragraph 

(a)(3)(ii) of this section consists of a mixture of fuel(s) 

listed in Table C-1 of this subpart and one or more fuels 

not listed in Table C-1, calculate CO2 and other GHG 

emissions only for the Table C-1 fuel(s), using the best 

available estimate of the mass or volume percentage(s) of 

the Table C-1 fuel(s) in the blend. In this case, Tier 1 

shall be used, with the following modifications to 

Equations C-17 and C-1, to account for the fact that not 

all of the fuels in the blend are listed in Table C-1: 

(A) In Equation C-17, apply the term (Fuel)i only to 

the Table C-1 fuels. For each Table C-1 fuel, (Fuel)i will 

be the estimated mass or volume percentage of the fuel in 

the blend, divided by the sum of the mass or volume 

percentages of the Table C-1 fuels. For example, suppose 

that a blend consists of two Table C-1 fuels (“A” and “B”) 

and one fuel type (“C”) not listed in the Table, and that 

the volume percentages of fuels A, B, and C in the blend, 

expressed as decimal fractions, are, respectively, 0.50, 

0.30, and 0.20. The term (Fuel)i in Equation C-17 for fuel 

A will be 0.50/(0.50 + 0.30) = 0.625, and for fuel B, 

(Fuel)i will be 0.30/(0.50 + 0.30) = 0.375. 

(B) In Equation C-1, the term “Fuel” will be equal to 

the total mass or volume of the blended fuel combusted 
Page 316 of 442 

during the year multiplied by the sum of the mass or volume 

percentages of the Table C-1 fuels in the blend. For the 

example in paragraph (a)(3)(iv)(A) of this section, “Fuel” 

= (Annual volume of the blend combusted)(0.80). 

* * * * * 

(6) You must use one of the following appropriate 

fuel sampling and analysis methods. The HHV may be 

calculated using chromatographic analysis together with 

standard heating values of the fuel constituents, provided 

that the gas chromatograph is operated, maintained, and 

calibrated according to the manufacturer’s instructions. 

Alternatively, you may use a method published by a 

consensus-based standards organization if such a method 

exists, or you may use industry standard practice to 

determine the high heat values. Consensus-based standards 

organizations include, but are not limited to, the 

following: ASTM International (100 Barr Harbor Drive, P.O. 

Box CB700, West Conshohocken, Pennsylvania 19428-B2959, 

(800) 262-1373, http://www.astm.org), the American National 

Standards Institute (ANSI, 1819 L Street, N.W., 6th floor, 

Washington, DC 20036, (202) 293-8020, http://www.ansi.org), 

the American Gas Association (AGA, 400 North Capitol 

Street, N.W., 4th Floor, Washington, DC 20001, (202) 824-

7000, http://www.aga.org), the American Society of 
Page 317 of 442 

Mechanical Engineers (ASME, Three Park Avenue, New York, NY 

10016-5990, (800) 843-2763, http://www.asme.org), the 

American Petroleum Institute (API, 1220 L Street, N.W., 

Washington, DC 20005-4070,(202) 682-8000, 

http://www.api.org), and the North American Energy 

Standards Board (NAESB, 801 Travis Street, Suite 1675, 

Houston, TX 77002, (713) 356-0060, http://www.api.org) . 

The method(s) used shall be documented in the Monitoring 

Plan required under §98.3(g)(5). 

(b) * * * 

(1) You must calibrate each oil and gas flow meter 

according to §98.3(i) and the provisions of this paragraph 

(b)(1). 

(i) Perform calibrations using any of the test 

methods and procedures in this paragraph (b)(1)(i). The 

method(s) used shall be documented in the Monitoring Plan 

required under §98.3(g)(5). 

(A) You may use the calibration procedures specified 

by the flow meter manufacturer. 

(B) You may use an appropriate flow meter calibration 

method published by a consensus-based standards 

organization, if such a method exists. Consensus-based 

standards organizations include, but are not limited to, 

the following: ASTM International (100 Barr Harbor Drive, 
Page 318 of 442 

P.O. Box CB700, West Conshohocken, Pennsylvania 19428-

B2959, (800) 262-1373, http://www.astm.org), the American 

National Standards Institute (ANSI, 1819 L Street, N.W., 

6th floor, Washington, DC 20036, (202) 293-8020, 

http://www.ansi.org), the American Gas Association (AGA, 

400 North Capitol Street, N.W., 4th Floor, Washington, DC 

20001, (202) 824-7000, http://www.aga.org), the American 

Society of Mechanical Engineers (ASME, Three Park Avenue, 

New York, NY 10016-5990, (800) 843-2763, 

http://www.asme.org), the American Petroleum Institute 

(API, 1220 L Street, N.W., Washington, DC 20005-4070,(202) 

682-8000, http://www.api.org), and the North American 

Energy Standards Board (NAESB, 801 Travis Street, Suite 

1675, Houston, TX 77002, (713) 356-0060, 

http://www.api.org). 

(C) You may use an industry-accepted practice. 

(ii) In addition to the initial calibration required 

by §98.3(i), recalibrate each fuel flow meter (except as 

otherwise provided in paragraph (b)(1)(iii) of this 

section) according to one of the following. You may 

recalibrate annually, at the minimum frequency specified by 

the manufacturer, or at the interval specified by industry 

standard practice. 
Page 319 of 442 

(iii) Fuel billing meters are exempted from the 

initial and ongoing calibration requirements of this 

paragraph and from the Monitoring Plan and recordkeeping 

requirements of §§98.3(g)(5)(i)(C), (g)(6), and (g)(7), 

provided that the fuel supplier and the unit combusting the 

fuel do not have any common owners and are not owned by 

subsidiaries or affiliates of the same company. Meters 

used exclusively to measure the flow rates of fuels that 

are only used for unit startup are also exempted from the 

initial and ongoing calibration requirements of this 

paragraph. 

* * * * * 

(vi) If a mixture of liquid or gaseous fuels is 

transported by a common pipe, you may either separately 

meter each of the fuels prior to mixing, using flow meters 

calibrated according to §98.3(i), or consider the fuel 

mixture to be the “fuel type” and meter the mixed fuel, 

using a flow meter calibrated according to §98.3(i). 

* * * * * 

(3) * * * 

(ii) For each type of fuel, the minimum required 

frequency for collecting and analyzing samples for carbon 

content and (if applicable) molecular weight is specified 

in this paragraph. When the sampling frequency is based on 
Page 320 of 442 

a specified time period (e.g., week, month, quarter, or 

half-year), fuel sampling and analysis is required for only 

those time periods in which the fuel is combusted. 

(A) For natural gas, semiannual sampling and analysis 

is required (i.e., twice in a calendar year, with 

consecutive samples taken at least four months apart). 

(B) For coal and fuel oil and for any other solid or 

liquid fuel that is delivered in lots, analysis of at least 

one representative sample from each fuel lot is required. 

For fuel oil, as an alternative to sampling each fuel lot, 

a sample may be taken upon each addition of oil to the 

storage tank. Flow proportional sampling, continuous drip 

sampling, or daily manual oil sampling may also be used, in 

lieu of sampling each fuel lot. If the daily manual oil 

sampling option is selected, sampling from a particular 

tank is required only on days when oil from the tank is 

combusted by the unit (or units) served by the tank. If 

you elect to sample from the storage tank upon each 

addition of oil to the tank, you must take at least one 

sample from each tank that is currently in service and 

whenever oil is added to the tank, for as long as the tank 

remains in service. You need not take any samples from a 

storage tank while it is out of service. Rather, take a 

sample when the tank is brought into service and whenever 
Page 321 of 442 

oil is added to the tank, for as long as the tank remains 

in service. If multiple additions of oil are made to a 

particular in service tank on a given day (e.g., from 

multiple deliveries), one sample taken after the final 

addition of oil is sufficient. For the purposes of this 

section, a fuel lot is defined as a shipment or delivery of 

a single type of fuel (e.g., ship load, barge load, group 

of trucks, group of railroad cars, oil delivery via 

pipeline from a tank farm, etc.). However, if multiple 

deliveries of a particular type of fuel are received from 

the same supply source in a given calendar month, the 

deliveries for that month may be considered, collectively, 

to comprise a fuel lot, requiring only one representative 

sample, subject to the following conditions: 

(1) For coal, the “type” of fuel means the rank of 

the coal (i.e., anthracite, bituminous, sub-bituminous, or 

lignite). For fuel oil, the “type” of fuel means the grade 

number or classification of the oil (e.g., No. 1 oil, No. 2 

oil, kerosene, Jet A fuel, etc.). 

(2) The owner or operator shall document in the 

monitoring plan under §98.3(g)(5) how the monthly sampling 

of each type of fuel is performed. 

(C) For liquid fuels other than fuel oil and for 

biogas, sampling and analysis is required at least once per 
Page 322 of 442 

calendar quarter. To the extent practicable, consecutive 

quarterly samples shall be taken at least 30 days apart. 

(D) For other solid fuels (except MSW), weekly 

sampling is required to obtain composite samples, which are 

then analyzed monthly. 

(E) For gaseous fuels other than natural gas and 

biogas (e.g., process gas), daily sampling and analysis to 

determine the carbon content and molecular weight of the 

fuel is required if continuous, on-line equipment, such as 

a gas chromatograph, is in place to make these 

measurements. Otherwise, weekly sampling and analysis 

shall be performed. 

(F) For mixtures (blends) of solid fuels, weekly 

sampling is required to obtain composite samples, which are 

analyzed monthly. For blends of liquid fuels, and for gas 

mixtures consisting only of natural gas and biogas, 

sampling and analysis is required at least once per 

calendar quarter. For gas mixtures that contain gases 

other than natural gas (including biogas), daily sampling 

and analysis to determine the carbon content and molecular 

weight of the fuel is required if continuous, on-line 

equipment is in place to make these measurements. 

Otherwise, weekly sampling and analysis shall be performed. 

* * * * * 
Page 323 of 442 

(v) To calculate the CO2 mass emissions from 

combustion of a blend of fuels in the same state of matter 

(solid, liquid, or gas), you may either: 

(A) Apply Equation C-3, C-4 or C-5 of this subpart 

(as applicable) to each component of the blend, if the mass 

or volume, the carbon content, and (if applicable), the 

molecular weight of each component are accurately measured 

prior to blending; or 

(B) Consider the blend to be the “fuel type.” Then, 

at the frequency specified in paragraph (b)(3)(ii)(F) of 

this section, measure the carbon content and, if 

applicable, the molecular weight of the blend and calculate 

the annual average value of each parameter in the manner 

described in §98.33(a)(2)(ii). Also measure the mass or 

volume of the blended fuel combusted during the reporting 

year. Substitute these measured values into Equation C-3, 

C-4, or C-5 of this subpart (as applicable). 

(4) You must use one of the following appropriate 

fuel sampling and analysis methods. The results of 

chromatographic analysis of the fuel may be used, provided 

that the gas chromatograph is operated, maintained, and 

calibrated according to the manufacturer’s instructions. 

Alternatively, you may use a method published by a 

consensus-based standards organization if such a method 
Page 324 of 442 

exists, or you may use industry standard practice to 

determine the carbon content and molecular weight (for 

gaseous fuel) of the fuel. Consensus-based standards 

organizations include, but are not limited to, the 

following: ASTM International (100 Barr Harbor Drive, P.O. 

Box CB700, West Conshohocken, Pennsylvania 19428-B2959, 

(800) 262-1373, http://www.astm.org), the American National 

Standards Institute (ANSI, 1819 L Street, N.W., 6th floor, 

Washington, DC 20036, (202) 293-8020, http://www.ansi.org), 

the American Gas Association (AGA, 400 North Capitol 

Street, N.W., 4th Floor, Washington, DC 20001, (202) 824-

7000, http://www.aga.org), the American Society of 

Mechanical Engineers (ASME, Three Park Avenue, New York, NY 

10016-5990, (800) 843-2763, http://www.asme.org), the 

American Petroleum Institute (API, 1220 L Street, N.W., 

Washington, DC 20005-4070,(202) 682-8000, 

http://www.api.org), and the North American Energy 

Standards Board (NAESB, 801 Travis Street, Suite 1675, 

Houston, TX 77002, (713) 356-0060, http://www.api.org). 

The method(s) used shall be documented in the Monitoring 

Plan required under §98.3(g)(5). 

(c) For the Tier 4 Calculation Methodology, the CO2, 

flow rate, and (if applicable) moisture monitors must be 
Page 325 of 442 

certified prior to the applicable deadline specified in 

§98.33(b)(5). 

(1) * * * 

(i) §§75.20(c)(2), (c)(4), and (c)(5) though (c)(7) 

of this chapter and appendix A to part 75 of this chapter. 

(ii) The calibration drift test and relative accuracy 

test audit (RATA) procedures of Performance Specification 3 

in appendix B to part 60 of this chapter (for the CO2

concentration monitor) and Performance Specification 6 in 

appendix B to part 60 of this chapter (for the continuous 

emission rate monitoring system (CERMS)). 

* * * * * 

(2) If an O2 concentration monitor is used to 

determine CO2 concentrations, the applicable provisions of 

part 75 of this chapter, part 60 of this chapter, or an 

applicable State continuous monitoring program shall be 

followed for initial certification and on-going quality 

assurance, and all required RATAs of the monitor shall be 

done on a percent CO2 basis. 

(3) For ongoing quality assurance, follow the 

applicable procedures in either appendix B to part 75 of 

this chapter, appendix F to part 60 of this chapter, or an 

applicable State continuous monitoring program. If 

appendix F to part 60 of this chapter is selected for on-
Page 326 of 442 

going quality assurance, perform daily calibration drift 

assessments for both the CO2 monitor (or surrogate O2

monitor) and the flow rate monitor, conduct cylinder gas 

audits of the CO2 concentration monitor in three of the four 

quarters of each year (except for non-operating quarters), 

and perform annual RATAs of the CO2 concentration monitor 

and the CERMS. 

(4) For the purposes of this part, the stack gas 

volumetric flow rate monitor RATAs required by appendix B 

to part 75 of this chapter and the annual RATAs of the 

CERMS required by appendix F to part 60 of this chapter 

need only be done at one operating level, representing 

normal load or normal process operating conditions, both 

for initial certification and for ongoing quality 

assurance. 

* * * * * 

(6) For certain applications where combined process 

emissions and combustion emissions are measured, the CO2

concentrations in the flue gas may be considerably higher 

than for combustion emissions alone. In such cases, the 

span of the CO2 monitor may, if necessary, be set higher 

than the specified levels in the applicable regulations. 

If the CO2 span value is set higher than 20 percent CO2, the 

cylinder gas audits of the CO2 monitor under appendix F to 
Page 327 of 442 

part 60 of this chapter may be performed at 40 to 60 

percent and 80 to 100 percent of span, in lieu of the 

prescribed calibration levels of 5 to 8 percent CO2 and 10 

to 14 percent CO2. 

(7) Hourly average data from the CEMS shall be 

validated in a manner consistent with one of the following: 

§§60.13(h)(2)(i) through (h)(2)(vi) of this chapter; 

§75.10(d)(1) of this chapter; or the hourly data validation 

requirements of an applicable State CEM regulation. 

(d) Except as otherwise provided in §98.33 (b)(1)(vi) 

and (b)(1)(vii), when municipal solid waste (MSW) is either 

the primary fuel combusted in a unit or the only fuel with 

a biogenic component combusted in the unit, determine the 

biogenic portion of the CO2 emissions using ASTM D6866-08 

Standard Test Methods for Determining the Biobased Content 

of Solid, Liquid, and Gaseous Samples Using Radiocarbon 

Analysis (incorporated by reference, see §98.7) and ASTM 

D7459-08 Standard Practice for Collection of Integrated 

Samples for the Speciation of Biomass (Biogenic) and 

Fossil-Derived Carbon Dioxide Emitted from Stationary 

Emissions Sources (incorporated by reference, see §98.7). 

Perform the ASTM D7459-08 sampling and the ASTM D6866-08 

analysis at least once in every calendar quarter in which 

MSW is combusted in the unit. Collect each gas sample 
Page 328 of 442 

during normal unit operating conditions for at least 24 

total (not necessarily consecutive) hours, or longer if the 

facility deems it necessary to obtain a representative 

sample. Notwithstanding this requirement, if the types of 

fuels combusted and their relative proportions are 

consistent throughout the year, the minimum required 

sampling time may be reduced to 8 hours if at least two 8-

hour samples and one 24-hour sample are collected under 

normal operating conditions, and arithmetic average of the 

biogenic fraction of the flue gas from the 8-hour samples 

(expressed as a decimal) is within ± 5 percent of the 

biogenic fraction from the 24-hour test. There must be no 

overlapping of the 8-hour and 24-hour test periods. 

Document the results of the demonstration in the unit’s 

monitoring plan. If the types of fuels and their relative 

proportions are not consistent throughout the year, an 

optional sampling approach that facilities may wish to 

consider to obtain a more representative sample is to 

collect an integrated sample by extracting a small amount 

of flue gas (e.g., 1 to 5 cc) in each unit operating hour 

during the quarter. Separate the total annual CO2 emissions 

into the biogenic and non-biogenic fractions using the 

average proportion of biogenic emissions of all samples 

analyzed during the reporting year. Express the results as 
Page 329 of 442 

a decimal fraction (e.g., 0.30, if 30 percent of the CO2 is 

biogenic). When MSW is the primary fuel for multiple units 

at the facility, and the units are fed from a common fuel 

source, testing at only one of the units is sufficient. 

(e) For other units that combust combinations of 

biomass fuel(s) (or heterogeneous fuels that have a biomass 

component, e.g., tires) and fossil (or other non-biogenic) 

fuel(s), in any proportions, ASTM D6866-08 (incorporated by 

reference, see §98.7) and ASTM D7459-08 (incorporated by 

reference, see §98.7) may be used to determine the biogenic 

portion of the CO2 emissions in every calendar quarter in 

which biomass and non-biogenic fuels are co-fired in the 

unit. Follow the procedures in paragraph (d) of this 

section. If the primary fuel for multiple units at the 

facility consists of tires, and the units are fed from a 

common fuel source, testing at only one of the units is 

sufficient. 

(f) The records required under §98.3(g)(2)(i) shall 

include an explanation of how the following parameters are 

determined from company records (or, if applicable, from 

the best available information): 

(1) Fuel consumption, when the Tier 1 and Tier 2 

Calculation Methodologies are used, including cases where 

§98.36(c)(4) applies. 
Page 330 of 442 

* * * * * 

(3) Fossil fuel consumption when §98.33(e)(2) applies 

to a unit that uses CEMS to quantify CO2 emissions and that 

combusts both fossil and biomass fuels. 

* * * * * 

(5) Quantity of steam generated by a unit when 

§98.33(a)(2)(iii) applies. 

(6) Biogenic fuel consumption and high heating value, 

as applicable, under §§98.33(e)(5) and (e)(6). 

(7) Fuel usage for CH4 and N2O emissions calculations 

under §98.33(c)(4)(ii). 

(8) Mass of biomass combusted, for premixed fuels 

that contain biomass and fossil fuels under 

§98.33(e)(1)(iii). 

11. Section 98.35 is amended by revising paragraph 

(a) to read as follows: 

§98.35 Procedures for estimating missing data. 

* * * * * 

(a) For all units subject to the requirements of the 

Acid Rain Program, and all other stationary combustion 

units subject to the requirements of this part that monitor 

and report emissions and heat input data year-round in 

accordance with part 75 of this chapter, the missing data 

substitution procedures in part 75 of this chapter shall be 
Page 331 of 442 

followed for CO2 concentration, stack gas flow rate, fuel 

flow rate, high heating value, and fuel carbon content. 

* * * * * 

12. Section 98.36 is amended by: 

a. Revising paragraph (b)(5). 

b. Removing paragraphs (b)(9) and (b)(10). 

c. Redesignating paragraphs (b)(6) through (b)(8) as 

paragraphs (b)(8) through (b)(10), respectively. 

d. Revising newly designated paragraphs (b)(8) and 

(b)(9). 

e. Adding new paragraphs (b)(6) and (b)(7). 

f. Removing and reserving paragraphs (c)(1)(ii) and 

(c)(1)(iii) 

g. Revising paragraphs (c)(1)(vi) and (c)(1)(vii). 

h. Redesignating paragraph (c)(1)(viii) as paragraph 

(c)(1)(x), and revising newly designated paragraph 

(c)(1)(x). 

i. Removing paragraph (c)(1)(ix). 

j. Adding new paragraphs (c)(1)(viii) and (c)(1)(ix). 

k. Revising paragraphs (c)(2) introductory text, 

(c)(2)(ii), (c)(2)(iii), and (c)(2)(v). 

l. Removing paragraph (c)(2)(viii). 

m. Redesignating paragraphs (c)(2)(vi) and 

(c)(2)(vii) as paragraphs (c)(2)(viii) and (c)(2)(ix), and 
Page 332 of 442 

revising newly designated paragraphs (c)(2)(viii) and 

(c)(2)(ix). 

n. Adding new paragraphs (c)(2)(vi) and (c)(2)(vii). 

o. Removing and reserving paragraph (c)(3)(ii). 

p. Revising paragraphs (c)(3) introductory text, 

(c)(3)(iii), and (c)(3)(vii). 

q. Removing paragraph (c)(3)(viii). 

r. Adding new paragraphs (c)(3)(viii), (c)(3)(ix), 

and (c)(4). 

s. Revising paragraph (d). 

t. Revising paragraphs (e)(1)(iii), (e)(2)(i), 

(e)(2)(ii)(C), (e)(2)(ii)(D), (e)(2)(iii), (e)(2)(iv)(A), 

(e)(2)(iv)(C), and (e)(2)(v)(C). 

u. Adding paragraphs (e)(2)(iv)(F), (e)(2)(iv)(G), 

and (e)(2)(v)(E). 

v. Revising paragraphs (e)(2)(vii)(A), (e)(2)(ix) 

introductory text, and (e)(2)(x) introductory text. 

w. Removing paragraphs (e)(2)(x)(B) and (e)(2)(x)(C). 

x. Redesignating paragraph (e)(2)(x)(D) as 

(e)(2)(x)(B), and revising newly designated paragraph 

(e)(2)(x)(B). 

y. Revising paragraph (e)(2)(xi). 

§98.36 Data reporting requirements. 

* * * * * 
Page 333 of 442 

(b) * * * 

(5) The methodology (i.e., tier) used to calculate 

the CO2 emissions for each type of fuel combusted (i.e., 

Tier 1, 2, 3, or 4). 

(6) The methodology start date, for each fuel type. 

(7) The methodology end date, for each fuel type. 

(8) For a unit that uses Tiers 1, 2, or 3: 

(i) The annual CO2 mass emissions (including biogenic 

CO2), and the annual CH4, and N2O mass emissions for each 

type of fuel combusted during the reporting year, expressed 

in metric tons of each gas and in metric tons of CO2e; and 

(ii) Metric tons of biogenic CO2 emissions (if 

applicable). 

(9) For a unit that uses Tier 4: 

(i) If the total annual CO2 mass emissions measured by 

the CEMS consists entirely of non-biogenic CO2 (i.e., CO2

from fossil fuel combustion plus, if applicable, CO2 from 

sorbent and/or process CO2), report the total annual CO2

mass emissions, expressed in metric tons. You are not 

required to report the combustion CO2 emissions by fuel 

type. 

(ii) Report the total annual CO2 mass emissions 

measured by the CEMS. If this total includes both biogenic 

and non-biogenic CO2, separately report the annual non-
Page 334 of 442 

biogenic CO2 mass emissions and the annual CO2 mass 

emissions from biomass combustion, each expressed in metric 

tons. You are not required to report the combustion CO2

emissions by fuel type. 

(iii) An estimate of the heat input from each type of 

fuel listed in Table C-2 of this subpart that was combusted 

in the unit during the report year, and the annual CH4 and 

N2O emissions for each of these fuels, expressed in metric 

tons of each gas and in metric tons of CO2e. 

* * * * * 

(c) * * * 

(1) * * * 

(ii) [Reserved] 

(iii) [Reserved] 

* * * * * 

(vi) Annual CO2 mass emissions and annual CH4, and N2O 

mass emissions, aggregated for each type of fuel combusted 

in the group of units during the report year, expressed in 

metric tons of each gas and in metric tons of CO2e. If any 

of the units burn both fossil fuels and biomass, report 

also the annual CO2 emissions from combustion of all fossil 

fuels combined and annual CO2 emissions from combustion of 

all biomass fuels combined, expressed in metric tons. 
Page 335 of 442 

(vii) The methodology (i.e., tier) used to calculate 

the CO2 mass emissions for each type of fuel combusted in 

the units (i.e., Tier 1, Tier 2, or Tier 3). 

(viii) The methodology start date, for each fuel 

type. 

(ix) The methodology end date, for each fuel type. 

(x) The calculated CO2 mass emissions (if any) from 

sorbent expressed in metric tons. 

(2) Monitored common stack or duct configurations. 

When the flue gases from two or more stationary fuel 

combustion units at a facility are combined together in a 

common stack or duct before exiting to the atmosphere and 

if CEMS are used to continuously monitor CO2 mass emissions 

at the common stack or duct according to the Tier 4 

Calculation Methodology, you may report the combined 

emissions from the units sharing the common stack or duct, 

in lieu of separately reporting the GHG emissions from the 

individual units. This monitoring and reporting 

alternative may also be used when process off-gases or a 

mixture of combustion products and process gases are 

combined together in a common stack or duct before exiting 

to the atmosphere. Whenever the common stack or duct 

monitoring option is applied, the following information 
Page 336 of 442 

shall be reported instead of the information in paragraph 

(b) of this section: 

* * * * * 

(ii) Number of units sharing the common stack or 

duct. Report “1” when the flue gas flowing through the 

common stack or duct includes combustion products and/or 

process off-gases, and all of the effluent comes from a 

single unit (e.g., a furnace, kiln, petrochemical 

production unit, or smelter). 

(iii) Combined maximum rated heat input capacity of 

the units sharing the common stack or duct (mmBtu/hr). 

This data element is required only when all of the units 

sharing the common stack are stationary fuel combustion 

units. 

* * * * * 

(v) The methodology (tier) used to calculate the CO2

mass emissions, i.e., Tier 4. 

(vi) The methodology start date. 

(vii) The methodology end date. 

(viii) Total annual CO2 mass emissions measured by the 

CEMS, expressed in metric tons. If any of the units burn 

both fossil fuels and biomass, separately report the annual 

non-biogenic CO2 mass emissions (i.e., CO2 from fossil fuel 

combustion plus, if applicable, CO2 from sorbent and/or 
Page 337 of 442 

process CO2) and the annual CO2 mass emissions from biomass 

combustion, each expressed in metric tons. 

(ix) An estimate of the heat input from each type of 

fuel listed in Table C-2 of this subpart that was combusted 

during the report year in the units sharing the common 

stack or duct during the report year, and, for each of 

these fuels, the annual CH4 and N2O mass emissions from the 

units sharing the common stack or duct, expressed in metric 

tons of each gas and in metric tons of CO2e. 

(3) Common pipe configurations. When two or more 

stationary combustion units at a facility combust the same 

type of liquid or gaseous fuel and the fuel is fed to the 

individual units through a common supply line or pipe, you 

may report the combined emissions from the units served by 

the common supply line, in lieu of separately reporting the 

GHG emissions from the individual units, provided that the 

total amount of fuel combusted by the units is accurately 

measured at the common pipe or supply line using a fuel 

flow meter, or, for natural gas, the amount of fuel 

combusted may be obtained from gas billing records. For 

Tier 3 applications, the flow meter shall be calibrated in 

accordance with §98.34(b). If a portion of the fuel 

measured (or obtained from gas billing records) at the main 

supply line is diverted to either: a flare; or another 
Page 338 of 442 

stationary fuel combustion unit (or units), including units 

that use a CO2 mass emissions calculation method in part 75 

of this chapter; or a chemical or industrial process (where 

it is used as a raw material but not combusted), and the 

remainder of the fuel is distributed to a group of 

combustion units for which you elect to use the common pipe 

reporting option, you may use company records to subtract 

out the diverted portion of the fuel from the fuel measured 

(or obtained from gas billing records) at the main supply 

line prior to performing the GHG emissions calculations for 

the group of units using the common pipe option. If the 

diverted portion of the fuel is combusted, the GHG 

emissions from the diverted portion shall be accounted for 

in accordance with the applicable provisions of this part. 

When the common pipe option is selected, the applicable 

tier shall be used based on the maximum rated heat input 

capacity of the largest unit served by the common pipe 

configuration, except where the applicable tier is based on 

criteria other than unit size. For example, if the maximum 

rated heat input capacity of the largest unit is greater 

than 250 mmBtu/hr, Tier 3 will apply, unless the fuel 

transported through the common pipe is natural gas or 

distillate oil, in which case Tier 2 may be used, in 

accordance with §98.33(b)(2)(ii). As a second example, in 
Page 339 of 442 

accordance with §98.33(b)(1)(v), Tier 1 may be used 

regardless of unit size when natural gas is transported 

through the common pipe, if the annual fuel consumption is 

obtained from gas billing records in units of therms. When 

the common pipe reporting option is selected, the following 

information shall be reported instead of the information in 

paragraph (b) of this section: 

* * * * * 

(iii) The highest maximum rated heat input capacity 

of any unit served by the common pipe (mmBtu/hr). 

* * * * * 

(vii) Annual CO2 mass emissions and annual CH4 and N2O 

emissions from each fuel type for the units served by the 

common pipe, expressed in metric tons of each gas and in 

metric tons of CO2e. 

(viii) Methodology start date 

(ix) Methodology end date 

(4) The following alternative reporting option 

applies to facilities at which a common liquid or gaseous 

fuel supply is shared between one or more large combustion 

units, such as boilers or combustion turbines (including 

units subject to subpart D of this part and other units 

subject to part 75 of this chapter) and small combustion 

sources, including, but not limited to, space heaters, hot 
Page 340 of 442 

water heaters, and lab burners. In this case, you may 

simplify reporting by attributing all of the GHG emissions 

from combustion of the shared fuel to the large combustion 

unit(s), provided that: 

(i) The total quantity of the fuel combusted during 

the report year in the units sharing the fuel supply is 

measured, either at the “gate” to the facility or at a 

point inside the facility, using a fuel flow meter, billing 

meter, or tank drop measurements (as applicable); 

(ii) On an annual basis, at least 95 percent (by mass 

or volume) of the shared fuel is combusted in the large 

combustion unit(s), and the remainder is combusted in the 

small combustion sources. Company records may be used to 

determine the percentage distribution of the shared fuel to 

the large and small units; and 

(iii) The use of this reporting option is documented 

in the Monitoring Plan required under §98.3(g)(5). 

Indicate in the Monitoring Plan which units share the 

common fuel supply and the method used to demonstrate that 

this alternative reporting option applies. For the small 

combustion sources, a description of the types of units and 

the approximate number of units is sufficient. 

(d) Units subject to part 75 of this chapter. 
Page 341 of 442 

(1) For stationary combustion units that are subject 

to subpart D of this part, you shall report the following 

unit-level information: 

(i) Unit or stack identification numbers. Use exact 

same unit, common stack, common pipe, or multiple stack 

identification numbers that represent the monitored 

locations (e.g., 1, 2, CS001, MS1A, CP001, etc.) that are 

reported under §75.64 of this chapter. 

(ii) Annual CO2 emissions at each monitored location, 

expressed in both short tons and metric tons. Separate 

reporting of biogenic CO2 emissions under §98.3(c)(4)(ii) 

and §98.3(c)(4)(iii)(A) is optional only for the 2010 

reporting year, as provided in §98.3(c)(12). 

(iii) Annual CH4 and N2O emissions at each monitored 

location, for each fuel type listed in Table C-2 that was 

combusted during the year (except as otherwise provided in 

§98.33(c)(4)(ii)(B)), expressed in metric tons of CO2e. 

(iv) The total heat input from each fuel listed in 

Table C-2 that was combusted during the year (except as 

otherwise provided in §98.33(c)(4)(ii)(B)), expressed in 

mmBtu. 

(v) Identification of the Part 75 methodology used to 

determine the CO2 mass emissions. 

(vi) Methodology start date. 
Page 342 of 442 

(vii) Methodology end date. 

(viii) Acid Rain Program indicator. 

(ix) Annual CO2 mass emissions from the combustion of 

biomass, expressed in metric tons of CO2e, except where the 

reporting provisions of §§98.3(c)(12)(i) through 

(c)(12)(iii) are implemented for the 2010 reporting year. 

(2) For units that use the alternative CO2 mass 

emissions calculation methods provided in §98.33(a)(5), you 

shall report the following unit-level information: 

(i) Unit, stack, or pipe ID numbers. Use exact same 

unit, common stack, common pipe, or multiple stack 

identification numbers that represent the monitored 

locations (e.g., 1, 2, CS001, MS1A, CP001, etc.) that are 

reported under §75.64 of this chapter. 

(ii) For units that use the alternative methods 

specified in §98.33(a)(5)(i) and (ii) to monitor and report 

heat input data year-round according to appendix D to part 

75 of this chapter or §75.19 of this chapter: 

(A) Each type of fuel combusted in the unit during 

the reporting year. 

(B) The methodology used to calculate the CO2 mass 

emissions for each fuel type. 

(C) Methodology start date. 

(D) Methodology end date. 
Page 343 of 442 

(E) A code or flag to indicate whether heat input is 

calculated according to appendix D to part 75 of this 

chapter or §75.19 of this chapter. 

(F) Annual CO2 emissions at each monitored location, 

across all fuel types, expressed in metric tons of CO2e. 

(G) Annual heat input from each type of fuel listed 

in Table C-2 of this subpart that was combusted during the 

reporting year, expressed in mmBtu. 

(H) Annual CH4 and N2O emissions at each monitored 

location, from each fuel type listed in Table C-2 of this 

subpart that was combusted during the reporting year 

(except as otherwise provided in §98.33(c)(4)(ii)(D)), 

expressed in metric tons CO2e. 

(I) Annual CO2 mass emissions from the combustion of 

biomass, expressed in metric tons CO2e, except where the 

reporting provisions of §§98.3(c)(12)(i) through 

(c)(12)(iii) are implemented for the 2010 reporting year. 

(iii) For units with continuous monitoring systems 

that use the alternative method for units with continuous 

monitoring systems in §98.33(a)(5)(iii) to monitor heat 

input year-round according to part 75 of this chapter: 

(A) Each type of fuel combusted during the reporting 

year. 
Page 344 of 442 

(B) Methodology used to calculate the CO2 mass 

emissions. 

(C) Methodology start date. 

(D) Methodology end date. 

(E) A code or flag to indicate that the heat input 

data is derived from CEMS measurements. 

(F) The total annual CO2 emissions at each monitored 

location, expressed in metric tons of CO2e. 

(G) Annual heat input from each type of fuel listed 

in Table C-2 of this subpart that was combusted during the 

reporting year, expressed in mmBtu. 

(H) Annual CH4 and N2O emissions at each monitored 

location, from each fuel type listed in Table C-2 of this 

subpart that was combusted during the reporting year 

(except as otherwise provided in §98.33(c)(4)(ii)(B)), 

expressed in metric tons CO2e. 

(I) Annual CO2 mass emissions from the combustion of 

biomass, expressed in metric tons CO2e, except where the 

reporting provisions of §§98.3(c)(12)(i) through 

(c)(12)(iii) are implemented for the 2010 reporting year. 

(e) * * * 

(1) * * * 

(iii) Are not in the Acid Rain Program, but are 

required to monitor and report CO2 mass emissions and heat 
Page 345 of 442 

input data year-round, in accordance with part 75 of this 

chapter. 

(2) * * * 

(i) For the Tier 1 Calculation Methodology, report 

the total quantity of each type of fuel combusted in the 

unit or group of aggregated units (as applicable) during 

the reporting year, in short tons for solid fuels, gallons 

for liquid fuels and standard cubic feet for gaseous fuels, 

or, if applicable, therms or mmBtu for natural gas. 

(ii) * * * 

(C) The high heat values used in the CO2 emissions 

calculations for each type of fuel combusted during the 

reporting year, in mmBtu per short ton for solid fuels, 

mmBtu per gallon for liquid fuels, and mmBtu per scf for 

gaseous fuels. Report a HHV value for each calendar month 

in which HHV determination is required. If multiple values 

are obtained in a given month, report the arithmetic 

average value for the month. Indicate whether each 

reported HHV is a measured value or a substitute data 

value. 

(D) If Equation C-2c of this subpart is used to 

calculate CO2 mass emissions, report the total quantity 

(i.e., pounds) of steam produced from MSW or solid fuel 

combustion during each month of the reporting year, and the 
Page 346 of 442 

ratio of the maximum rate heat input capacity to the design 

rated steam output capacity of the unit, in mmBtu per lb of 

steam. 

(iii) For the Tier 2 Calculation Methodology, keep 

records of the methods used to determine the HHV for each 

type of fuel combusted and the date on which each fuel 

sample was taken, except where fuel sampling data are 

received from the fuel supplier. In that case, keep 

records of the dates on which the results of the fuel 

analyses for HHV are received. 

(iv) * * * 

(A) The quantity of each type of fuel combusted in 

the unit or group of units (as applicable) during each 

month of the reporting year, in short tons for solid fuels, 

gallons for liquid fuels, and scf for gaseous fuels. 

* * * * * 

(C) The carbon content and, if applicable, gas 

molecular weight values used in the emission calculations 

(including both valid and substitute data values). For 

each calendar month of the reporting year in which carbon 

content and, if applicable, molecular weight determination 

is required, report a value of each parameter. If multiple 

values of a parameter are obtained in a given month, report 

the arithmetic average value for the month. Express carbon 
Page 347 of 442 

content as a decimal fraction for solid fuels, kg C per 

gallon for liquid fuels, and kg C per kg of fuel for 

gaseous fuels. Express the gas molecular weights in units 

of kg per kg-mole. 

* * * * * 

(F) The annual average HHV, when measured HHV data, 

rather than a default HHV from Table C-1 of this subpart, 

are used to calculate CH4 and N2O emissions for a Tier 3 

unit, in accordance with §98.33(c)(1). 

(G) The value of the molar volume constant (MVC) used 

in Equation C-5 (if applicable). 

(v) * * * 

(C) The methods used to determine the carbon content 

and (if applicable) the molecular weight of each type of 

fuel combusted. 

* * * * * 

(E) The date on which each fuel sample was taken, 

except where fuel sampling data are received from the fuel 

supplier. In that case, keep records of the dates on which 

the results of the fuel analyses for carbon content and (if 

applicable) molecular weight are received. 

* * * * * 

(vii) * * * 
Page 348 of 442 

(A) Whether the CEMS certification and quality 

assurance procedures of part 75 of this chapter, part 60 of 

this chapter, or an applicable State continuous monitoring 

program were used. 

* * * * * 

(ix) For units that combust both fossil fuel and 

biomass, when biogenic CO2 is determined according to 

§98.33(e)(2), you shall report the following additional 

information, as applicable: 

* * * * * 

(x) When ASTM methods D7459-08 (incorporated by 

reference, see §98.7) and D6866-08 (incorporated by 

reference, see §98.7) are used to determine the biogenic 

portion of the annual CO2 emissions from MSW combustion, as 

described in §98.34(d), report: 

* * * * * 

(B) The annual biogenic CO2 mass emissions from MSW 

combustion, in metric tons. 

(xi) When ASTM methods D7459-08 (incorporated by 

reference, see §98.7) and D6866-08 (incorporated by 

reference, see §98.7) are used in accordance with §98.34(e) 

to determine the biogenic portion of the annual CO2

emissions from a unit that co-fires biogenic fuels (or 

partly-biogenic fuels, including tires if you are electing 
Page 349 of 442 

to report biogenic CO2 emissions from tire combustion) and 

non-biogenic fuels, you shall report the results of each 

quarterly sample analysis, expressed as a decimal fraction 

(e.g., if the biogenic fraction of the CO2 emissions is 30 

percent, report 0.30). 

* * * * * 

13. Table C-1 to Subpart C is amended by: 

a. Revising the title to read “Table C-1 to Subpart 

C—Default CO2 Emission Factors and High Heat Values for 

Various Types of Fuel.” 

b. Revising the entry for “Pipeline (Weighted U.S. 

Average).” 

c. Removing the entry for “Still Gas.” 

d. Adding an entry for “Used Oil”, following the 

entry for “Residual Fuel Oil No. 6.” 

e. Revising the entry for “Ethane”. 

f. Adding an entry for “Ethanol”, following the entry 

for “Ethane.” 

g. Revising the entry for “Fossil fuel-derived fuels 

(solid)” to read “Other fuels-solid.” 

h. Revising the entry for “Municipal Solid Waste.” 

i. Adding entries for “Plastics” and “Petroleum 

Coke”, following the entry for “Tires.” 
Page 350 of 442 

j. Revising the entry for “Fossil fuel-derived fuels 

(gaseous)” to read “Other fuels-gaseous.” 

k. Adding entries for “Propane Gas” and “Fuel Gas,” 

following the entry for “Coke Oven Gas.” 

l. Revising the entry for “Biomass fuels – liquid” by 

centering “Biomass fuels – liquid.” 

m. Revising the entries for “Ethanol” and “Biodiesel” 

that follow the entry for “Biomass fuels – liquid.” 

n. Revising footnote “1.” 

o. Adding footnote “2.” 

Table C-1 to Subpart C—Default CO2 Emission Factors and High 

Heat Values for Various Types of Fuel

Fuel Type Default High 

Heat Value 

Default CO2 Emission 

Factor 

* * * * * * * 

(Weighted U.S. Average) 1.028 x 10-3 53.02 

* * * * * * * 

Used Oil 0.135 74.00 

* * * * * * * 

Ethane 0.069 62.64 

Ethanol 0.084 68.44 

* * * * * * * 

Other fuels (solid) mmBtu/short 

ton 

kg CO2 /mmBtu

Municipal Solid Waste 9.951 90.7 

* * * * * * * 

Plastics 38.00 75.00 

Petroleum Coke 30.00 102.41 

Other fuels (gaseous) mmBtu/scf kg CO2 /mmBtu

* * * * * * * 

Propane Gas 2.516 x 10-3 61.46 

Fuel Gas2 1.388 x 10-3 59.00 

* * * * * * * 

Ethanol 0.084 68.44 

Biodiesel 0.128 73.84 
Page 351 of 442 

Table C-1 to Subpart C—Default CO2 Emission Factors and High 

Heat Values for Various Types of Fuel

Fuel Type Default High 

Heat Value 

Default CO2 Emission 

Factor 

* * * * * * * 

1

 Use of this default HHV is allowed only for: (a) units that 

combust MSW, do not generate steam, and are allowed to use Tier 

1; (b) units that derive no more than 10 percent of their annual 

heat input from MSW and/or tires; and (c) small batch 

incinerators that combust no more than 1,000 tons of MSW per 

year. 

2

Reporters subject to subpart X of this part that are complying 

with §98.243(d) or subpart Y of this part may only use the 

default HHV and the default CO2 emission factor for fuel gas 

combustion under the conditions prescribed in §98.243(d)(2)(i) 

and (d)(2)(ii) and §98.252(a)(1) and (a)(2), respectively. 

Otherwise, reporters subject to subpart X or subpart Y shall use 

either Tier 3 (Equation C–5) or Tier 4. 

14. The first Table C-2 to Subpart C is removed, and 

the second Table C-2 to Subpart C is revised to read as 

follows: 

Table C-2 to Subpart C—Default CH4 and N2O Emission Factors 

for Various Types of Fuel. 

Fuel Type 

Default CH4

Emission Factor 

(kg CH4 /mmBtu) 

Default N2O 

Emission Factor (kg 

N2O/mmBtu)

Coal and Coke (All fuel 

types in Table C-1) 

1.1 x 10-02 1.6 x 10-03

Natural Gas 1.0 x 10-03 1.0 x 10-04

Petroleum (All fuel types 

in Table C-1) 

3.0 x 10-03 6.0 x 10-04

Municipal Solid Waste 3.2 x 10-02 4.2 x 10-03

Tires 3.2 x 10-02 4.2 x 10-03

Blast Furnace Gas 2.2 x 10-05 1.0 x 10-04

Coke Oven Gas 4.8 x 10-04 1.0 x 10-04

Biomass Fuels - Solid (All 

fuel types in Table C-1) 

3.2 x 10-02 4.2 x 10-03

Biogas 3.2 x 10-03 6.3 x 10-04

Biomass Fuels – Liquid 

(All fuel types in Table 

C-1) 

1.1 x 10-03 1.1 x 10-04

Note: Those employing this table are assumed to fall under the IPCC 

definitions of the “Energy Industry” or “Manufacturing Industries and 

Construction”. In all fuels except for coal the values for these two 

categories are identical. For coal combustion, those who fall within 
Page 352 of 442 

the IPCC “Energy Industry” category may employ a value of 1 g of 

CH4/mmBtu. 

Subpart D—[Amended] 

15. Section 98.40 is amended by revising paragraph 

(a) to read as follows: 

§98.40 Definition of the source category.

(a) The electricity generation source category 

comprises electricity generating units that are subject to 

the requirements of the Acid Rain Program and any other 

electricity generating units that are required to monitor 

and report to EPA CO2 mass emissions year-round according to 

40 CFR part 75. 

* * * * * 

16. Section 98.43 is revised to read as follows: 

§98.43 Calculating GHG emissions.

(a) Except as provided in paragraph (b) of this 

section, continue to monitor and report CO2 mass emissions 

as required under §75.13 or section 2.3 of appendix G to 40 

CFR part 75, and §75.64. Calculate CO2, CH4, and N2O 

emissions as follows: 

(1) Convert the cumulative annual CO2 mass emissions 

reported in the fourth quarter electronic data report 

required under §75.64 from units of short tons to metric 

tons. To convert tons to metric tons, divide by 1.1023. 
Page 353 of 442 

(2) Calculate and report annual CH4 and N2O mass 

emissions under this subpart by following the applicable 

method specified in §98.33(c). 

(b) Calculate and report biogenic CO2 emissions under 

this subpart by following the applicable methods specified 

in §98.33(e). The CO2 emissions (excluding biogenic CO2) 

for units subject to this subpart that are reported under 

§§98.3(c)(4)(i) and (c)(4)(iii)(B) shall be calculated by 

subtracting the biogenic CO2 mass emissions calculated 

according to §98.33(e) from the cumulative annual CO2 mass 

emissions from paragraph (a)(1) of this section. Separate 

calculation and reporting of biogenic CO2 emissions is 

optional only for the 2010 reporting year pursuant to 

§98.3(c)(12) and required every year thereafter. 

17. Section 98.46 is revised to read as follows: 

§98.46 Data reporting requirements. 

The annual report shall comply with the data reporting 

requirements specified in §98.36(d)(1). 

18. Section 98.47 is revised to read as follows: 

§98.47 Records that must be retained. 

You shall comply with the recordkeeping requirements 

of §§98.3(g) and 98.37. Records retained under §75.57(h) 

of this chapter for missing data events satisfy the 
Page 354 of 442 

recordkeeping requirements of §98.3(g)(4) for those same 

events. 

Subpart F—[Amended] 

19. Section 98.62 is amended by revising paragraphs 

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

§98.62 GHGs to report.

* * * * * 

(a) Perfluoromethane (CF4), and perfluoroethane (C2F6) 

emissions from anode effects in all prebake and Søderberg 

electrolysis cells. 

(b) CO2 emissions from anode consumption during 

electrolysis in all prebake and Søderberg electrolysis 

cells. 

* * * * * 

20. Section 98.63 is amended by: 

a. In paragraph (a), revising the only sentence and 

the definitions of “EPFC,” and “Em” in Equation F-1. 

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

c. Revising paragraph (c). 

§98.63 Calculating GHG emissions.

(a) The annual value of each PFC compound (CF4, C2F6) 

shall be estimated from the sum of monthly values using 

Equation F-1 of this section: 

* * * * * 
Page 355 of 442 

EPFC = Annual emissions of each PFC compound from 

aluminum production (metric tons PFC). 

Em = Emissions of the individual PFC compound from 

aluminum production for the month “m” (metric 

tons PFC). 

(b) Use Equation F-2 of this section to estimate CF4

emissions from anode effect duration or Equation F-3 of 

this section to estimate CF4 emissions from overvoltage, and 

use Equation F-4 of this section to estimate C2F6 emissions 

from anode effects from each prebake and Søderberg 

electrolysis cell. 

* * * * * 

(c) You must calculate and report the annual process 

CO2 emissions from anode consumption during electrolysis and 

anode baking of prebake cells using either the procedures 

in paragraph (d) of this section, the procedures in 

paragraphs (e) and (f) of this section, or the procedures 

in paragraph (g) of this section. 

* * * * * 

21. Section 98.64 is amended by revising the first 

sentence of paragraph (a); and by revising paragraph (b) to 

read as follows: 

§98.64 Monitoring and QA/QC requirements. 

(a) Effective December 31, 2010 for smelters with no 

prior measurement or effective December 31, 2012, for 

facilities with historic measurements, the smelter-specific 
Page 356 of 442 

slope coefficients, overvoltage emission factors, and 

weight fractions used in Equations F-2, F-3, and F-4 of 

this subpart must be measured in accordance with the 

recommendations of the EPA/IAI Protocol for Measurement of 

Tetrafluoromethane (CF4) and Hexafluoroethane (C2F6) 

Emissions from Primary Aluminum Production (2008) 

(incorporated by reference, see §98.7), except the minimum 

frequency of measurement shall be every 10 years unless a 

change occurs in the control algorithm that affects the mix 

of types of anode effects or the nature of the anode effect 

termination routine. * * * 

(b) The minimum frequency of the measurement and 

analysis is annually except as follows: 

(i) Monthly for anode effect minutes per cell day (or 

anode effect overvoltage and current efficiency). 

(ii) Monthly for aluminum production. 

(iii) Smelter-specific slope coefficients, 

overvoltage emission factors, and weight fractions 

according to paragraph (a) of this section. 

* * * * * 

22. Section 98.65 is amended by revising the only 

sentence of paragraph (a) to read as follows: 

§98.65 Procedures for estimating missing data.

* * * * * 
Page 357 of 442 

(a) Where anode or paste consumption data are 

missing, CO2 emissions can be estimated from aluminum 

production per Equation F-8 of this section. 

* * * * * 

23. Section 98.66 is amended by revising paragraph 

(c)(1) to read as follows: 

§98.66 Data reporting requirements. 

* * * * * 

(c) * * * 

(1) Perfluoromethane emissions and perfluoroethane 

emissions from anode effects in all prebake and all 

Søderberg electrolysis cells combined. 

* * * * * 

24. Table F-1 to Subpart F of Part 98 is revised to 

read as follows: 

Table F-1 to Subpart F of Part 98—Slope and Overvoltage 

Coefficients for the Calculation of PFC Emissions from 

Aluminum Production 
Page 358 of 442 

Technology

CF4 Slope 

Coefficient 

[(kg CF4/metric 

ton Al)/(AEMins/cell-day)] 

CF4 Overvoltage 

Coefficient 

[(kg CF4/metric 

ton Al)/(mV)] 

Weight 

Fraction 

C2F6/CF4 

[(kg C2F6/kg 

CF4)] 

Center 

Worked 

Prebake 

(CWPB) 

0.143 1.16 0.121 

Side 

Worked 

Prebake 

(SWPB) 

0.272 3.65 0.252 

Vertical 

Stud 

Søderberg 

(VSS) 

0.092 NA 0.053 

Horizontal 

Stud 

Søderberg 

(HSS) 

0.099 NA 0.085 

25. Table F-2 to Subpart F of Part 98 is amended by 

revising the entry for “CO2 Emissions from Pitch Volatiles 

Combustion (VSS and HSS)” to read as follows: 

Table F-2 to Subpart F of Part 98—Default Data Sources for 

Parameters Used for CO2 Emissions 

CO2 Emissions from Prebake Cells (CWPB and SWPB) 

Parameter Data Source 

 * * * * * * * 

CO2 Emissions from Pitch Volatiles Combustion (CWPB and SWPB) 

 * * * * * * * 

Subpart G—[Amended] 

26. Section 98.72 is amended by revising paragraphs 

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

§98.72 GHGs to report.

* * * * * 
Page 359 of 442 

(a) CO2 process emissions from steam reforming of a 

hydrocarbon or the gasification of solid and liquid raw 

material, reported for each ammonia manufacturing process 

unit following the requirements of this subpart (CO2 process 

emissions reported under this subpart may include CO2 that 

is later consumed on site for urea production, and 

therefore is not released to the ambient air from the 

ammonia manufacturing process unit). 

(b) CO2, CH4, and N2O emissions from each stationary 

fuel combustion unit. You must report these emissions 

under subpart C of this part (General Stationary Fuel 

Combustion Sources), by following the requirements of 

subpart C, except that for ammonia manufacturing processes 

subpart C does not apply to any CO2 resulting from 

combustion of the waste recycle stream (commonly referred 

to as the purge gas stream). 

* * * * * 

27. Section 98.73 is amended by: 

a. Revising paragraph (b) introductory text. 

b. Revising the definition of “CO2,G” in Equation G-1 

of paragraph (b)(1). 

c. Revising the definition of “CO2,L” in Equation G-2 

of paragraph (b)(2). 
Page 360 of 442 

d. Revising the definition of “CO2,S” in Equation G-3 

of paragraph (b)(3). 

e. Revising the definition of “CO2” in Equation G-5 of 

paragraph (b)(5). 

f. Removing paragraph (b)(6). 

§98.73 Calculating GHG emissions.

* * * * * 

(b) Calculate and report under this subpart process 

CO2 emissions using the procedures in paragraphs (b)(1) 

through (b)(5) of this section for gaseous feedstock, 

liquid feedstock, or solid feedstock, as applicable. 

(1) * * * * * 

CO2,G,k = Annual CO2 emissions arising from gaseous 

feedstock consumption (metric tons). 

* * * * * 

(2) * * * * * 

CO2,L,k = Annual CO2 emissions arising from liquid 

feedstock consumption (metric tons). 

* * * * * 

(3) * * * * * 

CO2,S,k = Annual CO2 emissions arising from solid 

feedstock consumption (metric tons). 

* * * * * 

(5) * * * * * 
Page 361 of 442 

CO2 = Annual combined CO2 emissions from all ammonia 

processing units (metric tons) (CO2 process 

emissions reported under this subpart may 

include CO2 that is later consumed on site for 

urea production, and therefore is not released 

to the ambient air from the ammonia 

manufacturing process unit(s)). 

28. Section 98.74 is amended by revising paragraph 

(d) to read as follows and by removing and reserving 

paragraph (f): 

§98.74 Monitoring and QA/QC requirements.

* * * * * 

(d) Calibrate all oil and gas flow meters that are 

used to measure liquid and gaseous feedstock volumes and 

flow rates (except for gas billing meters) according to the 

monitoring and QA/QC requirements for the Tier 3 

methodology in §98.34(b)(1). Perform oil tank drop 

measurements (if used to quantify feedstock volumes) 

according to §98.34(b)(2). 

* * * * * 

29. Section 98.75 is amended by revising the first 

sentence of paragraph (a); and by revising paragraph (b) to 

read as follows: 

§98.75 Procedures for estimating missing data. 

* * * * * 

(a) For missing data on monthly carbon contents of 

feedstock, the substitute data value shall be the 
Page 362 of 442 

arithmetic average of the quality-assured values of that 

carbon content in the month preceding and the month 

immediately following the missing data incident. * *

* 

(b) For missing feedstock supply rates used to 

determine monthly feedstock consumption, you must determine 

the best available estimate(s) of the parameter(s), based 

on all available process data. 

30. Section 98.76 is amended by: 

a. Revising paragraphs (a) introductory text and 

(b)(6). 

b. Removing paragraphs (b)(12) through (b)(15). 

c. Redesignating paragraph (b)(16) as paragraph 

(b)(12). 

c. Adding paragraph (b)(13). 

d. Removing paragraphs (b)(17) and (c). 

§98.76 Data reporting requirements. 

* * * * * 

(a) 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 and the 

following information in this paragraph (a): 

* * * * * 

(b) * * * 
Page 363 of 442 

(6) Sampling analysis results of carbon content of 

feedstock as determined for QA/QC of supplier data under 

§98.74(e). 

* * * * * 

(13) CO2 from the steam reforming of a hydrocarbon or 

the gasification of solid and liquid raw material at the 

ammonia manufacturing process unit used to produce urea and 

the method used to determine the CO2 consumed in urea 

production. 

Subpart P—[Amended] 

31. Section 98.163 is amended by revising the 

definitions of “CCn” and “MW” in Equation P-1 of paragraph 

(b)(1) to read as follows: 

§98.163 Calculating GHG emissions.

* * * * * 

(b) * * * 

(1) * * * * * 

CCn = Average carbon content of the gaseous fuel 

and feedstock, from the results of one or 

more analyses for month n (kg carbon per kg 

of fuel and feedstock). If measurements are 

taken more frequently than monthly, use the 

arithmetic average of measurement values 

within the month to calculate a monthly 

average. 

MWn = Average molecular weight of the gaseous fuel 

and feedstock from the results of one or 

more analyses for month n (kg/kg-mole). 

* * * * * 
Page 364 of 442 

32. Section 98.164 is amended by revising paragraphs 

(b)(1), (b)(2), and (b)(5) introductory text to read as 

follows: 

§98.164 Monitoring and QA/QC requirements.

* * * * * 

(b) * * * 

(1) Calibrate all oil and gas flow meters that are 

used to measure liquid and gaseous feedstock volumes 

(except for gas billing meters) according to the monitoring 

and QA/QC requirements for the Tier 3 methodology in 

§98.34(b)(1). Perform oil tank drop measurements (if used 

to quantify liquid fuel or feedstock consumption) according 

to §98.34(b)(2). Calibrate all solids weighing equipment 

according to the procedures in §98.3(i). 

(2) Determine the carbon content and the molecular 

weight annually of standard gaseous hydrocarbon fuels and 

feedstocks having consistent composition (e.g., natural 

gas). For other gaseous fuels and feedstocks (e.g., 

biogas, refinery gas, or process gas), sample and analyze 

no less frequently than weekly to determine the carbon 

content and molecular weight of the fuel and feedstock. 

* * * * * 

(5) You must use the following applicable methods to 

determine the carbon content for all fuels and feedstocks, 
Page 365 of 442 

and molecular weight of gaseous fuels and feedstocks. 

Alternatively, you may use the results of continuous 

chromatographic analysis of the fuel and feedstock, 

provided that the gas chromatograph (GC) is operated, 

maintained, and calibrated according to the manufacturer’s 

instructions; and the methods used for operation, 

maintenance, and calibration of the GC are documented in 

the written monitoring plan for the unit under §98.3(g)(5). 

* * * * * 

Subpart V—[Amended] 

33. Section 98.226 is revised by removing paragraph 

(o). 

Subpart X—[Amended] 

34. Section 98.240 is amended by revising paragraph 

(a); and by adding paragraph (g) to read as follows: 

§98.240 Definition of the source category.

(a) The petrochemical production source category 

consists of all processes that produce acrylonitrile, 

carbon black, ethylene, ethylene dichloride, ethylene 

oxide, or methanol, except as specified in paragraphs (b) 

through (g) of this section. The source category includes 

processes that produce the petrochemical as an intermediate 

in the on-site production of other chemicals as well as 
Page 366 of 442 

processes that produce the petrochemical as an end product 

for sale or shipment off site. 

* * * * * 

(g) A process that solely distills or recycles waste 

solvent that contains a petrochemical is not part of the 

petrochemical production source category. 

35. Section 98.242 is amended by revising paragraph 

(a)(1) and paragraph (b) introductory text to read as 

follows: 

§98.242 GHGs to report.

* * * * * 

(a) * * * 

(1) If you comply with §98.243(b) or (d), report 

under this subpart the calculated CO2, CH4, and N2O 

emissions for each stationary combustion source and flare 

that burns any amount of petrochemical process off-gas. If 

you comply with §98.243(b), also report under this subpart 

the measured CO2 emissions from process vents routed to 

stacks that are not associated with stationary combustion 

units. 

* * * * * 

(b) CO2, CH4, and N2O combustion emissions from 

stationary combustion units. 

* * * * * 
Page 367 of 442 

36. Section 98.243 is amended by: 

a. Revising the second sentence of paragraph (b). 

b. Revising paragraph (c)(3). 

c. Revising the definition of “MVC” in Equation X-1 

in paragraph (c)(5)(i). 

d. Revising paragraph (d). 

§98.243 Calculating GHG emissions.

* * * * * 

(b) * * * For each stack (except flare stacks) 

that includes emissions from combustion of petrochemical 

process off-gas, calculate CH4 and N20 emissions in 

accordance with subpart C of this part (use the Tier 3 

methodology, emission factors for “Petroleum” in Table C-2 

of subpart C of this part, and either the default high heat 

value for fuel gas in Table C-1 of subpart C of this part 

or a calculated HHV, as allowed in Equation C-8 of subpart 

C of this part). * * * 

(c) * * * 

(3) Collect a sample of each feedstock and product at 

least once per month and determine the carbon content of 

each sample according to the procedures of §98.244(b)(4). 

If multiple valid carbon content measurements are made 

during the monthly measurement period, average them 

arithmetically. However, if a particular liquid or solid 
Page 368 of 442 

feedstock is delivered in lots, and if multiple deliveries 

of the same feedstock are received from the same supply 

source in a given calendar month, only one representative 

sample is required. Alternatively, you may use the results 

of analyses conducted by a fuel or feedstock supplier, 

provided the sampling and analysis is conducted at least 

once per month using any of the procedures specified in 

§98.244(b)(4). 

* * * * * 

(5) * * * 

(i) * * * * * 

MVC = Molar volume conversion factor (849.5 scf per 

kg-mole at 68 °F and 14.7 pounds per square 

inch absolute or 836.6 scf/kg-mole at 60 °F and 

14.7 pounds per square inch absolute). 

* * * * * 

(d) Optional combustion methodology for ethylene 

production processes. For each ethylene production 

process, calculate GHG emissions from combustion units that 

burn fuel that contains any off-gas from the ethylene 

process as specified in paragraphs (d)(1) through (d)(5) of 

this section. 

(1) Except as specified in paragraphs (d)(2) and 

(d)(5) of this section, calculate CO2 emissions using the 

Tier 3 or Tier 4 methodology in subpart C of this part. 
Page 369 of 442 

(2) You may use either Equation C-1 or Equation C-2a 

in subpart C of this part to calculate CO2 emissions from 

combustion of any ethylene process off-gas streams that 

meet either of the conditions in paragraphs (d)(2)(i) or 

(d)(2)(ii) of this section (for any default values in the 

calculation, use the defaults for fuel gas in Table C-1 of 

subpart C of this part). Follow the otherwise applicable 

procedures in subpart C to calculate emissions from 

combustion of all other fuels in the combustion unit. 

(i) The annual average flow rate of fuel gas (that 

contains ethylene process off-gas) in the fuel gas line to 

the combustion unit, prior to any split to individual 

burners or ports, does not exceed 345 standard cubic feet 

per minute at 60°F and 14.7 pounds per square inch 

absolute, and a flow meter is not installed at any point in 

the line supplying fuel gas or an upstream common pipe. 

Calculate the annual average flow rate using company 

records assuming total flow is evenly distributed over 

525,600 minutes per year. 

(ii) The combustion unit has a maximum rated heat 

input capacity of less than 30 mmBtu/hr, and a flow meter 

is not installed at any point in the line supplying fuel 

gas (that contains ethylene process off-gas) or an upstream 

common pipe. 
Page 370 of 442 

(3) Except as specified in paragraph (d)(5) of this 

section, calculate CH4 and N2O emissions using the 

applicable procedures in §98.33(c) for the same tier 

methodology that you used for calculating CO2 emissions. 

(i) For all gaseous fuels that contain ethylene 

process off-gas, use the emission factors for “Petroleum” 

in Table C-2 of subpart C of this part (General Stationary 

Fuel Combustion Sources). 

(ii) For Tier 3, use either the default high heat 

value for fuel gas in Table C-1 of subpart C of this part 

or a calculated HHV, as allowed in Equation C-8 of subpart 

C of this part. 

(4) You are not required to use the same Tier for 

each stationary combustion unit that burns ethylene process 

off-gas. 

(5) For each flare, calculate CO2, CH4, and N2O 

emissions using the methodology specified in §98.253(b)(1) 

through (b)(3). 

37. Section 98.244 is amended by revising paragraphs 

(b)(1) through (b)(3), (b)(4) introductory text, and 

(b)(4)(viii); and by adding paragraphs (b)(4)(xi) through 

(b)(4)(xv) to read as follows: 

§98.244 Monitoring and QA/QC requirements.

* * * * * 
Page 371 of 442 

(b) * * * 

(1) Operate, maintain, and calibrate belt scales or 

other weighing devices as described in Specifications, 

Tolerances, and Other Technical Requirements For Weighing 

and Measuring Devices NIST Handbook 44 (2009) (incorporated 

by reference, see §98.7), or follow procedures specified by 

the measurement device manufacturer. You must recalibrate 

each weighing device according to one of the following 

frequencies. You may recalibrate either at the minimum 

frequency specified by the manufacturer or biennially 

(i.e., once every two years). 

(2) Operate and maintain all flow meters used for gas 

and liquid feedstocks and products according to the 

manufacturer’s recommended procedures. You must calibrate 

each of these flow meters as specified in paragraphs 

(b)(2)(i) and (b)(2)(ii) of this section: 

(i) You may use either the calibration methods 

specified by the flow meter manufacturer or an industry 

consensus standard method. Each flow meter must meet the 

applicable accuracy specification in §98.3(i), except as 

otherwise specified in §§98.3(i)(4) through (i)(6). 

(ii) You must recalibrate each flow meter according to 

one of the following frequencies. You may recalibrate at 

the minimum frequency specified by the manufacturer, 
Page 372 of 442 

biennially (every two years), or at the interval specified 

by the industry consensus standard practice used. 

(3) You must perform tank level measurements (if used 

to determine feedstock or product flows) according to one 

of the following methods. You may use any standard method 

published by a consensus-based standards organization or 

you may use an industry standard practice. Consensus-based 

standards organizations include, but are not limited to, 

the following: ASTM International (100 Barr Harbor Drive, 

P.O. Box CB700, West Conshohocken, Pennsylvania 19428-

B2959, (800) 262-1373, http://www.astm.org), the American 

National Standards Institute (ANSI, 1819 L Street, N.W., 

6th floor, Washington, DC 20036, (202) 293-8020, 

http://www.ansi.org), the American Gas Association (AGA, 

400 North Capitol Street, N.W., 4th Floor, Washington, DC 

20001, (202) 824-7000, http://www.aga.org), the American 

Society of Mechanical Engineers (ASME, Three Park Avenue, 

New York, NY 10016-5990, (800) 843-2763, 

http://www.asme.org), the American Petroleum Institute 

(API, 1220 L Street, N.W., Washington, DC 20005-4070,(202) 

682-8000, http://www.api.org), and the North American 

Energy Standards Board (NAESB, 801 Travis Street, Suite 

1675, Houston, TX 77002, (713) 356-0060, 

http://www.api.org). 
Page 373 of 442 

(4) Beginning January 1, 2010, use any applicable 

methods specified in paragraphs (b)(4)(i) through 

(b)(4)(xiv) of this section to determine the carbon content 

or composition of feedstocks and products and the average 

molecular weight of gaseous feedstocks and products. 

Calibrate instruments in accordance with paragraphs 

(b)(4)(i) through (b)(4)(xvi), as applicable. For coal 

used as a feedstock, the samples for carbon content 

determinations shall be taken at a location that is 

representative of the coal feedstock used during the 

corresponding monthly period. For carbon black products, 

samples shall be taken of each grade or type of product 

produced during the monthly period. Samples of coal 

feedstock or carbon black product for carbon content 

determinations may be either grab samples collected and 

analyzed monthly or a composite of samples collected more 

frequently and analyzed monthly. Analyses conducted in 

accordance with methods specified in paragraphs (b)(4)(i) 

through (b)(4)(xv) of this section may be performed by the 

owner or operator, by an independent laboratory, or by the 

supplier of a feedstock. 

* * * * * 

(viii) Method 8015C, Method 8021B, Method 8031, or 

Method 9060A (all incorporated by reference, see §98.7). 
Page 374 of 442 

* * * * * 

(xi) ASTM D2593-93 (Reapproved 2009) Standard Test 

Method for Butadiene Purity and Hydrocarbon Impurities by 

Gas Chromatography, (incorporated by reference, see §98.7). 

(xii) ASTM D7633-10 Standard Test Method for Carbon 

Black—Carbon Content, (incorporated by reference, see 

§98.7). 

(xiii) The results of chromatographic analysis of a 

feedstock or product, provided that the gas chromatograph 

is operated, maintained, and calibrated according to the 

manufacturer’s instructions. 

(xiv) The carbon content results of mass spectrometer 

analysis of a feedstock or product, provided that the mass 

spectrometer is operated, maintained, and calibrated 

according to the manufacturer’s instructions. 

(xv) Beginning on January 1, 2010, the methods 

specified in paragraphs (b)(4)(xv)(A) and (B) of this 

section may be used as alternatives for the methods 

specified in paragraphs (b)(4)(i) though (b)(4)(xiv) of 

this section. 

(A) An industry standard practice for carbon black 

feedstock oils and carbon black products. 

(B) Modifications of existing analytical methods or 

other methods that are applicable to your process provided 
Page 375 of 442 

that the methods listed in paragraphs (b)(4)(i) through 

(b)(4)(xiv) of this section are not appropriate because the 

relevant compounds cannot be detected, the quality control 

requirements are not technically feasible, or use of the 

method would be unsafe. 

38. Section 98.246 is amended by: 

a. Revising paragraphs (a) introductory text and 

(a)(4). 

b. Removing and reserving paragraph (a)(7). 

c. Revising paragraph (a)(10). 

d. Adding paragraph (a)(11). 

e. Revising paragraphs (b) introductory text, and 

(b)(1) through (b)(5). 

f. Revising paragraph (c). 

§98.246 Data reporting requirements.

* * * * * 

(a) If you use the mass balance methodology in 

§98.243(c), you must report the information specified in 

paragraphs (a)(1) through (a)(11) of this section for each 

type of petrochemical produced, reported by process unit. 

* * * * * 

(4) Each of the monthly volume, mass, and carbon 

content values used in Equations X-1 through X-3 of this 

subpart (i.e., the directly measured values, substitute 
Page 376 of 442 

values, or the calculated values based on other measured 

data such as tank levels or gas composition) and the 

molecular weights for gaseous feedstocks and products used 

in Equation X-1 of this subpart, and the temperature (in 

°F) at which the gaseous feedstock and product volumes used 

in Equation X-1 of this subpart were determined. Indicate 

whether you used the alternative to sampling and analysis 

specified in §98.243(c)(4). 

* * * * * 

(10) You may elect to report the flow and carbon 

content of wastewater, and you may elect to report the 

annual mass of carbon released in fugitive emissions and in 

process vents that are not controlled with a combustion 

device. These values may be estimated based on engineering 

analyses. These values are not to be used in the mass 

balance calculation. 

(11) If you determine carbon content or composition 

of a feedstock or product using a method under 

§98.244(b)(4)(xv)(B), report the information listed in 

paragraphs (a)(11)(i) through (a)(11)(iv) of this section. 

Include the information in paragraph (a)(11)(i) of this 

section in each annual report. Include the information in 

paragraphs (a)(11)(ii) and (a)(11)(iii) of this section 
Page 377 of 442 

only in the first applicable annual report, and provide any 

changes to this information in subsequent annual reports. 

(i) Name or title of the analytical method. 

(ii) A copy of the method. If the method is a 

modification of a method listed in §98.244(b)(4)(i) through 

(xiv), you may provide a copy of only the sections that 

differ from the listed method. 

(iii) An explanation of why an alternative to the 

methods listed in §98.244(b)(4)(i) through (xii) is needed. 

(b) If you measure emissions in accordance with 

§98.243(b), then you must report the information listed in 

paragraphs (b)(1) through (b)(8) of this section. 

(1) The petrochemical process unit ID or other 

appropriate descriptor, and the type of petrochemical 

produced. 

(2) For CEMS used on stacks for stationary combustion 

units, report the relevant information required under 

§98.36 for the Tier 4 calculation methodology. Section 

98.36(b)(9)(iii) does not apply for the purposes of this 

subpart. 

(3) For CEMS used on stacks that are not used for 

stationary combustion units, report the information 

required under §98.36(e)(2)(vi). 
Page 378 of 442 

(4) The CO2 emissions from each stack and the combined 

CO2 emissions from all stacks (except flare stacks) that 

handle process vent emissions and emissions from stationary 

combustion units that burn process off-gas for the 

petrochemical process unit. For each stationary combustion 

unit (or group of combustion units monitored with a single 

CO2 CEMS) that burns petrochemical process off-gas, provide 

an estimate based on engineering judgment of the fraction 

of the total emissions that is attributable to combustion 

of off-gas from the petrochemical process unit. 

(5) For stationary combustion units that burn process 

off-gas from the petrochemical process unit, report the 

information related to CH4 and N2O emissions as specified in 

paragraphs (b)(5)(i) through (b)(5)(iv) of this section. 

(i) The CH4 and N2O emissions from each stack that is 

monitored with a CO2 CEMS, expressed in metric tons of each 

gas and in metric tons of CO2e. For each stack provide an 

estimate based on engineering judgment of the fraction of 

the total emissions that is attributable to combustion of 

off-gas from the petrochemical process unit. 

(ii) The combined CH4 and N2O emissions from all 

stationary combustion units, expressed in metric tons of 

each gas and in metric tons of CO2e. 
Page 379 of 442 

(iii) The quantity of each type of fuel used in 

Equation C-8 in §98.33(c) for each stationary combustion 

unit or group of units (as applicable) during the reporting 

year, expressed in short tons for solid fuels, gallons for 

liquid fuels, and scf for gaseous fuels. 

(iv) The HHV (either default or annual average from 

measured data) used in Equation C-8 in §98.33(c) for each 

stationary combustion unit or group of combustion units (as 

applicable). 

* * * * * 

(c) If you comply with the combustion methodology 

specified in §98.243(d), you must report under this subpart 

the information listed in paragraphs (c)(1) through (c)(5) 

of this section. 

(1) The ethylene process unit ID or other appropriate 

descriptor. 

(2) For each stationary combustion unit that burns 

ethylene process off-gas (or group of stationary sources 

with a common pipe), except flares, the relevant 

information listed in §98.36 for the applicable Tier 

methodology. For each stationary combustion unit or group 

of units (as applicable) that burns ethylene process offgas, provide an estimate based on engineering judgment of 
Page 380 of 442 

the fraction of the total emissions that is attributable to 

combustion of off-gas from the ethylene process unit. 

(3) Information listed in §98.256(e) of subpart Y of 

this part for each flare that burns ethylene process offgas. 

(4) Name and annual quantity of each feedstock. 

(5) Annual quantity of ethylene produced from each 

process unit (metric tons). 

39. Section 98.247 is amended by: 

a. Revising paragraph (a). 

b. Adding paragraph (b)(4). 

c. Revising paragraph (c). 

§98.247 Records that must be retained.

* * * * * 

(a) If you comply with the CEMS measurement 

methodology in §98.243(b), then you must retain under this 

subpart the records required for the Tier 4 Calculation 

Methodology in §98.37, records of the procedures used to 

develop estimates of the fraction of total emissions 

attributable to combustion of petrochemical process off-gas 

as required in §98.246(b), and records of any annual 

average HHV calculations. 

(b) * * * 
Page 381 of 442 

(4) The dates and results (e.g., percent calibration 

error) of the calibrations of each measurement device. 

(c) If you comply with the combustion methodology in 

§98.243(d), then you must retain under this subpart the 

records required for the applicable Tier Calculation 

Methodologies in §98.37. If you comply with §98.243(d)(2), 

you must also keep records of the annual average flow 

calculations. 

Subpart Y—[Amended] 

40. Section 98.252 is amended by revising paragraph 

(a) and the first sentence of paragraph (i) to read as 

follows: 

§98.252 GHGs to report.

* * * * * 

(a) CO2, CH4, and N2O combustion emissions from 

stationary combustion units and from each flare. Calculate 

and report the emissions from stationary combustion units 

under subpart C of this part (General Stationary Fuel 

Combustion Sources) by following the requirements of 

subpart C, except for emissions from combustion of fuel 

gas. For CO2 emissions from combustion of fuel gas, use 

either Equation C-5 in subpart C of this part or the Tier 4 

methodology in subpart C of this part, unless either of the 

conditions in paragraphs (a)(1) or (2) of this section are 
Page 382 of 442 

met, in which case use either Equations C-1 or C-2a in 

subpart C of this part. For CH4 and N2O emissions from 

combustion of fuel gas, use the applicable procedures in 

§98.33(c) for the same tier methodology that was used for 

calculating CO2 emissions. (Use the default CH4 and N2O 

emission factors for “Petroleum (All fuel types in Table C1)” in Table C-2 of this part. For Tier 3, use either the 

default high heat value for fuel gas in Table C-1 of 

subpart C of this part or a calculated HHV, as allowed in 

Equation C-8 of subpart C of this part.) You may aggregate 

units, monitor common stacks, or monitor common (fuel) 

pipes as provided in §98.36(c) when calculating and 

reporting emissions from stationary combustion units. 

Calculate and report the emissions from flares under this 

subpart. 

(1) The annual average fuel gas flow rate in the fuel 

gas line to the combustion unit, prior to any split to 

individual burners or ports, does not exceed 345 standard 

cubic feet per minute at 60oF and 14.7 pounds per square 

inch absolute and either of the conditions in paragraph 

(a)(1)(i) or (ii) of this section exist. Calculate the 

annual average flow rate using company records assuming 

total flow is evenly distributed over 525,600 minutes per 

year. 
Page 383 of 442 

(i) A flow meter is not installed at any point in the 

line supplying fuel gas or an upstream common pipe. 

(ii) The fuel gas line contains only vapors from 

loading or unloading, waste or wastewater handling, and 

remediation activities that are combusted in a thermal 

oxidizer or thermal incinerator. 

(2) The combustion unit has a maximum rated heat 

input capacity of less than 30 mmBtu/hr and either of the 

following conditions exist: 

(i) A flow meter is not installed at any point in the 

line supplying fuel gas or an upstream common pipe; or 

(ii) The fuel gas line contains only vapors from 

loading or unloading, waste or wastewater handling, and 

remediation activities that are combusted in a thermal 

oxidizer or thermal incinerator. 

* * * * * 

(i) CO2 emissions from non-merchant hydrogen 

production process units (not including hydrogen produced 

from catalytic reforming units) under this 

subpart. * * * 

41. Section 98.253 is amended by: 

a. Revising paragraph (b)(1)(ii)(A). 

b. Revising the definition of “(Flare)p” in Equation 

Y-2 in paragraph (b)(1)(ii)(B). 
Page 384 of 442 

c. Revising the definition of “MVC” in Equation Y-3 

in paragraph (b)(1)(iii)(C). 

d. Revising paragraph (c)(1)(ii). 

e. Revising the definition of “MVC” in Equation Y-6 

in paragraph (c)(2)(i). 

f. Revising paragraph (c)(2)(ii). 

g. Revising the definition of “CBQ” and “n” in 

Equation Y-11 in paragraph (e)(3). 

h. Revising the first sentence of paragraph (f) 

introductory text and the last sentence of paragraph 

(f)(1). 

i. Revising the definition of “MVC” in Equation Y-12 

in paragraph (f)(4). 

j. Revising the definition of “Mdust” in Equation Y-13 

in paragraph (g)(2). 

k. Revising paragraphs (h) introductory text and 

(h)(2). 

l. In paragraph (i)(1), revising the first two 

sentences and the definition of “MVC” in Equation Y-18. 

m. In paragraph (j), revising the first two 

sentences; and revising the definitions of “(VR)p,” 

“(MFx)p,” and “MVC” in Equation Y-19. 

n. In paragraph (k), revising the first sentence and 

the definition of “MVC” in Equation Y-20. 
Page 385 of 442 

o. Revising paragraph (m) introductory text. 

p. Revising the only sentence of paragraph (m)(1). 

p. Revising the definitions of “MFCH4” and “MVC” in 

Equation Y-23 in paragraph (m)(2). 

q. Revising paragraph (n). 

§98.253 Calculating GHG emissions.

* * * * * 

(b) * * * 

(1) * * * 

(ii) * * * 

(A) If you monitor gas composition, calculate the CO2

emissions from the flare using either Equation Y-1a or 

Equation Y-1b of this section. If daily or more frequent 

measurement data are available, you must use daily values 

when using Equation Y-1a or Equation Y-1b of this section; 

otherwise, use weekly values. 

( )

( )

( )

































= × × ∑ × × ×

=

n

p

p

p

p CC

MVC

MW

CO Flare

1

2

12

44 0.98 0.001 (Eq.Y-1a) 

Where: 

CO2 = Annual CO2 emissions for a specific fuel type 

(metric tons/year). 

0.98 = Assumed combustion efficiency of a flare. 

0.001 = Unit conversion factor (metric tons per 

kilogram, mt/kg). 

n = Number of measurement periods. The minimum 

value for n is 52 (for weekly measurements); 
Page 386 of 442 

the maximum value for n is 366 (for daily 

measurements during a leap year). 

p = Measurement period index. 

44 = Molecular weight of CO2 (kg/kg-mole). 

12 = Atomic weight of C (kg/kg-mole). 

(Flare)p = Volume of flare gas combusted during 

measurement period (standard cubic feet per 

period, scf/period). If a mass flow meter is 

used, measure flare gas flow rate in kg/period 

and replace the term “(MW)p/MVC” with “1”. 

(MW)p = Average molecular weight of the flare gas 

combusted during measurement period (kg/kgmole). If measurements are taken more 

frequently than daily, use the arithmetic 

average of measurement values within the day 

to calculate a daily average. 

MVC = Molar volume conversion factor (849.5 scf/kgmole at 68 oF and 14.7 pounds per square inch 

absolute (psia) or 836.6 scf/kg-mole at 60 oF 

and 14.7 psia). 

(CC)p = Average carbon content of the flare gas 

combusted during measurement period (kg C per 

kg flare gas). If measurements are taken more 

frequently than daily, use the arithmetic 

average of measurement values within the day 

to calculate a daily average. 

( )

( ) ( )

∑ ∑ = = 











































= × × × + × ×

n

p

y

x

x

p x p

p CMN

CO C

MVC

CO Flare

1 1

2

2

100%

%

0.98

100%

%

0.001 44

(Eq.Y-1b) 

Where: 

CO2 = Annual CO2 emissions for a specific fuel type 

(metric tons/year). 

n = Number of measurement periods. The minimum 

value for n is 52 (for weekly measurements); 

the maximum value for n is 366 (for daily 

measurements during a leap year). 

p = Measurement period index. 
Page 387 of 442 

(Flare)p = Volume of flare gas combusted during 

measurement period (standard cubic feet per 

period, scf/period). If a mass flow meter is 

used, you must determine the average molecular 

weight of the flare gas during the measurement 

period and convert the mass flow to a 

volumetric flow. 

44 = Molecular weight of CO2 (kg/kg-mole). 

MVC = Molar volume conversion factor (849.5 scf/kgmole at 68oF and 14.7 psia or 836.6 scf/kgmole at 60oF and 14.7 psia). 

0.001 = Unit conversion factor (metric tons per 

kilogram, mt/kg). 

(%CO2)p = Mole percent CO2 concentration in the flare 

gas stream during the measurement period (mole 

percent = percent by volume). 

y = Number of carbon-containing compounds other 

than CO2 in the flare gas stream. 

x = Index for carbon-containing compounds other 

than CO2. 

0.98 = Assumed combustion efficiency of a flare (mole 

CO2 per mole carbon). 

(%Cx)p = Mole percent concentration of compound “x” in 

the flare gas stream during the measurement 

period (mole percent = percent by volume) 

CMNx = Carbon mole number of compound “x” in the 

flare gas stream (mole carbon atoms per mole 

compound). E.g., CMN for ethane (C2H6) is 2; 

CMN for propane (C3H8) is 3. 

(B) * * * * * 

(Flare)p = Volume of flare gas combusted during 

measurement period (million (MM) scf/period). 

If a mass flow meter is used, you must also 

measure molecular weight and convert the mass 

flow to a volumetric flow as follows: 

Flare[MMscf] = 0.000001 × Flare[kg] × 

MVC/(MW)p, where MVC is the molar volume 

conversion factor [849.5 scf/kg-mole at 68 oF 

and 14.7 psia or 836.6 scf/kg-mole at 60 oF 

and 14.7 psia depending on the standard 
Page 388 of 442 

conditions used when determining (HHV)p] and 

(MW)p is the average molecular weight of the 

flare gas combusted during measurement period 

(kg/kg-mole). 

* * * * * 

(iii) * * * 

(C) * * * * * 

MVC = Molar volume conversion factor (849.5 scf/kgmole at 68 oF and 14.7 psia or 836.6 scf/kgmole at 60 oF and 14.7 psia). 

* * * * * 

(c) * * * 

(1) * * * 

(ii) For catalytic cracking units whose process 

emissions are discharged through a combined stack with 

other CO2 emissions (e.g., co-mingled with emissions from a 

CO boiler) you must also calculate the other CO2 emissions 

using the applicable methods for the applicable subpart 

(e.g., subpart C of this part in the case of a CO boiler). 

Calculate the process emissions from the catalytic cracking 

unit or fluid coking unit as the difference in the CO2 CEMS 

emissions and the calculated emissions associated with the 

additional units discharging through the combined stack. 

(2) * * * 

(i) * * * * * 
Page 389 of 442 

MVC = Molar volume conversion factor (849.5 scf/kgmole at 68 oF and 14.7 psia or 836.6 scf/kg-mole 

at 60 oF and 14.7 psia). 

 (ii) Either continuously monitor the volumetric flow 

rate of exhaust gas from the fluid catalytic cracking unit 

regenerator or fluid coking unit burner prior to the 

combustion of other fossil fuels or calculate the 

volumetric flow rate of this exhaust gas stream using 

either Equation Y-7a or Equation Y-7b of this section. 

( )

% 2 % % 2100

79 * (100 % ) *

CO CO O

Q O Q

Q

a oxy oxy

r

− − −

+ −

=

(Eq. Y-7a) 

Where: 

Qr = Volumetric flow rate of exhaust gas from the 

fluid catalytic cracking unit regenerator or 

fluid coking unit burner prior to the combustion 

of other fossil fuels (dscfh). 

Qa = Volumetric flow rate of air to the fluid 

catalytic cracking unit regenerator or fluid 

coking unit burner, as determined from control 

room instrumentation (dscfh). 

Qoxy = Volumetric flow rate of oxygen enriched air to 

the fluid catalytic cracking unit regenerator or 

fluid coking unit burner as determined from 

control room instrumentation (dscfh). 

%O2 = Hourly average percent oxygen concentration in 

exhaust gas stream from the fluid catalytic 

cracking unit regenerator or fluid coking unit 

burner (percent by volume – dry basis). 

%Ooxy = O2 concentration in oxygen enriched gas stream 

inlet to the fluid catalytic cracking unit 

regenerator or fluid coking unit burner based on 

oxygen purity specifications of the oxygen supply 

used for enrichment (percent by volume – dry 

basis). 
Page 390 of 442 

%CO2 = Hourly average percent CO2 concentration in the 

exhaust gas stream from the fluid catalytic 

cracking unit regenerator or fluid coking unit 

burner (percent by volume – dry basis). 

%CO = Hourly average percent CO concentration in the 

exhaust gas stream from the fluid catalytic 

cracking unit regenerator or fluid coking unit 

burner (percent by volume – dry basis). When no 

auxiliary fuel is burned and a continuous CO 

monitor is not required under 40 CFR part 63 

subpart UUU, assume %CO to be zero. 

( )

exhaust

a oxy oxy

r

N

Q N Q

Q

2,

2,

%

78.1* + (% ) *

= (Eq. Y-7b) 

Where: 

Qr = Volumetric flow rate of exhaust gas from the 

fluid catalytic cracking unit regenerator or 

fluid coking unit burner prior to the combustion 

of other fossil fuels (dscfh). 

Qa = Volumetric flow rate of air to the fluid 

catalytic cracking unit regenerator or fluid 

coking unit burner, as determined from control 

room instrumentation (dscfh). 

Qoxy = Volumetric flow rate of oxygen enriched air to 

the fluid catalytic cracking unit regenerator or 

fluid coking unit burner as determined from 

control room instrumentation (dscfh). 

%N2,oxy = N2 concentration in oxygen enriched gas stream 

inlet to the fluid catalytic cracking unit 

regenerator or fluid coking unit burner based on 

measured value or maximum N2 impurity 

specifications of the oxygen supply used for 

enrichment (percent by volume – dry basis). 

%N2,exhaust = Hourly average percent N2 concentration in the 

exhaust gas stream from the fluid catalytic 

cracking unit regenerator or fluid coking unit 

burner (percent by volume – dry basis). 

* * * * * 

(e) * * * 
Page 391 of 442 

(3) * * * * * 

CBQ = Coke burn-off quantity per regeneration cycle or 

measurement period from engineering estimates 

(kg coke/cycle or kg coke/measurement period). 

n = Number of regeneration cycles or measurement 

periods in the calendar year. 

* * * * * 

(f) For on-site sulfur recovery plants and for sour 

gas sent off site for sulfur recovery, calculate and report 

CO2 process emissions from sulfur recovery plants according 

to the requirements in paragraphs (f)(1) through (f)(5) of 

this section, or, for non-Claus sulfur recovery plants, 

according to the requirements in paragraph (j) of this 

section regardless of the concentration of CO2 in the vented 

gas stream. * * * 

(1) * * * Other sulfur recovery plants must 

either install a CEMS that complies with the Tier 4 

Calculation Methodology in subpart C, or follow the 

requirements of paragraphs (f)(2) through (f)(5) of this 

section, or (for non-Claus sulfur recovery plants only) 

follow the requirements in paragraph (j) of this section to 

determine CO2 emissions for the sulfur recovery plant. 

* * * * * 

(4) * * * * * 
Page 392 of 442 

MVC = Molar volume conversion factor (849.5 scf/kg-mole 

at 68 oF and 14.7 psia or 836.6 scf/kg-mole at 60 

oF and 14.7 psia). 

* * * * * 

(g) * * * 

(2) * * * * * 

Mdust = Annual mass of petroleum coke dust removed from 

the process through the dust collection system 

of the coke calcining unit from facility records 

(metric ton petroleum coke dust/year). For coke 

calcining units that recycle the collected dust, 

the mass of coke dust removed from the process 

is the mass of coke dust collected less the mass 

of coke dust recycled to the process. 

* * * * * 

(h) For asphalt blowing operations, calculate CO2 and 

CH4 emissions according to the requirements in paragraph (j) 

of this section regardless of the CO2 and CH4 concentrations 

or according to the applicable provisions in paragraphs 

(h)(1) and (h)(2) of this section. 

* * * * * 

(2) For asphalt blowing operations controlled by 

thermal oxidizer or flare, calculate CO2 using either 

Equation Y-16a or Equation Y-16b of this section and 

calculate CH4 emissions using Equation Y-17 of this section, 

provided these emissions are not already included in the 

flare emissions calculated in paragraph (b) of this section 

or in the stationary combustion unit emissions required 
Page 393 of 442 

under subpart C of this part (General Stationary Fuel 

Combustion Sources). 













= × × ×

12

44 0.98 CO2 QAB CEFAB (Eq. Y-16a) 

Where: 

CO2 = Annual CO2 emissions from controlled asphalt 

blowing (metric tons CO2/year). 

0.98 = Assumed combustion efficiency of thermal oxidizer 

or flare. 

QAB = Quantity of asphalt blown (MMbbl/year). 

CEFAB = Carbon emission factor from asphalt blowing from 

facility-specific test data (metric tons C/MMbbl 

asphalt blown); default = 2,750. 

44 = Molecular weight of CO2 (kg/kg-mole). 

12 = Atomic weight of C (kg/kg-mole). 





























 −











2 = × , 2 + × × , 2

12

44 CO QAB EFAB CO 0.98 CEFAB EFAB CO (Eq. Y-16b) 

Where: 

CO2 = Annual CO2 emissions from controlled asphalt 

blowing (metric tons CO2/year). 

QAB = Quantity of asphalt blown (MMbbl/year). 

0.98 = Assumed combustion efficiency of thermal oxidizer 

or flare. 

EFAB,CO2 = Emission factor for CO2 from uncontrolled asphalt 

blowing from facility-specific test data (metric 

tons CO2/MMbbl asphalt blown); default = 1,100. 

CEFAB = Carbon emission factor from asphalt blowing from 

facility-specific test data (metric tons C/MMbbl 

asphalt blown); default = 2,750. 

44 = Molecular weight of CO2 (kg/kg-mole). 

12 = Atomic weight of C (kg/kg-mole). 
Page 394 of 442 

( ) 4 02 , 4 0. CH = × QAB × EFAB CH (Eq. Y-17) 

Where: 

CH4 = Annual methane emissions from controlled asphalt 

blowing (metric tons CH4/year). 

0.02 = Fraction of methane uncombusted in thermal 

oxidizer or flare based on assumed 98% combustion 

efficiency. 

QAB = Quantity of asphalt blown (million barrels per 

year, MMbbl/year). 

EFAB,CH4 = Emission factor for CH4 from uncontrolled asphalt 

blowing from facility-specific test data (metric 

tons CH4/MMbbl asphalt blown); default = 580. 

(i) * * * 

(1) Use the process vent method in paragraph (j) of 

this section to calculate the CH4 emissions from the 

depressurization of the coke drum or vessel regardless of 

the CH4 concentration and also calculate the CH4 emissions 

from the subsequent opening of the vessel for coke cutting 

operations using Equation Y-18 of this section. If you 

have coke drums or vessels of different dimensions, use the 

process vent method in paragraph (j) of this section and 

Equation Y-18 for each set of coke drums or vessels of the 

same size and sum the resultant emissions across each set 

of coke drums or vessels to calculate the CH4 emissions for 

all delayed coking units. 

* * * * * 
Page 395 of 442 

MVC = Molar volume conversion factor (849.5 scf/ kgmole at 68 oF and 14.7 psia or 836.6 scf/kg-mole 

at 60 oF and 14.7 psia). 

* * * * * 

(j) For each process vent not covered in paragraphs 

(a) through (i) of this section that can reasonably be 

expected to contain greater than 2 percent by volume CO2 or 

greater than 0.5 percent by volume of CH4 or greater than 

0.01 percent by volume (100 parts per million) of N2O, 

calculate GHG emissions using the Equation Y-19 of this 

section. You must use Equation Y-19 of this section to 

calculate CH4 emissions for catalytic reforming unit 

depressurization and purge vents when methane is used as 

the purge gas or if you elected this method as an 

alternative to the methods in paragraphs (f), (h), or (k) 

of this section. 

* * * * * 

(VR)p = Average volumetric flow rate of process gas 

during the event (scf per hour) from measurement 

data, process knowledge, or engineering 

estimates. 

(MFx)p = Mole fraction of GHG x in process vent during 

the event (kg-mol of GHG x/kg-mol vent gas) from 

measurement data, process knowledge, or 

engineering estimates. 

* * * * * 

MVC = Molar volume conversion factor (849.5 scf/kgmole at 68 oF and 14.7 psia or 836.6 scf/kg-mole 

at 60 oF and 14.7 psia). 
Page 396 of 442 

* * * * * 

(k) For uncontrolled blowdown systems, you must 

calculate CH4 emissions either using the methods for 

process vents in paragraph (j) of this section regardless 

of the CH4 concentration or using Equation Y­20 of this 

section. * * * 

* * * * * 

MVC = Molar volume conversion factor (849.5 scf/kgmole at 68 oF and 14.7 psia or 836.6 scf/kg-mole 

at 60 oF and 14.7 psia). 

* * * * * 

(m) For storage tanks, except as provided in 

paragraph (m)(4) of this section, calculate CH4 emissions 

using the applicable methods in paragraphs (m)(1) through 

(m)(3) of this section. 

(1) For storage tanks other than those processing 

unstabilized crude oil, you must either calculate CH4

emissions from storage tanks that have a vapor-phase 

methane concentration of 0.5 volume percent or more using 

tank-specific methane composition data (from measurement 

data or product knowledge) and the emission estimation 

methods provided in AP 42, Section 7.1 (incorporated by 

reference, see §98.7) or estimate CH4 emissions from 

storage tanks using Equation Y-22 of this section. 

* * * * * 
Page 397 of 442 

(2) * * * * * 

MFCH4 = Average mole fraction of CH4 in vent gas from the 

unstabilized crude oil storage tanks from 

facility measurements (kg-mole CH4/kg-mole gas); 

use 0.27 as a default if measurement data are 

not available. 

* * * * * 

MVC = Molar volume conversion factor (849.5 scf/kgmole at 68 oF and 14.7 psia or 836.6 scf/kg-mole 

at 60 oF and 14.7 psia). 

* * * * * 

(n) For crude oil, intermediate, or product loading 

operations for which the vapor-phase concentration of 

methane is 0.5 volume percent or more, calculate CH4

emissions from loading operations using vapor-phase methane 

composition data (from measurement data or process 

knowledge) and the emission estimation procedures provided 

in AP 42, Section 5.2 (incorporated by reference, see 

§98.7). For loading operations in which the vapor-phase 

concentration of methane is less than 0.5 volume percent, 

you may assume zero methane emissions. 

42. Section 98.254 is amended by: 

a. Revising paragraph (a). 

b. Revising paragraph (b). 

c. Revising paragraph (c). 

d. Revising paragraph (d) introductory text 

e. Adding paragraph (d)(6). 
Page 398 of 442 

f. Revising paragraph (e) introductory text. 

g. Revising paragraph (f) introductory text and 

(f)(1). 

h. Removing and reserving paragraph (f)(2). 

i. Removing paragraph (f)(4). 

j. Revising paragraph (g). 

k. Revising the second sentence of paragraph (h). 

l. Removing paragraph (l). 

§98.254 Monitoring and QA/QC requirements. 

(a) Fuel flow meters, gas composition monitors, and 

heating value monitors that are associated with sources 

that use a CEMS to measure CO2 emissions according to 

subpart C of this part or that are associated with 

stationary combustion sources must meet the applicable 

monitoring and QA/QC requirements in §98.34. 

(b) All gas flow meters, gas composition monitors, 

and heating value monitors that are used to provide data 

for the GHG emissions calculations in this subpart for 

sources other than those subject to the requirements in 

paragraph (a) of this section shall be calibrated according 

to the procedures specified by the manufacturer, or 

according to the procedures in the applicable methods 

specified in paragraphs (c) through (g) of this section. 

In the case of gas flow meters, all gas flow meters must 
Page 399 of 442 

meet the calibration accuracy requirements in §98.3(i). 

All gas flow meters, gas composition monitors, and heating 

value monitors must be recalibrated at the applicable 

frequency specified in paragraph (b)(1) or (b)(2) of this 

section. 

(1) You must recalibrate each gas flow meter according 

to one of the following frequencies. You may recalibrate 

at the minimum frequency specified by the manufacturer, 

biennially (every two years), or at the interval specified 

by the industry consensus standard practice used. 

(2) You must recalibrate each gas composition monitor 

and heating value monitor according to one of the following 

frequencies. You may recalibrate at the minimum frequency 

specified by the manufacturer, annually, or at the interval 

specified by the industry standard practice used. 

(c) For flare or sour gas flow meters and gas flow 

meters used to comply with the requirements in §98.253(j), 

operate, calibrate, and maintain the flow meter according 

to one of the following. You may use the procedures 

specified by the flow meter manufacturer, or a method 

published by a consensus-based standards organization. 

Consensus-based standards organizations include, but are 

not limited to, the following: ASTM International (100 Barr 

Harbor Drive, P.O. Box CB700, West Conshohocken, 
Page 400 of 442 

Pennsylvania 19428-B2959, (800) 262-1373, 

http://www.astm.org), the American National Standards 

Institute (ANSI, 1819 L Street, N.W., 6th floor, 

Washington, DC 20036, (202) 293-8020, http://www.ansi.org), 

the American Gas Association (AGA, 400 North Capitol 

Street, N.W., 4th Floor, Washington, DC 20001, (202) 824-

7000, http://www.aga.org), the American Society of 

Mechanical Engineers (ASME, Three Park Avenue, New York, NY 

10016-5990, (800) 843-2763, http://www.asme.org), the 

American Petroleum Institute (API, 1220 L Street, N.W., 

Washington, DC 20005-4070,(202) 682-8000, 

http://www.api.org), and the North American Energy 

Standards Board (NAESB, 801 Travis Street, Suite 1675, 

Houston, TX 77002, (713) 356-0060, http://www.api.org). 

(d) Except as provided in paragraph (g) of this 

section, determine gas composition and, if required, 

average molecular weight of the gas using any of the 

following methods. Alternatively, the results of 

chromatographic analysis of the fuel may be used, provided 

that the gas chromatograph is operated, maintained, and 

calibrated according to the manufacturer’s instructions; 

and the methods used for operation, maintenance, and 

calibration of the gas chromatograph are documented in the 

written Monitoring Plan for the unit under §98.3(g)(5). 
Page 401 of 442 

* * * * * 

(6) ASTM D2503-92 (Reapproved 2007) Standard Test 

Method for Relative Molecular Mass (Molecular Weight) of 

Hydrocarbons by Thermoelectric Measurement of Vapor 

Pressure (incorporated by reference, see §98.7). 

(e) Determine flare gas higher heating value using 

any of the following methods. Alternatively, the results 

of chromatographic analysis of the fuel may be used, 

provided that the gas chromatograph is operated, 

maintained, and calibrated according to the manufacturer’s 

instructions; and the methods used for operation, 

maintenance, and calibration of the gas chromatograph are 

documented in the written Monitoring Plan for the unit 

under §98.3(g)(5). 

* * * * * 

(f) For gas flow meters used to comply with the 

requirements in §98.253(c)(2)(ii), install, operate, 

calibrate, and maintain each gas flow meter according to 

the requirements in 40 CFR 63.1572(c) and the following 

requirements. 

(1) Locate the flow monitor at a site that provides 

representative flow rates. Avoid locations where there is 

swirling flow or abnormal velocity distributions due to 

upstream and downstream disturbances. 
Page 402 of 442 

* * * * * 

(g) For exhaust gas CO2/CO/O2 composition monitors 

used to comply with the requirements in §98.253(c)(2), 

install, operate, calibrate, and maintain exhaust gas 

composition monitors according to the requirements in 40 

CFR 60.105a(b)(2) or 40 CFR 63.1572(c) or according to the 

manufacturer’s specifications and requirements. 

(h) * * * Calibrate the measurement device 

according to the procedures specified by NIST handbook 44 

(incorporated by reference, see §98.7) or the procedures 

specified by the manufacturer. * * * 

* * * * * 

43. Section 98.256 is amended by: 

a. Revising paragraph (e)(6). 

b. Redesignating paragraphs (e)(7) through (e)(9) as 

(e)(8) through (e)(10), respectively. 

c. Adding paragraph (e)(7). 

d. Revising newly designated paragraphs (e)(8) and 

(e)(9). 

e. Revising paragraphs (f)(6) through (f)(8). 

f. Redesignating paragraphs (f)(9) through (f)(12) as 

(f)(10) through (f)(13), respectively. 

g. Adding paragraph (f)(9). 
Page 403 of 442 

h. Revising newly designated paragraphs (f)(11) 

through (f)(13). 

i. Revising paragraphs (g)(5), (h)(2), (h)(4), and 

(h)(6). 

j. Adding paragraph (h)(7). 

k. Revising paragraphs (i)(5), (i)(6), (i)(8), and 

(j)(2). 

l. Redesignating paragraph (j)(8) as (j)(9). 

m. Adding paragraph (j)(8). 

n. Revising paragraphs (k)(1), (k)(3), (l) 

introductory text, (l)(5), and (m). 

o. Revising paragraph (o)(1) through (o)(4). 

§98.256 Data reporting requirements. 

* * * * * 

(e) * * * 

(6) If you use Equation Y-1a of this subpart, an 

indication of whether daily or weekly measurement periods 

are used, the annual volume of flare gas combusted (in 

scf/year) and the annual average molecular weight (in 

kg/kg-mole), the molar volume conversion factor (in scf/kgmole), and annual average carbon content of the flare gas 

(in kg carbon per kg flare gas). 

(7) If you use Equation Y-1b of this subpart, an 

indication of whether daily or weekly measurement periods 
Page 404 of 442 

are used, the annual volume of flare gas combusted (in 

scf/year), the molar volume conversion factor (in scf/kgmole), the annual average CO2 concentration (volume or mole 

percent), the number of carbon containing compounds other 

than CO2 in the flare gas stream, and for each of the carbon 

containing compounds other than CO2 in the flare gas stream: 

(i) The annual average concentration of the compound 

(volume or mole percent). 

(ii) The carbon mole number of the compound (moles 

carbon per mole compound). 

(8) If you use Equation Y-2 of this subpart, an 

indication of whether daily or weekly measurement periods 

are used, the annual volume of flare gas combusted (in 

million (MM) scf/year), the annual average higher heating 

value of the flare gas (in mmBtu/mmscf), and an indication 

of whether the annual volume of flare gas combusted and the 

annual average higher heating value of the flare gas were 

determined using standard conditions of 68 oF and 14.7 psia 

or 60 oF and 14.7 psia. 

(9) If you use Equation Y-3 of this subpart, the 

annual volume of flare gas combusted (in MMscf/year) during 

normal operations, the annual average higher heating value 

of the flare gas (in mmBtu/mmscf), the number of SSM events 

exceeding 500,000 scf/day, the volume of gas flared (in 
Page 405 of 442 

scf/event), the average molecular weight (in kg/kg-mole), 

the molar volume conversion factor (in scf/kg-mole), and 

carbon content of the flare gas (in kg carbon per kg flare) 

for each SSM event over 500,000 scf/day. 

* * * * * 

(f) * * * 

(6) If you use a CEMS, the relevant information 

required under §98.36 for the Tier 4 Calculation 

Methodology, the CO2 annual emissions as measured by the 

CEMS (unadjusted to remove CO2 combustion emissions 

associated with additional units, if present) and the 

process CO2 emissions as calculated according to 

§98.253(c)(1)(ii). Report the CO2 annual emissions 

associated with sources other than those from the coke 

burn-off in the applicable subpart (e.g., subpart C of this 

part in the case of a CO boiler). 

(7) If you use Equation Y-6 of this subpart, the 

annual average exhaust gas flow rate, %CO2, %CO, and the 

molar volume conversion factor (in scf/kg-mole). 

(8) If you use Equation Y-7a of this subpart, the 

annual average flow rate of inlet air and oxygen-enriched 

air, %O2, %Ooxy, %CO2, and %CO. 
Page 406 of 442 

(9) If you use Equation Y-7b of this subpart, the 

annual average flow rate of inlet air and oxygen-enriched 

air, %N2,oxy, and %N2,exhaust. 

* * * * * 

(11) Indicate whether you use a measured value, a 

unit-specific emission factor, or a default emission factor 

for CH4 emissions. If you use a unit-specific emission 

factor for CH4, report the unit-specific emission factor for 

CH4, the units of measure for the unit-specific factor, the 

activity data for calculating emissions (e.g., if the 

emission factor is based on coke burn-off rate, the annual 

quantity of coke burned), and the basis for the factor. 

(12) Indicate whether you use a measured value, a 

unit-specific emission factor, or a default emission factor 

for N2O emissions. If you use a unit-specific emission 

factor for N2O, report the unit-specific emission factor for 

N2O, the units of measure for the unit-specific factor, the 

activity data for calculating emissions (e.g., if the 

emission factor is based on coke burn-off rate, the annual 

quantity of coke burned), and the basis for the factor. 

(13) If you use Equation Y-11 of this subpart, the 

number of regeneration cycles or measurement periods during 

the reporting year, the average coke burn-off quantity per 
Page 407 of 442 

cycle or measurement period, and the average carbon content 

of the coke. 

(g) * * * 

(5) If the GHG emissions for the low heat value gas 

are calculated at the flexicoking unit, also report the 

calculated annual CO2, CH4, and N2O emissions for each unit, 

expressed in metric tons of each pollutant emitted, and the 

applicable equation input parameters specified in 

paragraphs (f)(7) through (f)(13) of this section. 

(h) * * * 

(2) Maximum rated throughput of each independent 

sulfur recovery plant, in metric tons sulfur 

produced/stream day, a description of the type of sulfur 

recovery plant, and an indication of the method used to 

calculate CO2 annual emissions for the sulfur recovery plant 

(e.g., CO2 CEMS, Equation Y-12, or process vent method in 

§98.253(j)). 

* * * * * 

(4) If you use Equation Y-12 of this subpart, the 

annual volumetric flow to the sulfur recovery plant (in 

scf/year), the molar volume conversion factor (in scf/kgmole), and the annual average mole fraction of carbon in 

the sour gas (in kg-mole C/kg-mole gas). 

* * * * * 
Page 408 of 442 

(6) If you use a CEMS, the relevant information 

required under §98.36 for the Tier 4 Calculation 

Methodology, the CO2 annual emissions as measured by the 

CEMS and the annual process CO2 emissions calculated 

according to §98.253(f)(1). * * * 

(7) If you use the process vent method in §98.253(j) 

for a non-Claus sulfur recovery plant, the relevant 

information required under paragraph (l)(5) of this 

section. 

(i) * * * 

(5) If you use Equation Y-13 of this subpart, annual 

mass and carbon content of green coke fed to the unit, the 

annual mass and carbon content of marketable coke produced, 

the annual mass of coke dust removed from the process 

through dust collection systems, and an indication of 

whether coke dust is recycled to the unit (e.g., all dust 

is recycled, a portion of the dust is recycled, or none of 

the dust is recycled). 

(6) If you use a CEMS, the relevant information 

required under §98.36 for the Tier 4 Calculation 

Methodology, the CO2 annual emissions as measured by the 

CEMS and the annual process CO2 emissions calculated 

according to §98.253(g)(1). * * * 

* * * * * 
Page 409 of 442 

(8) Indicate whether you use a measured value, a 

unit-specific emission factor, or a default emission factor 

for N2O emissions. If you use a unit-specific emission 

factor for N2O, report the unit-specific emission factor for 

N2O, the units of measure for the unit-specific factor, the 

activity data for calculating emissions (e.g., if the 

emission factor is based on coke burn-off rate, the annual 

quantity of coke burned), and the basis for the factor. . 

(j) * * * 

(2) The quantity of asphalt blown (in million bbl) at 

the unit in the reporting year. 

* * * * * 

(8) If you use Equation Y-16b of this subpart, the CO2

emission factor used and the basis for its value and the 

carbon emission factor used and the basis for its value. 

* * * * * 

(k) * * * 

(1) The cumulative annual CH4 emissions (in metric 

tons of CH4) for all delayed coking units at the facility. 

* * * * * 

(3) The total number of delayed coking units at the 

facility, the total number of delayed coking drums at the 

facility, and for each coke drum or vessel: the dimensions, 

the typical gauge pressure of the coking drum when first 
Page 410 of 442 

vented to the atmosphere, typical void fraction, the 

typical drum outage (i.e. the unfilled distance from the 

top of the drum, in feet), the molar volume conversion 

factor (in scf/kg-mole), and annual number of coke-cutting 

cycles. 

* * * * * 

(l) For each process vent subject to §98.253(j), the 

owner or operator shall report: 

* * * * * 

(5) The annual volumetric flow discharged to the 

atmosphere (in scf), and an indication of the measurement 

or estimation method, annual average mole fraction of each 

GHG above the concentration threshold or otherwise required 

to be reported and an indication of the measurement or 

estimation method, the molar volume conversion factor (in 

scf/kg-mole), and for intermittent vents, the number of 

venting events and the cumulative venting time. 

(m) For uncontrolled blowdown systems, the owner or 

operator shall report: 

(1) An indication of whether the uncontrolled 

blowdown emission are reported under §98.253(k) or 

§98.253(j) or a statement that the facility does not have 

any uncontrolled blowdown systems. 
Page 411 of 442 

(2) The cumulative annual CH4 emissions (in metric 

tons of CH4) for uncontrolled blowdown systems. 

(3) For uncontrolled blowdown systems reporting under 

§98.253(k), the total quantity (in million bbl) of crude 

oil plus the quantity of intermediate products received 

from off site that are processed at the facility in the 

reporting year, the methane emission factor used for 

uncontrolled blowdown systems, the basis for the value, and 

the molar volume conversion factor (in scf/kg-mole). 

(4) For uncontrolled blowdown systems reporting under 

§98.253(j), the relevant information required under 

paragraph (l)(5) of this section. 

* * * * * 

(o) For storage tanks, the owner or operator shall 

report: 

(1) The cumulative annual CH4 emissions (in metric 

tons of CH4) for all storage tanks, except for those used to 

process unstabilized crude oil. 

(2) For storage tanks other than those processing 

unstabilized crude oil: 

(i) The method used to calculate the reported storage 

tank emissions for storage tanks other than those 

processing unstabilized crude (i.e., either AP 42, Section 
Page 412 of 442 

7.1 (incorporated by reference, see §98.7), or Equation Y22 of this section). 

(ii) The total quantity (in MMbbl) of crude oil plus 

the quantity of intermediate products received from off 

site that are processed at the facility in the reporting 

year. 

(3) The cumulative CH4 emissions (in metric tons of 

CH4) for storage tanks used to process unstabilized crude 

oil or a statement that the facility did not receive any 

unstabilized crude oil during the reporting year. 

(4) For storage tanks that process unstabilized crude 

oil: 

(i) The method used to calculate the reported 

unstabilized crude oil storage tank emissions. 

(ii) The quantity of unstabilized crude oil received 

during the calendar year (in MMbbl). 

(iii) The average pressure differential (in psi). 

(iv) The molar volume conversion factor (in scf/kgmole). 

(v) The average mole fraction of CH4 in vent gas from 

unstabilized crude oil storage tanks and the basis for the 

mole fraction. 

(vi) If you did not use Equation Y-23, the tankspecific methane composition data and the gas generation 
Page 413 of 442 

rate data used to estimate the cumulative CH4 emissions for 

storage tanks used to process unstabilized crude oil. 

* * * * * 

44. Section 98.257 is revised to read as follows: 

§98.257 Records that must be retained. 

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

must retain the records of all parameters monitored under 

§98.255. If you comply with the combustion methodology in 

§98.252(a), then you must retain under this subpart the 

records required for the Tier 3 and/or Tier 4 Calculation 

Methodologies in §98.37 and you must keep records of the 

annual average flow calculations. 

Subpart AA—[Amended] 

45. Section 98.273 is amended by: 

a. Revising paragraphs (a)(1) and (a)(2). 

b. Revising the definition of “EF” in Equation AA-1 

of paragraph (a)(3). 

c. Revising paragraphs (b)(1) and (b)(2). 

d. Revising paragraphs (c)(1) and (c)(2). 

§98.273 Calculating GHG emissions. 

(a) * * * 

(1) Calculate fossil fuel-based CO2 emissions from 

direct measurement of fossil fuels consumed and default 

emissions factors according to the Tier 1 methodology for 
Page 414 of 442 

stationary combustion sources in §98.33(a)(1). A higher 

tier from §98.33(a) may be used to calculate fossil fuelbased CO2 emissions if the respective monitoring and QA/QC 

requirements described in §98.34 are met. 

(2) Calculate fossil fuel-based CH4 and N2O emissions 

from direct measurement of fossil fuels consumed, default 

or site-specific HHV, and default emissions factors and 

convert to metric tons of CO2 equivalent according to the 

methodology for stationary combustion sources in §98.33(c). 

(3) * * * * * 

(EF) = Default or site-specific emission factor for CO2, 

CH4, or N2O, from Table AA–1 of this subpart (kg 

CO2, CH4, or N2O per mmBtu). 

* * * * * 

(b) * * * 

(1) Calculate fossil CO2 emissions from fossil fuels 

from direct measurement of fossil fuels consumed and 

default emissions factors according to the Tier 1 

Calculation Methodology for stationary combustion sources 

in §98.33(a)(1). A higher tier from §98.33(a) may be used 

to calculate fossil fuel-based CO2 emissions if the 

respective monitoring and QA/QC requirements described in 

§98.34 are met. 
Page 415 of 442 

(2) Calculate CH4 and N2O emissions from fossil fuels 

from direct measurement of fossil fuels consumed, default 

or site-specific HHV, and default emissions factors and 

convert to metric tons of CO2 equivalent according to the 

methodology for stationary combustion sources in §98.33(c). 

* * * * * 

(c) * * * 

(1) Calculate CO2 emissions from fossil fuel from 

direct measurement of fossil fuels consumed and default HHV 

and default emissions factors, according to the Tier 1 

Calculation Methodology for stationary combustion sources 

in §98.33(a)(1). A higher tier from §98.33(a) may be used 

to calculate fossil fuel-based CO2 emissions if the 

respective monitoring and QA/QC requirements described in 

§98.34 are met. 

(2) Calculate CH4 and N2O emissions from fossil fuel 

from direct measurement of fossil fuels consumed, default 

or site-specific HHV, and default emissions factors and 

convert to metric tons of CO2 equivalent according to the 

methodology for stationary combustion sources in §98.33(c); 

use the default HHV listed in Table C-1 of subpart C and 

the default CH4 and N2O emissions factors listed in Table 

AA-2 of this subpart. 

* * * * * 
Page 416 of 442 

46. Section 98.276 is amended by revising the 

introductory text and revising paragraph (e) to read as 

follows: 

§98.276 Data reporting requirements. 

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

and the applicable information required by §98.36, each 

annual report must contain the information in paragraphs 

(a) through (k) of this section as applicable: 

* * * * * 

(e) The default or site-specific emission factor for 

CO2, CH4, or N2O, used in Equation AA–1 of this subpart (kg 

CO2, CH4, or N2O per mmBtu). 

47. Table AA-2 is revised to read as follows: 

Table AA-2 of Subpart AA—Kraft Lime Kiln and Calciner 

Emissions Factors for Fossil Fuel-Based CH4 and N2O

Fossil Fuel-Based Emissions Factors (kg/mmBtu HHV) 

Kraft Lime Kilns Kraft Calciners 

Fuel CH4 N2O CH4 N2O 

Residual Oil 0.0003 

Distillate 

Oil 

0.0004 

Natural Gas 0.0001 

Biogas 

0.0027 

0.0001 

Petroleum 

coke 

0.0027 0 

NA NAa

a

Emission factors for kraft calciners are not available.

Subpart OO—[Amended] 

48. Section 98.410 is amended by revising paragraph 

(b) to read as follows: 

§98.410 Definition of the source category.

* * * * * 
Page 417 of 442 

(b) To produce a fluorinated GHG means to manufacture 

a fluorinated GHG from any raw material or feedstock 

chemical. Producing a fluorinated GHG includes the 

manufacture of a fluorinated GHG as an isolated 

intermediate for use in a process that will result in its 

transformation either at or outside of the production 

facility. Producing a fluorinated GHG also includes the 

creation of a fluorinated GHG (with the exception of HFC23) that is captured and shipped off site for any reason, 

including destruction. Producing a fluorinated GHG does 

not include the reuse or recycling of a fluorinated GHG, 

the creation of HFC-23 during the production of HCFC-22, 

the creation of intermediates that are created and 

transformed in a single process with no storage of the 

intermediates, or the creation of fluorinated GHGs that are 

released or destroyed at the production facility before the 

production measurement at §98.414(a). 

* * * * * 

49. Section 98.414 is amended by: 

a. Revising paragraph (a) by adding second and third 

sentences. 

b. Revising paragraph (h). 

c. Removing and reserving paragraph (j). 

d. Adding new paragraphs (n) through (q). 
Page 418 of 442 

§98.414 Monitoring and QA/QC requirements. 

(a) * * * If the measured mass includes more 

than one fluorinated GHG, the concentrations of each of the 

fluorinated GHGs, other than low-concentration 

constituents, shall be measured as set forth in paragraph 

(n) of this section. For each fluorinated GHG, the mean of 

the concentrations of that fluorinated GHG (mass fraction) 

measured under paragraph (n) of this section shall be 

multiplied by the mass measurement to obtain the mass of 

that fluorinated GHG coming out of the production process. 

* * * * * 

(h) You must measure the mass of each fluorinated GHG 

that is fed into the destruction device and that was 

previously produced as defined at §98.410(b). Such 

fluorinated GHGs include but are not limited to quantities 

that are shipped to the facility by another facility for 

destruction and quantities that are returned to the 

facility for reclamation but are found to be irretrievably 

contaminated and are therefore destroyed. You must use 

flowmeters, weigh scales, or a combination of volumetric 

and density measurements with an accuracy and precision of 

one percent of full scale or better. If the measured mass 

includes more than trace concentrations of materials other 

than the fluorinated GHG being destroyed, you must estimate 
Page 419 of 442 

the concentrations of the fluorinated GHG being destroyed 

considering current or previous representative 

concentration measurements and other relevant process 

information. You must multiply this concentration (mass 

fraction) by the mass measurement to obtain the mass of the 

fluorinated GHG fed into the destruction device. 

* * * * * 

(n) If the mass coming out of the production process 

includes more than one fluorinated GHG, you shall measure 

the concentrations of all of the fluorinated GHGs, other 

than low-concentration constituents, as follows: 

(1) Analytical Methods. Use a quality-assured 

analytical measurement technology capable of detecting the 

analyte of interest at the concentration of interest and 

use a procedure validated with the analyte of interest at 

the concentration of interest. Where standards for the 

analyte are not available, a chemically similar surrogate 

may be used. Acceptable analytical measurement 

technologies include but are not limited to gas 

chromatography (GC) with an appropriate detector, infrared 

(IR), fourier transform infrared (FTIR), and nuclear 

magnetic resonance (NMR). Acceptable methods include EPA 

Method 18 in Appendix A-1 of 40 CFR part 60; EPA Method 320 

in Appendix A of 40 CFR part 63; the Protocol for Measuring 
Page 420 of 442 

Destruction or Removal Efficiency (DRE) of Fluorinated 

Greenhouse Gas Abatement Equipment in Electronics 

Manufacturing, Version 1, EPA-430-R-10-003, (March 2010) 

(incorporated by reference, see §98.7); ASTM D6348-03 

Standard Test Method for Determination of Gaseous Compounds 

by Extractive Direct Interface Fourier Transform Infrared 

(FTIR) Spectroscopy (incorporated by reference, see §98.7); 

or other analytical methods validated using EPA Method 301 

in Appendix A of 40 CFR part 63 or some other 

scientifically sound validation protocol. The validation 

protocol may include analytical technology manufacturer 

specifications or recommendations. 

(2) Documentation in GHG Monitoring Plan. Describe 

the analytical method(s) used under paragraph (n)(1) of 

this section in the site GHG Monitoring Plan as required 

under §98.3(g)(5). At a minimum, include in the 

description of the method a description of the analytical 

measurement equipment and procedures, quantitative 

estimates of the method’s accuracy and precision for the 

analytes of interest at the concentrations of interest, as 

well as a description of how these accuracies and 

precisions were estimated, including the validation 

protocol used. 
Page 421 of 442 

(3) Frequency of measurement. Perform the 

measurements at least once by [INSERT THE DATE 60 DAYS 

AFTER THE DATE OF PUBLICATION OF THIS FINAL RULE IN THE 

FEDERAL REGISTER] if the fluorinated GHG product is being 

produced on [INSERT THE DATE OF PUBLICATION OF THIS FINAL 

RULE IN THE FEDERAL REGISTER]. Perform the measurements 

within 60 days of commencing production of any fluorinated 

GHG product that was not being produced on [INSERT THE DATE 

OF PUBLICATION OF THIS FINAL RULE IN THE FEDERAL REGISTER]. 

Repeat the measurements if an operational or process change 

occurs that could change the identities or significantly 

change the concentrations of the fluorinated GHG 

constituents of the fluorinated GHG product. Complete the 

repeat measurements within 60 days of the operational or 

process change. 

(4) Measure all product grades. Where a fluorinated 

GHG is produced at more than one purity level (e.g., 

pharmaceutical grade and refrigerant grade), perform the 

measurements for each purity level. 

(5) Number of samples. Analyze a minimum of three 

samples of the fluorinated GHG product that have been drawn 

under conditions that are representative of the process 

producing the fluorinated GHG product. If the relative 

standard deviation of the measured concentrations of any of 
Page 422 of 442 

the fluorinated GHG constituents (other than lowconcentration constituents) is greater than or equal to 15 

percent, draw and analyze enough additional samples to 

achieve a total of at least six samples of the fluorinated 

GHG product. 

(o) All analytical equipment used to determine the 

concentration of fluorinated GHGs, including but not 

limited to gas chromatographs and associated detectors, IR, 

FTIR and NMR devices, shall be calibrated at a frequency 

needed to support the type of analysis specified in the 

site GHG Monitoring Plan as required under §98.414(n) and 

§98.3(g)(5) of this part. Quality assurance samples at the 

concentrations of concern shall be used for the 

calibration. Such quality assurance samples shall consist 

of or be prepared from certified standards of the analytes 

of concern where available; if not available, calibration 

shall be performed by a method specified in the GHG 

Monitoring Plan. 

(p) Isolated intermediates that are produced and 

transformed at the same facility are exempt from the 

monitoring requirements of this section. 

(q) Low-concentration constituents are exempt from 

the monitoring and QA/QC requirements of this section. 

50. Section 98.416 is amended by: 
Page 423 of 442 

a. Revising paragraph (a)(3). 

b. Removing and reserving paragraph (a)(4). 

c. Revising paragraphs (a)(11) and (a)(15). 

d. Revising paragraphs (b) introductory text and 

(b)(1). 

e. Revising paragraphs (c) introductory text, (c)(1), 

and (c)(10). 

f. Revising paragraph (d) introductory text. 

g. Revising paragraph (e) introductory text. 

h. Adding paragraphs (f) through (h). 

§98.416 Data reporting requirements.

* * * * * 

(a) * * * 

(3) Mass in metric tons of each fluorinated GHG that 

is destroyed at that facility and that was previously 

produced as defined at §98.410(b). Quantities to be 

reported under this paragraph (a)(3) of this section 

include but are not limited to quantities that are shipped 

to the facility by another facility for destruction and 

quantities that are returned to the facility for 

reclamation but are found to be irretrievably contaminated 

and are therefore destroyed. 

* * * * * 
Page 424 of 442 

(11) Mass in metric tons of each fluorinated GHG that 

is fed into the destruction device and that was previously 

produced as defined at §98.410(b). Quantities to be 

reported under this paragraph (a)(11) of this section 

include but are not limited to quantities that are shipped 

to the facility by another facility for destruction and 

quantities that are returned to the facility for 

reclamation but are found to be irretrievably contaminated 

and are therefore destroyed. 

* * * * * 

(15) Names and addresses of facilities to which any 

fluorinated GHGs were sent for destruction, and the 

quantities (metric tons) of each fluorinated GHG that were 

sent to each for destruction. 

* * * * * 

(b) By March 31, 2011 or within 60 days of commencing 

fluorinated GHG destruction, whichever is later, a 

fluorinated GHG production facility or importer that 

destroys fluorinated GHGs shall submit a one-time report 

containing the following information for each destruction 

process: 

(1) Destruction efficiency (DE). 

* * * * * 
Page 425 of 442 

(c) Each bulk importer of fluorinated GHGs or nitrous 

oxide shall submit an annual report that summarizes its 

imports at the corporate level, except for shipments 

including less than twenty-five kilograms of fluorinated 

GHGs or nitrous oxide, transshipments, and heels that meet 

the conditions set forth at §98.417(e). The report shall 

contain the following information for each import: 

(1) Total mass in metric tons of nitrous oxide and 

each fluorinated GHG imported in bulk, including each 

fluorinated GHG constituent of the fluorinated GHG product 

that makes up between 0.5 percent and 100 percent of the 

product by mass. 

* * * * * 

(10) If applicable, the names and addresses of the 

persons and facilities to which the fluorinated GHGs were 

sold or transferred for destruction, and the quantities 

(metric tons) of each fluorinated GHG that were sold or 

transferred to each facility for destruction. 

(d) Each bulk exporter of fluorinated GHGs or nitrous 

oxide shall submit an annual report that summarizes its 

exports at the corporate level, except for shipments 

including less than twenty-five kilograms of fluorinated 

GHGs or nitrous oxide, transshipments, and heels. The 
Page 426 of 442 

report shall contain the following information for each 

export: 

* * * * * 

(e) By March 31, 2011, or within 60 days of 

commencing fluorinated GHG production, whichever is later, 

a fluorinated GHG production facility shall submit a onetime report describing the following information: 

* * * * * 

(f) By March 31, 2011, all fluorinated GHG production 

facilities shall submit a one-time report that includes the 

concentration of each fluorinated GHG constituent in each 

fluorinated GHG product as measured under §98.414(n). If 

the facility commences production of a fluorinated GHG 

product that was not included in the initial report or 

performs a repeat measurement under §98.414(n) that shows 

that the identities or concentrations of the fluorinated 

GHG constituents of a fluorinated GHG product have changed, 

then the new or changed concentrations, as well as the date 

of the change, must be reflected in a revision to the 

report. The revised report must be submitted to EPA by the 

March 31st that immediately follows the measurement under 

§98.414(n). 
Page 427 of 442 

(g) Isolated intermediates that are produced and 

transformed at the same facility are exempt from the 

reporting requirements of this section. 

(h) Low-concentration constituents are exempt from 

the reporting requirements of this section. 

51. Section 98.417 is amended by revising paragraphs 

(a)(2), (b), and (d)(2); and by adding paragraphs (f) and 

(g) to read as follows: 

§98.417 Records that must be retained.

(a) * * * 

(2) Records documenting the initial and periodic 

calibration of the analytical equipment (including but not 

limited to GC, IR, FTIR, or NMR), weigh scales, flowmeters, 

and volumetric and density measures used to measure the 

quantities reported under this subpart, including the 

manufacturer directions or industry standards used for 

calibration pursuant to §98.414(m) and (o). 

(b) In addition to the data required by paragraph (a) 

of this section, any fluorinated GHG production facility 

that destroys fluorinated GHGs shall keep records of test 

reports and other information documenting the facility’s 

one-time destruction efficiency report in §98.416(b). 

* * * * * 

(d) * * * 
Page 428 of 442 

(2) The invoice for the export. 

* * * * * 

(f) Isolated intermediates that are produced and 

transformed at the same facility are exempt from the 

recordkeeping requirements of this section. 

(g) Low-concentration constituents are exempt from 

the recordkeeping requirements of this section. 

52. Section 98.418 is revised to read as follows: 

§98.418 Definitions.

Except as provided below, all of the terms used in 

this subpart have the same meaning given in the Clean Air 

Act and subpart A of this part. If a conflict exists 

between a definition provided in this subpart and a 

definition provided in subpart A, the definition in this 

subpart shall take precedence for the reporting 

requirements in this subpart. 

Isolated intermediate means a product of a process 

that is stored before subsequent processing. An isolated 

intermediate is usually a product of chemical synthesis. 

Storage of an isolated intermediate marks the end of a 

process. Storage occurs at any time the intermediate is 

placed in equipment used solely for storage. 

Low-concentration constituent means, for purposes of 

fluorinated GHG production and export, a fluorinated GHG 
Page 429 of 442 

constituent of a fluorinated GHG product that occurs in the 

product in concentrations below 0.1 percent by mass. For 

purposes of fluorinated GHG import, low-concentration 

constituent means a fluorinated GHG constituent of a 

fluorinated GHG product that occurs in the product in 

concentrations below 0.5 percent by mass. Lowconcentration constituents do not include fluorinated GHGs 

that are deliberately combined with the product (e.g., to 

affect the performance characteristics of the product). 

Subpart PP—[Amended] 

53. Section 98.422 is amended by revising paragraphs 

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

§98.422 GHGs to report.

(a) Mass of CO2 captured from production process 

units. 

(b) Mass of CO2 extracted from CO2 production wells. 

* * * * * 

54. Section 98.423 is amended by: 

a. Revising the first sentence of paragraph (a) 

introductory text. 

b. Revising the first sentences of paragraphs (a)(1) 

and (a)(2). 

c. Revising the definitions of “CCO2,p” and “Dp” in 

Equation PP-2 in paragraph (a)(2). 
Page 430 of 442 

d. Revising paragraph (a)(3). 

e. Redesignating paragraph (b) as paragraph (c) and 

revising newly designated paragraph (c). 

f. Adding paragraph (b). 

§98.423 Calculating CO2 Supply.

(a) Except as allowed in paragraph (b) of this 

section, calculate the annual mass of CO2 captured, 

extracted, imported, or exported through each flow meter in 

accordance with the procedures specified in either 

paragraph (a)(1) or (a)(2) of this section. * * * 

(1) For each mass flow meter, you shall calculate 

quarterly the mass of CO2 in a CO2 stream in metric tons by 

multiplying the mass flow by the composition data, 

according to Equation PP-1 of this section. * * * 

* * * * * 

(2) For each volumetric flow meter, you shall 

calculate quarterly the mass of CO2 in a CO2 stream in 

metric tons by multiplying the volumetric flow by the 

concentration and density data, according to Equation PP-2 

of this section. * * * 

* * * * * 

CCO2,p = Quarterly CO2 concentration measurement in flow 

for flow meter u in quarter p (measured as 

either volume % CO2 or weight % CO2). 
Page 431 of 442 

* * * * * 

Dp = Density of CO2 in quarter p (metric tons CO2 per 

standard cubic meter) for flow meter u if CCO2,p

is measured as volume % CO2, or density of the 

whole CO2 stream for flow meter u (metric tons 

per standard cubic meter) if CCO2,p is measured as 

weight % CO2. 

* * * * * 

(3) To aggregate data, use either Equation PP-3a or 

PP-3b in this paragraph, as appropriate. 

(i) For facilities with production process units that 

capture a CO2 stream and either measure it after segregation 

or do not segregate the flow, calculate the total CO2

supplied in accordance with Equation PP-3a. 

CO2 = ∑=

U

p 1

CO2, u (Eq. PP-3a) 

Where: 

CO2 = Total annual mass of CO2 (metric tons). 

CO2,u = Annual mass of CO2 (metric tons) through flow 

meter u. 

u = Flow meter. 

(ii) For facilities with production process units 

that capture a CO2 stream and measure it ahead of 

segregation, calculate the total CO2 supplied in accordance 

with Equation PP-3b. 

CO2 = ∑=

U

p 1

CO2, u - ∑=

V

p 1

CO2, v (Eq. PP-3b) 
Page 432 of 442 

Where: 

CO2 = Total annual mass of CO2 (metric tons). 

CO2,u = Annual mass of CO2 (metric tons) through main 

flow meter u. 

CO2,v = Annual mass of CO2 (metric tons) through 

subsequent flow meter v for use on site. 

u = Main flow meter. 

v = Subsequent flow meter. 

(b) As an alternative to paragraphs (a)(1) through 

(3) of this section for CO2 that is supplied in containers, 

calculate the annual mass of CO2 supplied in containers 

delivered by each CO2 stream in accordance with the 

procedures specified in either paragraph (b)(1) or (b)(2) 

of this section. If multiple CO2 streams are used to 

deliver CO2 to containers, you shall calculate the annual 

mass of CO2 supplied in containers delivered by all CO2

streams according to the procedures specified in paragraph 

(b)(3) of this section. 

(1) For each CO2 stream that delivers CO2 to 

containers, for which mass is measured, you shall calculate 

CO2 supply in containers using Equation PP-1 of this 

section. 

Where: 

CO2,u = Annual mass of CO2 (metric tons) supplied in 

containers delivered by CO2 stream u. 
Page 433 of 442 

CCO2,p,u = Quarterly CO2 concentration measurement of CO2

stream u that delivers CO2 to containers in 

quarter p (wt. %CO2). 

Qp,u = Quarterly mass of contents supplied in all 

containers delivered by CO2 stream u in quarter 

p (metric tons). 

p = Quarter of the year. 

u = CO2 stream that delivers to containers. 

(2) For each CO2 stream that delivers to containers, 

for which volume is measured, you shall calculate CO2 supply 

in containers using Equation PP-2 of this section. 

Where: 

CO2,u = Annual mass of CO2 (metric tons) supplied in 

containers delivered by CO2 stream u. 

CCO2,p = Quarterly CO2 concentration measurement of CO2

stream u that delivers CO2 to containers in 

quarter p (measured as either volume % CO2 or 

weight % CO2). 

Qp = Quarterly volume of contents supplied in all 

containers delivered by CO2 stream u in quarter 

p (standard cubic meters). 

Dp = Quarterly CO2 density determination for CO2

stream u in quarter p (metric tons per 

standard cubic meter) if CO2,p is measured as 

volume % CO2, or density of CO2 stream u 

(metric tons per standard cubic meter) if CO2,p 

is measured as weight % CO2. 

p = Quarter of the year. 

u = CO2 stream that delivers to containers. 

(3) To aggregate data, sum the mass of CO2 supplied in 

containers delivered by all CO2 streams in accordance with 

Equation PP-3a of this section. 

Where: 
Page 434 of 442 

CO2 = Annual mass of CO2 (metric tons) supplied in 

containers delivered by all CO2 streams. 

CO2,u = Annual mass of CO2 (metric tons) supplied in 

containers delivered by CO2 stream u. 

u = CO2 stream that delivers to containers. 

(c) Importers or exporters that import or export CO2

in containers shall calculate the total mass of CO2 imported 

or exported in metric tons based on summing the mass in 

each CO2 container using weigh bills, scales, or load cells 

according to Equation PP-4 of this section. 

CO2 = Q

I

p

∑=1

(Eq. PP-4) 

Where: 

CO2 = Annual mass of CO2 (metric tons). 

Q = Annual mass in all CO2 containers imported or 

exported during the reporting year (metric 

tons). 

55. Section 98.424 is amended by: 

a. Revising paragraphs (a)(1), (a)(2), and (a)(5). 

b. Revising the second sentence of paragraph (b)(2). 

c. Adding paragraph (c). 

§98.424 Monitoring and QA/QC requirements.

(a) * * * 

(1) Reporters following the procedures in §98.423(a) 

shall determine quantity using a flow meter or meters 

located in accordance with this paragraph. 
Page 435 of 442 

(i) If the CO2 stream is segregated such that only a 

portion is captured for commercial application or for 

injection, you must locate the flow meter according to the 

following: 

(A) For reporters following the procedures in 

§98.423(a)(3)(i), you must locate the flow meter(s) after 

the point of segregation. 

(B) For reporters following the procedures in 

paragraph (a)(3)(ii) of §98.423, you must locate the main 

flow meter(s) on the captured CO2 stream(s) prior to the 

point of segregation and the subsequent flow meter(s) on 

the CO2 stream(s) for on-site use after the point of 

segregation. You may only follow the procedures in 

paragraph (a)(3)(ii) of §98.423 if the CO2 stream(s) for onsite use is/are the only diversion(s) from the main, 

captured CO2 stream(s) after the main flow meter 

location(s). 

(ii) Reporters that have a mass flow meter or 

volumetric flow meter installed to measure the flow of a CO2 

stream that meets the requirements of paragraph (a)(1)(i) 

of this section shall base calculations in §98.423 of this 

subpart on the installed mass flow or volumetric flow 

meters. 
Page 436 of 442 

(iii) Reporters that do not have a mass flow meter or 

volumetric flow meter installed to measure the flow of the 

CO2 stream that meets the requirements of paragraph 

(a)(1)(i) of this section shall base calculations in 

§98.423 of this subpart on the flow of gas transferred off 

site using a mass flow meter or a volumetric flow meter 

located at the point of off-site transfer. 

(2) Reporters following the procedures in paragraph 

(b) of §98.423 shall determine quantity in accordance with 

this paragraph. 

(i) Reporters that supply CO2 in containers using 

weigh bills, scales, or load cells shall measure the mass 

of contents of each CO2 container to which the CO2 stream is 

delivered, sum the mass of contents supplied in all 

containers to which the CO2 stream is delivered during each 

quarter, sample the CO2 stream delivering CO2 to containers 

on a quarterly basis to determine the composition of the CO2

stream, and apply Equation PP-1. 

(ii) Reporters that supply CO2 in containers using 

loaded container volumes shall measure the volume of 

contents of each CO2 container to which the CO2 stream is 

delivered, sum the volume of contents supplied in all 

containers to which the CO2 stream is delivered during each 

quarter, sample the CO2 stream on a quarterly basis to 
Page 437 of 442 

determine the composition of the CO2 stream, determine the 

density quarterly, and apply Equation PP-2. 

* * * * * 

(5) Reporters using Equation PP-2 of this subpart and 

measuring CO2 concentration as weight % CO2 shall determine 

the density of the CO2 stream on a quarterly basis in order 

to calculate the mass of the CO2 stream according to one of 

the following procedures: 

(i) You may use a method published by a consensusbased standards organization. Consensus-based standards 

organizations include, but are not limited to, the 

following: ASTM International (100 Barr Harbor Drive, P.O. 

Box CB700, West Conshohocken, Pennsylvania 19428-B2959, 

(800) 262-1373, http://www.astm.org), the American National 

Standards Institute (ANSI, 1819 L Street, N.W., 6th floor, 

Washington, DC 20036, (202) 293-8020, http://www.ansi.org), 

the American Gas Association (AGA, 400 North Capitol 

Street, N.W., 4th Floor, Washington, DC 20001, (202) 824-

7000, http://www.aga.org), the American Society of 

Mechanical Engineers (ASME, Three Park Avenue, New York, NY 

10016-5990, (800) 843-2763, http://www.asme.org), the 

American Petroleum Institute (API, 1220 L Street, N.W., 

Washington, DC 20005-4070,(202) 682-8000, 

http://www.api.org), and the North American Energy 
Page 438 of 442 

Standards Board (NAESB, 801 Travis Street, Suite 1675, 

Houston, TX 77002, (713) 356-0060, http://www.api.org). 

The method(s) used shall be documented in the Monitoring 

Plan required under §98.3(g)(5). 

(ii) You may follow an industry standard method. 

(b) * * * 

(2) * * * Acceptable methods include, but are 

not limited to, the U.S. Food and Drug Administration 

food-grade specifications for CO2 (see 21 CFR 184.1240) and 

ASTM standard E1747-95 (Reapproved 2005) Standard Guide for 

Purity of Carbon Dioxide Used in Supercritical Fluid 

Applications (ASTM International, 100 Barr Harbor Drive, 

P.O. Box CB700, West Conshohocken, Pennsylvania 19428-

B2959, (800) 262-1373, http://www.astm.org). 

(c) You shall convert the density of the CO2 stream(s) 

and all measured volumes of carbon dioxide to the following 

standard industry temperature and pressure conditions: 

standard cubic meters at a temperature of 60 degrees 

Fahrenheit and at an absolute pressure of 1 atmosphere. If 

you apply the density value for CO2 at standard conditions, 

you must use 0.001868 metric tons per standard cubic meter. 

56. Section 98.425 is amended by revising paragraph 

(a) introductory text; and by adding paragraph (d) to read 

as follows: 
Page 439 of 442 

§98.425 Procedures for estimating missing data.

(a) Whenever the quality assurance procedures in 

§98.424(a)(1) of this subpart cannot be followed to measure 

quarterly mass flow or volumetric flow of CO2, the most 

appropriate of the following missing data procedures shall 

be followed: 

* * * * * 

(d) Whenever the quality assurance procedures in 

§98.424(a)(2) of this subpart cannot be followed to measure 

quarterly quantity of CO2 in containers, the most 

appropriate of the following missing data procedures shall 

be followed: 

(1) A quarterly quantity of CO2 in containers that is 

missing may be substituted with a quarterly value measured 

during another representative quarter of the current 

reporting year. 

(2) A quarterly quantity of CO2 in containers that is 

missing may be substituted with a quarterly value measured 

during the same quarter from the past reporting year. 

(3) The quarterly quantity of CO2 in containers 

recorded for purposes of product tracking and billing 

according to the reporter’s established procedures may be 

substituted for any period during which measurement 

equipment is inoperable. 
Page 440 of 442 

57. Section 98.426 is amended by: 

a. Revising paragraphs (a) introductory text and 

(a)(2). 

b. Adding paragraph (a)(5). 

c. Revising paragraphs (b) introductory text, (b)(2), 

(b)(3), and (b)(4). 

d. Adding paragraph (b)(7). 

e. Revising paragraphs (c) and (e)(1). 

§98.426 Data reporting requirements.

* * * * * 

(a) If you use Equation PP-1 of this subpart, report 

the following information for each mass flow meter or CO2

stream that delivers CO2 to containers: 

* * * * * 

(2) Quarterly mass in metric tons of CO2.

* * * * * 

(5) The location of the flow meter in your process 

chain in relation to the points of CO2 stream capture, 

dehydration, compression, and other processing. 

* * * * * 

(b) If you use Equation PP-2 of this subpart, report 

the following information for each volumetric flow meter or 

CO2 stream that delivers CO2 to containers: 

* * * * * 
Page 441 of 442 

(2) Quarterly volume in standard cubic meters of CO2. 

(3) Quarterly concentration of the CO2 stream in 

volume or weight percent. 

(4) Report density as follows: 

(i) Quarterly density of CO2 in metric tons per 

standard cubic meter if you report the concentration of the 

CO2 stream in paragraph (b)(3) of this section in weight 

percent. 

(ii) Quarterly density of the CO2 stream in metric 

tons per standard cubic meter if you report the 

concentration of the CO2 stream in paragraph (b)(3) of this 

section in volume percent. 

* * * * * 

(7) The location of the flow meter in your process 

chain in relation to the points of CO2 stream capture, 

dehydration, compression, and other processing. 

(c) For the aggregated annual mass of CO2 emissions 

calculated using Equation PP-3a or PP-3b, report the 

following: 

(1) If you use Equation PP-3a of this subpart, report 

the annual CO2 mass in metric tons from all flow meters and 

CO2 streams that deliver CO2 to containers. 

(2) If you use Equation PP-3b of this subpart, 

report: 
Page 442 of 442 

(i) The total annual CO2 mass through main flow 

meter(s) in metric tons. 

(ii) The total annual CO2 mass through subsequent flow 

meter(s) in metric tons. 

(iii) The total annual CO2 mass supplied in metric 

tons. 

(iv) The location of each flow meter in relation to 

the point of segregation. 

* * * * * 

(e) * * * 

(1) The type of equipment used to measure the total 

flow of the CO2 stream or the total mass or volume in CO2

containers. 

* * * * *