6560.50

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 98

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

RIN 2060-AQ33

Mandatory Reporting of Greenhouse Gases

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed Rule

SUMMARY: EPA is proposing to amend specific provisions 

in the GHG 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 proposed changes include providing 

additional information and clarity on existing 

requirements, allowing greater flexibility or simplified 

calculation methods for certain sources in a facility, 

amending data reporting requirements to provide additional 

clarity on when different types of GHG emissions need to be 

calculated and reported, clarifying terms and definitions 

in certain equations, and technical corrections. 

DATES: Comments. Comments must be received on or 

before [INSERT THE DATE 45 DAYS AFTER DATE OF PUBLICATION 

IN THE FEDERAL REGISTER]. 
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Public Hearing. EPA does not plan to conduct a public 

hearing unless requested. To request a hearing, please 

contact the person listed in the FOR FURTHER INFORMATION 

CONTACT section by [INSERT DATE 7 DAYS AFTER DATE OF 

PUBLICATION IN THE FEDERAL REGISTER]. If requested, the 

hearing will be conducted [INSERT DATE 15 DAYS AFTER DATE 

OF PUBLICATION IN THE FEDERAL REGISTER], at 1310 L St., NW, 

Washington, DC 20005 starting at 9 a.m., local time. EPA 

will provide further information about the hearing on its 

Web page if a hearing is requested.

ADDRESSES: You may submit your comments, identified 

by docket ID No. EPA–HQ–OAR–2008-0508 by any of the 

following methods:

• Federal eRulemaking Portal: 

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

instructions for submitting comments.

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

EPA–HQ–OAR–2008-0508 [and/or RIN number 2060-aq33] in 

the subject line of the message.

• Fax: (202) 566–1741.

• Mail: Environmental Protection Agency, EPA Docket 

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

No. EPA-HQ-OAR–2008-0508, 1200 Pennsylvania Avenue, 

NW., Washington, DC 20004.

• Hand/Courier Delivery: EPA Docket Center, Public 

Reading Room, EPA West Building, Room 3334, 1301 

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

deliveries are only accepted during the Docket’s 

normal hours of operation, and special arrangements 

should be made for deliveries of boxed information.
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Instructions: Direct your comments to Docket ID No. 

EPA–HQ–OAR–2008-0508, Revision of Certain GHGMRR Provisions 

and Other Corrections. EPA’s policy is that all comments 

received will be included in the public docket without 

change and may be made available online at 

http://www.regulations.gov, including any personal 

information provided, unless the comment includes 

information claimed to be confidential business information 

(CBI) or other information whose disclosure is restricted 

by statute. Do not submit information that you consider to 

be CBI or otherwise protected through 

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

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

system, which means EPA will not know your identity or 

contact information unless you provide it in the body of 

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

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

e-mail address will be automatically captured and included 

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

and made available on the Internet. If you submit an 

electronic comment, EPA recommends that you include your 

name and other contact information in the body of your 

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

cannot read your comment due to technical difficulties and 
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cannot contact you for clarification, EPA may not be able 

to consider your comment. Electronic files should avoid 

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

be free of any defects or viruses. 

Docket: All documents in the docket are listed in the 

http://www.regulations.gov index. Although listed in the 

index, some information is not publicly available, e.g., 

CBI or other information whose disclosure is restricted by 

statute. Certain other material, such as copyrighted 

material, will be publicly available only in hard copy. 

Publicly available docket materials are available either 

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

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

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

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

through Friday, excluding legal holidays. The telephone 

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

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

FOR FURTHER GENERAL INFORMATION CONTACT: Carole Cook, 

Climate Change Division, Office of Atmospheric Programs 

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

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

number: (202) 343-9263; fax number: (202) 343-2342; e-mail 

address: GHGReportingRule@epa.gov. For technical 
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information contact the Greenhouse Gas Reporting Rule 

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

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

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

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

emissions/ghgrulemaking.html. Alternatively, contact 

Carole Cook at 202–343–9263. 

Worldwide Web (WWW). In addition to being available 

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

also be available through the WWW. Following the 

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

posted on EPA's greenhouse gas reporting rule website at 

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

emissions/ghgrulemaking.html.

SUPPLEMENTARY INFORMATION:

Additional Information on Submitting Comments: To 

expedite review of your comments by Agency staff, you are 

encouraged to send a separate copy of your comments, in 

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

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

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

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

GHGReportingRule@epa.gov.
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Regulated Entities. The Administrator determined that 

this action is subject to the provisions of Clean Air Act 

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

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

as the Administrator may determine”). These are proposed 

amendments to existing regulations. If finalized, these 

amended regulations would affect owners or operators of 

certain fossil fuel and industrial gas suppliers, and 

direct emitters of 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.

325 Chemical manufacturers.

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.

General 

Stationary Fuel 

Combustion 

Sources

611 Educational services.
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Category NAICS Examples of affected facilities

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.

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

Petrochemical 

Production

32511 Ethylene dichloride production 

facilities.
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Category NAICS Examples of affected facilities

325199 Acrylonitrile, ethylene oxide, 

methanol production facilities.

325110 Ethylene production facilities.

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 

Management1

112320 Broilers and other meat type 

chicken production.

221210 Natural gas distribution 

facilities.

Suppliers of 

Natural Gas and 

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.

1 EPA will not be implementing subpart JJ of Part 98 using funds 

provided in its FY2010 appropriations 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 
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regarding facilities likely to be affected by this action. 

Table 1 of this preamble lists the types of facilities that 

EPA is now aware could potentially be affected by the 

reporting requirements. Other types of facilities than 

those listed in the table could also be subject to 

reporting requirements. To determine whether you are 

affected by this action, you should carefully examine the 

applicability criteria found in 40 CFR part 98, subpart A 

or the relevant criteria in the sections related to fossil 

fuel and industrial gas suppliers, and direct emitters of 

GHGs. If you have questions regarding the applicability of 

this action to a particular facility, consult the person 

listed in the preceding “FOR FURTHER GENERAL INFORMATION 

CONTACT Section.

Acronyms and Abbreviations. The following acronyms 

and abbreviations are used in this document.

ACC American Chemistry Council

AGA American Gas Association

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

Btu/scf British thermal unit per standard cubic foot

CAA Clean Air Act

CAIR Clean Air Interstate Rule

CBI confidential business information
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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

EGU electricity generating unit

EIA Energy Information Administration

EO Executive Order

EPA U.S. Environmental Protection Agency

ERC Energy Recovery Council

FGD flue gas desulfurization

FR Federal Register

FTIR fourier transform infrared

GC gas chromatography

GHG greenhouse gas

GPA Gas Processors Association

GWP global warming potential

HCl hydrogen chloride

HHV high heat value

HSS horizontal stud Søderberg

IPCC Intergovernmental Panel on Climate Change

IR infrared

LDCs local natural gas distribution companies

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 

MWC municipal waste combustor
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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

O&M operation and maintenance

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

RFG Refinery fuel gas

RGGI Regional Greenhouse Gas Initiative

scf standard cubic feet

scfm standard cubic feet per minute

SO2 sulfur dioxide

SWPB side worked prebake

U.S. United States

UMRA Unfunded Mandates Reform Act of 1995

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 Would These Amendments Apply to 2011 Reports?

II. Revisions and Other Amendments
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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
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I. Background

A. How is this Preamble Organized?

The first section of this preamble contains the basic 

background information about the origin of these proposed 

rule amendments and request for public comment. This 

section also discusses EPA’s use of our legal authority 

under the Clean Air Act to collect data on GHGs.

The second section of this preamble describes in 

detail the changes that are being proposed to correct 

technical errors or to address implementation issues 

identified by EPA and others. This section also presents 

EPA’s rationale for the proposed changes and identifies 

issues on which EPA is particularly interested in receiving 

public comments. 

Finally, the last (third) section discusses the 

various statutory and executive order requirements 

applicable to this proposed rulemaking.

B. Background on This Action

The final Part 98 was signed by EPA Administrator Lisa 

Jackson on September 22, 2009 and published in the Federal 

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

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

2009, included reporting of GHG information from facilities 
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and suppliers, consistent with the 2008 Consolidated 

Appropriations Act1. These source categories capture 

approximately 85 percent of U.S. GHG emissions through 

reporting by direct emitters as well as suppliers of fossil 

fuels and industrial gases. 

This is the second time that EPA has published a 

notice proposing amendments to Part 98 to, among other 

things, correct certain technical and editorial errors that 

have been identified since promulgation and clarify or 

propose amendments to certain provisions that have been the 

subject of questions from reporting entities. The first 

proposal was published on June 15, 2010 (75 FR 33950). 

This proposal complements the proposal published on June 

15, 2010 and is not intended to duplicate or replace the 

proposed amendments published on June 15, 2010. We are 

seeking public comment only on the issues specifically 

identified in this proposal for the identified subparts. 

We will not respond to any comments addressing other 

aspects of Part 98 or any other related rulemakings.

C. Legal Authority

EPA is proposing these rule amendments under its 

existing CAA authority, specifically authorities provided 

in section 114 of the CAA. 

 

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

1844, 2128. 
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As stated in the preamble to the final Part 98 (74 FR 

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

broad authority to require the information proposed to be 

gathered 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), section 

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

require emissions sources, persons subject to the CAA, 

manufacturers of control equipment, or persons whom the 

Administrator believes may have necessary information to 

monitor and report emissions and provide such other 

information the Administrator requests for the purposes of 

carrying out any provision of the CAA. For further 

information about EPA’s legal authority, see the preambles 

to the proposed and final rule, and Response to Comments 

Documents.2

D. How Would These Amendments Apply to 2011 Reports?

EPA is planning to address the comments on these 

proposed amendments and publish the final amendments before 

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

calculate emissions and other relevant data for the reports 

 

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
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that are submitted in 2011 using Part 98, as amended by 

this and the other revisions package (75 FR 33950), as 

finalized. We have determined that it is feasible for the 

sources to implement these changes for the 2010 reporting 

year since the revisions primarily provide additional 

clarifications or flexibility regarding the existing 

regulatory requirements, generally do not affect the type 

of information that must be collected, and do not 

substantially affect how emissions are calculated. 

For example, many proposed revisions simply provide 

additional information and clarity on existing 

requirements. For example, we are proposing to amend 40 

CFR 98.3(c)(5)(i) to clarify that suppliers of industrial 

flourinated GHGs need to calculate and report GHG emissions 

in metric tons of CO2 equivalents (mtCO2e) only for those 

flourinated GHGs that are listed in Table A-1. This 

proposed clarification is consistent with clarifications we 

have issued in response to industry questions and would not 

change how facilities collected data during 2010. 

Some of the proposed amendments provide greater 

flexibility or simplified calculation methods for certain 

facilities. For example, we are proposing to amend subpart 

C by adding a new equation that would enable sources that 

receive natural gas billing data from their suppliers in 
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therms 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. 

Some proposed amendments are to the data reporting 

requirements to provide additional clarity on when 

different types of GHG emissions need to be calculated and 

reported. For example, in subpart G, Ammonia 

Manufacturing, we are proposing to eliminate the 

calculation and reporting of CO2 emissions associated with 

the use of the waste recycle stream or “purge” as fuel 

under subpart C because these emissions are already 

accounted for in the calculation of total process emissions 

in subpart G, which includes CO2 emissions resulting from 

the use of purge gas as a fuel. We have concluded that 

amendments such as these can be implemented for the reports 

submitted to EPA in 2011 because the proposed changes are 

consistent with the calculation methodologies already in 

part 98 and the owners or operators are not required to 

actually report until March 2011, several months after we 

expect this proposal to be finalized. 

For some subparts, we are proposing amendments to 

address issues identified as a result of working with the 

affected sources during rule implementation. These 

proposed revisions provide additional flexibility to the 
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sources, or reduce the reporting burden. For example, in 

subparts X (Petrochemical Production) and Y (Petroleum 

Refineries), reporters have requested that allowance be 

made for alternative standard conditions within the molar 

volume conversion factor (MVC) used in various equations. 

Therefore, we are proposing to amend those subparts to 

include MVCs at standard conditions defined at both 60oF or 

68oF, so the facilities will not have to make those 

corrections in their data. 

We are also proposing corrections to terms and 

definitions in certain equations. For example, in subpart 

Y, Petroleum Refineries, we are proposing to clarify in an 

equation that for coke calcining units that recycle the 

collected coke 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. These clarifications do 

not result in additional requirements; therefore, we have 

concluded that reporters can follow Part 98, as amended, in 

submitting their first reports in 2011.

Finally, we are proposing other technical corrections 

that have no impact on facility’s data collection efforts 

in 2010. For example, we are proposing to amend subpart C 

to remove a second copy of Table C-2 that was inadvertently 
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included in the final Part 98 published on October 30, 

2009. 

In summary, these amendments would not require any 

additional monitoring or information collection above what 

was already included in Part 98. Therefore, we expect that 

sources can use the same information that they have been 

collecting under the current version of Part 98 to 

calculate and report GHG emissions for 2010 and submit 

reports in 2011 under the amended Part 98.

We seek comment on the conclusion that it is 

appropriate to implement these amendments and incorporate 

the requirements in the data reported to EPA by March 31, 

2011. Further, we seek comment on whether there are 

specific subparts of Part 98 for which this timeline may 

not be feasible or appropriate due to the nature of the 

proposed changes or the way in which data have been 

collected thus far in 2010. We request that commenters 

provide specific examples of how the proposed 

implementation schedule would or would not work.

II. Revisions and Other Amendments

Following promulgation of Part 98, we have identified 

errors in the regulatory language that we are now proposing 

to correct. These errors were identified as a result of 

working with affected industries to implement the various 
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subparts of Part 98. We have also identified certain rule 

provisions that should be amended to provide greater 

clarity. We are also proposing revisions to provide 

additional flexibility for certain requirements based in 

part on our better understanding of various industries. 

Finally, we are also proposing to revise or remove certain 

applicability thresholds (for example for local 

distribution companies subject to subpart NN (Suppliers of 

Natural Gas and Natural Gas Liquids)) and monitoring 

thresholds and reporting requirements (for example for 

municipal solid waste combusters subject to subpart C 

(General Stationary Fuel Combustion) and for certain small 

sources subject to subpart X (Petrochemicals) or subpart Y 

(Petroleum Refineries)). The amendments we are now 

proposing include the following types of changes:

• Changes to correct cross references within and between 

subparts. 

• Additional information to better or more fully 

understand compliance obligations in a specific 

provision, such as the reference to a standardized 

method that must be followed.

• Amendments to certain equations to better reflect 

actual operating conditions.

• Corrections to terms and definitions in certain 

equations.

• Corrections to data reporting requirements so that 

they more closely conform to the information used to 

perform emission calculations.
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• Other amendments related to certain issues identified 

as a result of working with the affected sources 

during rule implementation and outreach.

As mentioned above in section I of this preamble, we 

published an earlier proposed rulemaking proposing 

technical corrections and other amendments to Part 98 on 

June 15, 2010 (75 FR 33950). This proposal complements the 

notice published on June 15, 2010 and is not intended to 

duplicate or replace the proposed amendments published on 

June 15, 2010. We are seeking public comment only on the 

issues specifically identified in this notice for the 

identified subparts. We will not respond to any comments 

addressing other aspects of Part 98 or any other related 

rulemakings. 

A. Subpart A (General Provisions): Best Available 

Monitoring Methods 

Certain owners and operators in the more complex 

hydrogen, petrochemical, and petroleum refinery industries 

have expressed concerns regarding the timing of the 

requirements to install meters and other measurement 

devices to comply with Part 98. Specifically, they were 

concerned that the safe installation of required 

measurement devices requires detailed engineering and 

planning and, therefore, stated that EPA should provide 

sufficient time for designing and safely engineering 
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instrumentation installations or upgrades. Further, they 

claimed that in continuously operated plants there is 

typically not a scheduled shutdown for an entire facility 

and unit maintenance and turnarounds are not an annual 

occurrence for all units. Reporters in these industries

have asserted that EPA has properly recognized this 

operational reality in the context of instrument 

calibration by allowing calibration to be delayed until the 

next scheduled shutdown. The reporters have noted, 

however, that parallel requirements have not been developed 

for installation of monitoring devices. Specifically, they 

requested that EPA should provide approval criteria for 

extending the use of “best available monitoring methods” 

(BAMM) beyond December 31, 2010 for equipment installation.

These types of concerns were the reason owners and 

operators were given the opportunity in Part 98 to request 

an extension from EPA to use BAMM beyond March 31, 2010 in 

situations where it was not reasonably feasible to acquire, 

install and operate the required monitoring equipment by 

that date. We recognize, however, that instances may occur 

where facilities subject to Part 98 may not have been 

scheduled to shutdown during 2010, and requiring the 

facility to shutdown solely to install the required 
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measurement devices during 2010 could impose an unnecessary 

burden.

Therefore, we are proposing that a new petition 

process be established in a new paragraph 40 CFR 98.3(j) 

that would allow use of BAMM past December 31, 2010 for 

owners and operators required to report under subpart P

(Hydrogen Production), subpart X (Petrochemicals 

Production), or subpart Y (Petroleum Refineries), under 

limited circumstances. We are proposing that owners or 

operators subject to these subparts could petition EPA to 

extend use of BAMM past December 31, 2010, if compliance 

with a specific provision in the regulation required 

measurement device installation, and installing the 

device(s) would necessitate an unscheduled process 

equipment or unit shutdown or could only be installed 

through a hot tap. If the petition is approved, the owner 

or operator could 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. 
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The initial process for use of best available 

monitoring methods in Part 98 ended December 31, 2010, 

because we concluded that it is important to establish a 

date by which all equipment must be installed and operating 

in order to ensure that consistent data are collected by 

all reporters. We maintain that it is important to have 

consistent methods being used by all reporters. However, 

we also recognize that some complex facilities have unique 

operating circumstances that justify additional 

flexibility. Therefore, although we are proposing to 

initially approve extension requests no later than December 

31, 2013, owners or operators subject to these subparts 

would have a one time opportunity to re-apply for the 

extension request for an additional two years, with 

approval being granted no later than December 31, 2015. We 

believe that a date of December 31, 2013, four years after 

the effective date of Part 98, would accommodate the 

shutdown schedules for most, if not all facilities subject 

to subparts P, X, and/or Y. Because we recognize that all 

such facilities subject to Part 98 may not have a planned 

process equipment or unit shutdown prior to December 31, 

2013, we have has concluded that it is reasonable to 

propose that owners or operators could re-apply one time 

for an additional two years. This timeline balances the 
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need to gather consistent data, while recognizing the 

operational reality of such facilities. 

Process for Requesting an Extension of Best Available 

Monitoring Methods. We are proposing to add a similar 

petition process to that recently concluded for the use of 

BAMM for 2010 in the new paragraph 40 CFR 98.3(j). The 

process would be available solely for facilties 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 would be allowable 

initially until December 31, 2013. Subpart P, X, and/or Y 

owners or operators requesting to use BAMM beyond 2010 

would be 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 

would require a hot tap or unscheduled shutdown. 

Owners or operators would be required to submit the 

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

full extension requests would 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 would not 

be accomplished in 2010 with supporting material, an 
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estimated date for the next planned maintenance outage, and 

a discussion of how emissions would be calculated in the 

interim. More specifically, the full extension request 

would need to 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 would also be required to 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. 

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 would automatically be able to use 

BAMM through June 30, 2011. All measurement devices would 
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need to be installed by July 1, 2011 unless EPA approves 

the BAMM request before that date. 

Approval of Extension Requests. In an approval of an 

extension request, EPA would 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 would have until the date approved by EPA to 

install any remaining meters or other measurement devices, 

however initial approvals would not grant extensions beyond 

December 31, 2013. An owner/operator that already received 

approval from EPA to use BAMM during part or all of 2010 

would be 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 proposed process for BAMM would 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 proposing to 

include a process by which owners or operators who had 

received an extension would have the opportunity to extend 
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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 moved would be 

required to notify EPA within 4 weeks of such a 

determination, but no later than 4 weeks before the date of 

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 

owners or operators determine that a scheduled shutdown 

will not occur by December 31, 2013, they would be required 

to 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 13, 2013, owners or operators would 

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

2013 that contains the information required in proposed 40 

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

request under this paragraph to extend use of best 

available monitoring methods for measurement device 

installation would be required to install all measurement 

devices by December 31, 2013, unless the extension request 

under this paragraph is approved by EPA. 
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We seek comment on this approach to extend the 

deadline for installation of measurement devices in cases 

where such installation would require an unscheduled 

process equipment or unit shutdown at a subpart P, X,

and/or Y facility. The proposed approach is consistent 

with the language and intent in Part 98 to defer 

calibration of required monitors in order to avoid 

unnecessary and unplanned shutdowns. The proposed approach 

is also modeled after the provision to request EPA to use 

BAMM during 2010. We considered, but did not propose, 

limiting this provision to only those subpart P, X, and/or 

Y owners and operators who submitted a request for use of 

BAMM by January 28, 2010. This option was considered based 

on an assumption that the full universe of reporters that 

had difficulty installing the necessary measurement devices 

according to the schedule in the rule would have already 

submitted a request for the use of BAMM in 2010. We still 

believe that all owners or operators that required a 

process equipment or unit shutdown to install measurement 

devices should have submitted an extension request to EPA 

by January 28, 2010. Nevertheless, we also recognize that 

this is a new regulation and facilities subject to Part 98 

are making good faith efforts to understand all 

requirements. After careful consideration we are proposing 
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to initiate a new process for BAMM, providing all facilties 

with units subject to subpart P, subpart X or subpart Y the 

opportunity to apply. 

We are proposing to limit the provision to facilities 

with units subject to one or more of these three subparts 

because, based on questions received during implementation, 

the concerns raised about installation of measurement 

devices necessitating process equipment or unit shutdown 

have been from facilities subject to these subparts. A 

clear case was not presented by other industries as to any 

unique circumstances in those industries (e.g., safety 

concerns associated with installation of measurement 

devices, frequency of shutdowns, complexities associated 

with shutting down, etc.) that might necessitate extending 

the deadline for BAMM for these other industries. We are 

seeking comment on this conclusion and whether there are 

other facilities beyond these subparts P, X, and Y that 

would need a shutdown, or a hot tap, in order to install 

the required measurement devices. If providing comments, 

please 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 shutdown or why such shutdowns did not or could not 

occur in 2010 without unreasonable burden on the facility.
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We are generally seeking comment on this new petition 

process for BAMM. 

B. Subpart A (General Provisions): Calibration 

Requirements

Since the rule was published on October 30, 2009, EPA 

has received numerous questions about the intent and extent 

of the equipment calibration requirements specified in 40 

CFR 98.3(i). The current rule could be interpreted to 

require all types of measurement equipment that provide 

data for the GHG emissions calculations, including flow 

meters and “other devices” such as belt scales, to be 

calibrated to a specified accuracy (i.e., 5.0 percent in 

most cases). 

The perceived universal nature of the calibration 

requirements in 40 CFR 98.3(i) has caused a great deal of 

concern in the regulated community. For example, the 

appropriateness of a 5.0 percent accuracy specification for 

a wide variety of measurement devices has been questioned. 

Specifically, reporters have recommended that the initial 

and on-going calibration requirements be modified to allow 

the accuracy to be determined within an appropriate error 

range for each measurement technology, based on an 

applicable standard. 
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Also, for small combustion units using the Tier 1 or 

Tier 2 CO2 calculation methodologies in 40 CFR 98.33(a), 

reporters were concerned that the calibration requirements 

and accuracy specifications appear to apply to flow meters 

that are used to quantify liquid and gaseous fuel usage. 

This contradicts the clear statements in the nomenclature 

of Equations C-1 and C-2a of Subpart C that company records 

can be used to measure fuel consumption for Tier 1 and 2 

units. We note that the definition of “company records” in 

40 CFR 98.6 is quite flexible and it does not require that 

any particular calibration methods be used or that specific 

accuracy percentages be met. 

In view of these considerations, we are proposing to 

amend 40 CFR 98.3(i) as follows, to more clearly define the 

scope of the calibration requirements:

(a) We are proposing to amend 40 CFR 98.3(i)(1) to 

specify that the calibration accuracy requirements of 40 

CFR 98.3(i)(2) and (i)(3) would be 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 
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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) would continue to

apply to these meters. EPA has many years of experience 

with fuel flow meter calibration, for example in the Acid 

Rain and NOx Budget Programs, and the Agency is confident 

that the accuracy requirements specified in 40 CFR 98.3(i) 

are both reasonable and achievable for such meters. For 

more information please refer to the Background Technical 

Support Document at EPA-HQ-OAR-2008-0508. We are also 

proposing to add statements to 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 

required to explain in their monitoring plan the processes 

and methods used to collect the necessary data for the GHG 

calculations. 
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(b) We are proposing to further amend 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 would have to be calibrated to meet the 

accuracy requirements of the relevant subpart(s), or, in 

the absence of such requirements, to meet appropriate, 

technology-based error-limits, 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 would be documented in the written 

monitoring plan.

(c) We are proposing to add 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.

(d) We are proposing to add a new paragraph 40 CFR 

98.3(i)(1)(iii) to specify the frequency at which 

subsequent recalibrations of flow meters and other 

measurement devices need to be performed. Recalibration 
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would 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.

(e) We are proposing to specify the consequences of a 

failed flow meter calibration in a new paragraph 40 CFR 

98.3(i)(7). Data would become invalid prospectively, 

beginning at the hour of the failed calibration and 

continuing until a successful calibration is completed. 

Appropriate substitute data values would be used during the 

period of data invalidation.

(f) In 40 CFR 98.3(i)(2) and (3), we are proposing to 

add absolute value signs to the numerators of Equations A-2 

and A-3. These were inadvertently omitted in the October 

30, 2009 Part 98.

(g) We are proposing to amend 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 proposing to amend 40 

CFR 98.3(i)(3) for orifice, nozzle, and venturi flow meters 
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to account for 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 would, as described below,

conditionally be 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 would be 4.0 percent. If two 

assumed values are used and only the differential pressure 

transmitter is calibrated, the maximum allowable 

calibration error would be 2.0 percent. We note that the 

use of an arithmetic sum of the calibration errors is 

consistent with the approach in Part 75, and is designed to 

introduce flexibility, by allowing the results of a 

calibration to be accepted as valid when the calibration 

error of one (or in some cases, two) of the transmitters 

exceeds 2.0 percent. We did not intend to introduce an 

uncertainty analysis, such as the square root of the sum of 

the squares, for quantifying uncertainty.

We are also proposing to amend 40 CFR 98.3(i)(3) to 

add five conditions that must be met in order for a source 
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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 would have to 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 could 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, 

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 would have to 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.

(h) We are proposing to amend 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 
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for unit startup or ignition. 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 would be exempted. 

This proposed revision is modeled after a similar 

calibration exemption in section 2.1.4.1 of Appendix D to 

40 CFR Part 75, for fuel flow meters that measure startup 

and ignition fuels. The amount of fuel used for ignition 

and startup generally provides a very small percentage of 

the annual unit heat input (less than 1 percent in most 

cases). Therefore, rigorous calibration of meters used 

exclusively for startup and ignition fuels is unnecessary. 

Paragraph 98.3(i)(4) would be further amended to clarify 

that gas billing meters are exempted from the monitoring 

plan and record keeping provisions of 40 CFR 

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

that a description of the methods used to quality-assure 

data from instruments used to provide data for the GHG 

emissions calculations be included in the written 

monitoring plan, and that maintenance records be kept for 

those instruments. We are proposing these changes because 

operation, maintenance, and quality assurance of gas 

billing meters is the responsibility of the fuel supplier, 

not the consumer.
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(i) We are proposing to amend 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 would also be amended to clarify that the 

deadline for successive calibrations would be according to 

the a manufacturer’s recommended calibration schedule or an 

industry consensus calibration schedule.

(j) We are proposing to amend 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 currently allows the owner or operator 

to postpone the initial calibration until the next 

scheduled maintenance outage. The rule did not require 

shutdown for calibration of equipment because it was 

determined to be an unnecessary burden to require shutdown 

for calibration given that all measurement equipment 

required for GHG emissions would be required to be 

calibrated if they did not have an active calibration, 

necessitating a potentially large number of shutdowns. 
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Although the rule allows postponement of calibration,

it does not specify how to report fuel consumption for the 

entire time period extending from January 1, 2010 until the 

next maintenance outage. Section 98.3(d) of subpart A 

allows sources to use the “best available monitoring 

methods” (BAMM) until April 1, 2010, and to petition the 

Administrator to continue using the BAMM through December 

31, 2010, but not beyond that date. 

In view of this, we are proposing to amend 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 proposed revision would 

address situations where the next scheduled outage is in 

2011, or later. 

C. Subpart A (General Provisions): Reporting of Biogenic 

Emissions 

Reporters have noted that in the final Part 98 a new 

requirement was introduced that requires separate reporting 

of biogenic emissions from facilities (40 CFR 98.3(c)). 

They have noted that had EPA sought comment on this

requirement in the proposal, they may have commented that 

units subject to subpart D (Electricity Generation) should 

not be required to report biogenic emissions separately, as 

this is not currently required under Part 75, which 
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generally established the procedures for measuring data 

under subpart D. Or, they may have recommended specific 

methods for calculating biogenic emissions from Part 75 

units. Owners and operators have stated that it is not 

clear in Part 98 which method is required for estimating 

these emissions from units subject to subpart D. 

EPA has subsequently provided guidance that separate 

reporting of biogenic emissions for units subject to 

subpart D is optional; however, in order to provide clarity 

and remove any potential inconsistencies, we are proposing 

revisions to subpart A and soliciting comment. 

We intended that units subject to subpart D would 

continue to monitor and report CO2 mass emissions as 

required under 40 CFR 75.13 or section 2.3 of apppendix G 

to 40 CFR part 75, and 40 CFR 75.64. These provisions do 

not require separate accounting of biogenic emissions, and 

we did not intend to require additional accounting methods 

for these units under Part 98. We intended for the 

reporting of biogenic CO2 emissions to be optional for units 

subject to subpart D. However, the current rule does not 

consistently affirm this. Section 98.3(c)(4) of subpart A 

requires sources to report facility-wide GHG emissions, 

excluding biogenic CO2, and to report CO2 emissions for each 

source category excluding biogenic CO2. To meet these 
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reporting requirements, facilities with subpart D and/or 

other Part 75 units on-site would have to separately 

account for the biogenic CO2 emissions (if any) from those 

units. 

To address these concerns, we are proposing to amend 

the data elements in subparts A and C that currently 

require separate accounting and reporting of biogenic CO2

emissions so that it would be optional for Part 75 units. 

All units, except Part 75 units, would still be required to 

calculate and report biogenic CO2 emissions separately under 

subpart C. We are proposing to amend the following 

sections of subparts A and C to reflect these changes:

• 40 CFR 98.3(c)(4)(i) would be revised to no longer 

require facilities to report annual emissions, 

excluding biogenic CO2; instead, it would require all 

owners or operators to report annual facility-wide 

emissions, including biogenic CO2. 

• 40 CFR 98.3(c)(4)(ii) and (c)(4)(iii)(A) would be 

amended to state that separate reporting of biogenic 

CO2 emissions is not required for units using part 75 

methodologies to calculate CO2 mass emissions.

• 40 CFR 98.3(c)(4)(ii)(B) would be revised to no longer 

require reporting of the annual CO2 emissions from 

subparts C through JJ, excluding biogenic CO2; instead, 

it would require reporting of the total annual CO2

emissions for each subpart, including biogenic CO2. 

• 40 CFR 98.33(a)(5)(iii)(D) would be redesignated as 40 

CFR 98.33(a)(5)(iv) and amended to state that separate 

reporting of biogenic CO2 emissions is optional for 

part 75 units that qualify for and elect to use the 

alternative CO2 mass emissions reporting options in 40 

CFR 98.33(a)(5).

• A statement would be added to 40 CFR 98.33(e) to 

indicate that separate reporting of biogenic CO2
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emissions is not required for units subject to subpart 

D of part 98, and for part 75 units using the 

alternative CO2 mass emissions reporting options in 40 

CFR 98.33(a)(5). However, if the owner or operator 

elects to report biogenic CO2 emissions, the methods in 

§98.33(e) would be used.

• Three paragraphs of the data reporting section of 

subpart C, specifically 40 CFR 98.36(d)(1)(ii), 

(d)(2)(ii)(I), and (d)(2)(iii)(I), would be amended to 

reinforce that separate reporting of biogenic CO2

emissions is optional for part 75 units. 

The proposed amendments would not affect the burden 

for existing facilities, as existing non-Part 75 facilities 

were always required to calculate and report biogenic 

emissions separately. The amendments would simply require 

them to include those biogenic emissions in facility-wide 

and source category (subpart) totals, as opposed to 

subtracting them out. The proposed amendments would also 

address the inconsistency that appeared in Part 98 

regarding separate reporting of biogenic emissions for 

electric generating units subject to subpart D or other 

units subject to Part 75, as these facilities would no 

longer be required to report facility emissions excluding 

biogenic CO2, although they retain the option to report 

biogenic CO2 separately. 

D. Subpart A (General Provisions): Requirements for 

Correction and Resubmission of Annual Reports 

Subpart A requires that an “owner or operator shall 

submit a revised report within 45 days of discovering or 
44 of 392

being notified by EPA of errors in an annual GHG report. 

The revised report must correct all identified errors. The 

owner or operator shall retain documentation for 3 years to 

support any revisions made to an annual GHG report.” 

Some owners and operators have asserted that the 

requirements for resubmission of annual reports within 45 

days of discovering an error or being notified by EPA of an 

error, and the requirement to correct all errors, is overly 

broad and could trigger a resubmission for virtually any 

error. They were also concerned that these requirements 

are made more burdensome by the fact that the data system 

is not yet developed, and some identified “errors” may not 

in fact be errors, but rather software bugs that are most 

likely to happen in the first year of operation of the data 

system. They have also observed that the regulatory

requirement is more burdensome than the Acid Rain Program 

(ARP), which has operated for more than 15 years without 

such a requirement in the regulation. 

We included this correction requirement in Part 98 

because we determined that it is important to ensure that 

the most accurate data are available, in a timely fashion, 

for developing future GHG policies and programs. 

Generally, adding a requirement to resubmit data is also 

consistent with other EPA reporting programs, such as the 
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ARP and the Toxic Release Inventory, as well as State and 

other GHG programs. While it is true that the ARP does not 

have a specific time requirement for resubmission in the 

regulation, in practice revised data have been submitted in 

less than 45 days after notification or identification of 

an error. While we maintain that it is important to retain 

a deadline for resubmission of the report after an error is 

identified in order to ensure EPA receives timely 

submission of data, we also recognize that certain 

circumstances may exist in which owners or operators cannot 

correct the identified errors within the 45 days. 

Therefore, we are proposing to amend 40 CFR 98.3(h) to 

clarify how a resubmission is triggered and the process for 

resubmitting annual GHG reports. 

First, reports would only have to be resubmitted when 

the owner or operator or the Administrator determines that 

a substantive error exists. A substantive error would be 

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 “errors” 

would not obligate the owner or operator to resubmit the 

annual report. 
46 of 392

The owner or operator would be required to resubmit 

the report within 45 days of identifying the substantive 

error, or the Administrator notifying them 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 proposed 

change would provide owners or operators the opportunity to 

demonstrate that what the Administrator has deemed to be 

substantive errors are not, in fact, substantive errors. 

Finally, we are also proposing to introduce the 

opportunity for owners or operators to request an extension 

on the 45-day resubmission deadline to address facilityspecific circumstances that arise in either correcting an 

error or determining whether or not an identified error is, 

in fact, a substantive error. Owners or operators would be 

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 

would be granted if EPA does not respond to the extension 

request by the end of the 45-day period.

We are proposing 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 
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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 would 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 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. 

E. Subpart A (General Provisions): Information to Record 

for Missing Data Events

Certain reporters have suggested that the 

recordkeeping requirements related to missing data events 

are overly burdensome. Specifically, 40 CFR 98.3(g)(4) of 

Part 98 specifies that the owner or operator must keep 

records of the cause and duration of each event, the 

actions taken to restore malfunctioning monitoring 

equipment, and actions taken to prevent or minimize future 

occurrences. They have asserted that compared to Part 98, 
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Part 75 requires only reporting of the cause of the missing 

data event and the corrective actions taken, but does not 

require separate accounting of the duration of the event or 

the actions taken to minimize occurrence in the future. 

They have further claimed that most missing data events 

associated with the use of continuous emissions monitors 

are due to routine activities or calibration failures for 

which there are no clear measures to avoid similar 

occurrences in the future. Therefore, according to the 

owners and operators, the final recordkeeping requirements 

are overly burdensome and add little value.

After reviewing these requirements, we agree with the 

claims and we are proposing to amend 40 CFR 98.3(g)(4) by 

requiring that records be kept of only the cause of each 

missing data event and the corrective actions taken. We 

have concluded that this information is sufficient for 

operating the program and that making this change will 

reduce the reporting burden for all reporters. This 

proposed revision would make the Part 98 recordkeeping 

provisions for missing data events consistent with those in 

40 CFR Part 75 (specifically 40 CFR 75.57(h)). We further 

propose to clarify that the records retained pursuant to 40 

CFR 75.57(h) may be used to meet the recordkeeping 
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requirements under Part 98 for the same missing data 

events.

F. Subpart A (General Provisions): Other Technical 

Corrections and Amendments 

We are proposing several amendments to subpart A, as 

follows. We are proposing to amend 40 CFR 98.3(c)(1) by 

adding a requirement to report a facility or supplier ID 

number. We expect to receive GHG emissions data in 

electronic format from thousands of facilities and 

suppliers. Therefore, a unique ID number must be assigned 

to each facility or supplier, for administrative purposes, 

to facilitate program implementation. This approach has 

worked well in other EPA programs that require electronic 

data reporting from large numbers of facilities (e.g., the 

Acid Rain and NOx Budget Programs). The exact mechanism for 

assigning the ID numbers has not yet been determined. EPA 

will provide the necessary guidance later this year.

We are proposing to amend the elements required with a 

certificate of representation under 40 CFR 98.4(i)(2) to 

include organization name (company affiliation-employer). 

We are also proposing to add the same element to the 

delegation by designated representative and alternate 

designated representative under 40 CFR 98.4(m)(2). This 

information will help EPA and reporting system users to 
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correctly identify persons during the designated 

representative appointment or agent delegation process. 

Part 98 and the proposed amendments would not require the 

designated representative, alternate designated 

representative or agent to be an employee of the reporting 

entity. When a designated representative further delegates 

their authority to an agent, the agent would gain access to 

all data for that facility or supplier. To underline the 

importance of granting access to the correct person, EPA 

would require the designated representative (or alternate) 

to confirm each agent delegation. Adding organization name 

to the certificate of representation and notice of 

delegation will add a level of assurance to the 

confirmation process.

We are proposing to amend 40 CFR 98.3(c)(5)(i) to 

clarify that for the purposes of meeting the requirements 

of this paragraph, suppliers of industrial flourinated GHGs 

only need to calculate and report GHG emissions in mtCO2e 

for those flourinated GHGs that are listed in Table A-1. 

This amendment is proposed because in order to incorporate 

additional fluorinated GHGs not listed in Table A-1 into 

the supplier’s total GHG emissions in mtCO2e, the reporter

would be required to propose a GWP for the gas or use an 

established factor developed by the Intergovernmental Panel 
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on Climate Change or another entity. EPA does not believe 

it is necessary to require reporters to develop a GWP for 

these gases at this time. Further, it is important to note 

that these gases would still be required to be reported

under 40 CFR 98.3(c)(5)(ii) (in metric tons of GHG). 

Therefore, EPA could calculate mtCO2e emissions from these 

gases in the future as GWP’s become available or are 

updated.

Finally, we are proposing to amend 40 CFR Part 98.6 

(Definitions) and 40 CFR Part 98.7 (What Standardized 

Methods are Incorporated by Reference into this Part?). We 

are proposing to add or change several definitions to 

Subpart A, which are needed to clarify terms used in other 

subparts of Part 98. Similarly, we are proposing to amend 

40 CFR 98.7 (incorporation by reference) to accommodate 

changes in the standard methods that are allowed by other 

subparts of the rule. 

We are proposing to amend 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 proposing to amend 40 CFR 98.3(f) to correct 

the cross-reference from “§98.3(c)(8)” to “§98.3(c)(9).”
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We are proposing to amend the definitions of several 

terms in 40 CFR 98.6:

• Bulk Natural Gas Liquid

• Distillate fuel oil

• Fossil fuel

• Mscf

• Municipal solid waste or MSW, and

• Natural gas.

Bulk Natural Gas Liquid. Owners and operators have 

objected to the definition of “bulk natural gas liquid or 

NGL.” Section 98.6 in subpart A defines “bulk natural gas 

liquid or NGL” as a product which “refers to mixtures of 

hydrocarbons that have been separated from natural gas as 

liquids through the process of absorption, condensation, 

adsorption, or other methods at lease separators and field 

facilities.” The owners and operators have requested we 

remove the phrase “or other methods at lease separators and 

field facilities” from the above definition. They assert 

that these processes are not simple separation processes, 

but rather, NGL extraction processes that are typically 

performed at “gas plants” and not at “lease separators and 

field facilities.” 

We agree that the separation processes listed in the 

definition of “bulk natural gas liquid or NGL” are 

associated with gas plants, and not lease separators and 
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field facilities. It was not EPA’s intent to require the 

reporting of emissions associated with these processes at 

lease separators and field facilities. In fact, in 40 CFR 

98.400, we specifically state that the supplier category 

consists only of natural gas liquids fractionators and 

local natural gas distribution companies. Under 40 CFR 

98.400(c), we specify that field gathering and boosting 

stations, as well as natural gas processing plants that 

“separate NGLs from natural gas ... but do not fractionate 

these NGLs into their constituent products” do not meet the 

source category’s definition. 

Therefore, we are proposing to strike “lease 

separators and field facilities” from the definition of 

“bulk natural gas liquid or NGL,” as well as from the 

definition of “natural gas liquids (NGL)” for enhanced 

clarity. However, we have determined that the words “or 

other methods” should remain in the above definition 

because the list of separation processes listed in the 

definition (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. 
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Distillate Fuel Oil. We are proposing to expand the 

definition of “Distillate fuel oil” to include kerosenetype jet fuel. 

Fossil Fuel. Some reporters have noted that the 

proposed rule set forth the same definition of “fossil 

fuel” that applies in the New Source Performance Standards 

program: "Fossil fuel means natural gas, petroleum, coal, 

or any form of solid, liquid, or gaseous fuel derived from 

such materials for the purpose of creating useful heat" (74 

FR 16621). 

However, the final Part 98 includes the following 

definition, which, according to certain Parties, has no 

precedent in Clean Air Act (CAA) regulations: "Fossil fuel 

means natural gas, petroleum, coal, or any form of solid, 

liquid, or gaseous fuel derived from such material, 

including for example, consumer products that are derived 

from such materials and are combusted." 

These owners and operators have asserted that the 

public did not have sufficient opportunity to comment on 

these changes, which together, they claimed, re-classify 

municipal solid waste (MSW) and tires as fossil fuel and 

could set an unintended precedent for other CAA programs. 

Further, they claimed that EPA changed the designation of 

MSW and tires from being classified as “alternative fuels” 
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in the proposal to being classified as “fossil fuel-derived 

fuels (solid)” in the final Part 98. 

We did not intend to “re-classify” MSW and tires 

between the proposal and final Part 98 in any meaningful 

way. Rather, any changes made were due to the overall 

restructuring of the General Stationary Fuel Combustion 

source category in response to comments and were intended 

to expand the use of Tier 1 and Tier 2, and to remove some 

requirements that would subject units to Tier 3. Based on 

the above concerns, however, it has become apparent that 

stakeholders believe the changes had unintended 

consequences. Therefore, we have reevaluated this issue 

and are proposing amendments to the classification of fuels 

in Table C-1, as well as the definition of fossil fuel. We 

note that overall we do not believe that the changes 

between the proposed and final Part 98, nor the amendments 

described below, have a substantive impact on the 

calculation requirements or the reporting of emissions for 

MSW or tires under this rule. 

We made several changes from proposal in Part 98 in 

response to comments about use of the Tiers. In subpart C, 

in order for facilities to use Tier 1 or Tier 2, the fuel 

combusted had to be included in Table C-1. MSW and tires 

were not included in Table C-1; rather they were included 
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in the proposed Table C-2, which was generically labeled 

“alternative fuels.” The restructuring of the Tiers in 

subpart C necessitated moving all fuels for which Tier 1 

and Tier 2 were allowed into Table C-1. Table C-1 labeled 

these fuels as “fossil fuel-derived” to reflect the methods 

used to calculate emissions, noting the related provisions 

for determining the biogenic portions of fuels in subpart 

C.

In order to address the above concerns raised with 

subpart C, we are now proposing to change the heading for 

these fuels from “fossil fuel-derived” to “Other fuels 

(solid)” in Table C-1. 

Further, we are proposing to amend the definition of 

fossil fuel to return to the initial proposed definition. 

After proposal, we altered the definition in subpart A 

intending to provide clarity to facilities subject to 

Subpart C in the reporting of CO2 emissions per the 

requirements of 40 CFR 98.36, specifically, intending to 

clarify what was meant in the proposed definition by 

“...solid, liquid, or gaseous fuel derived from such 

materials.” We also changed the definition in subpart A to 

better align the definition of fossil fuel with the 

definition of the general stationary fuel combustion 

sources in 40 CFR 98.30 (i.e., “devices that combust solid, 
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liquid, or gaseous fuels, generally for the purposes of 

producing electricity, generating steam, or providing 

useful heat or energy for industrial, commercial, or 

institutional use, or reducing the volume of waste by 

removing combustible materials”). 

We believe that the definition included in subpart A 

may have not added the clarity expected and that the 

definition of general stationary fuel combustion sources 

provided in subpart C is sufficient. We are soliciting 

comment on the proposed changes in the definition of fossil 

fuel in subpart A in the context of the calculation methods 

provided for these fuels in subpart C, and ask commenters 

to provide additional information if they believe that 

emissions from combusting these fuels should be estimated 

differently.

Mscf. We are proposing to amend the definition of 

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

thousand standard cubic feet, and not, as incorrectly noted 

in the final rule, a million standard cubic feet. 

Municipal Solid Waste. We have received many 

questions regarding the definition of “Municipal solid 

waste or MSW” in Part 98. Specifically, the brevity of the 

definition makes it difficult to determine whether certain 

types of waste constitute MSW. We are proposing to amend 
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the definition to closely match the definition of 

“municipal solid waste” in Subpart Ea of the NSPS 

regulations (40 CFR 60.51a). The amended definition would 

explain what is meant by “household waste,” 

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

would also provide a comprehensive list of materials that 

are excluded from these categories (e.g., industrial 

process or manufacturing wastes and medical waste). 

Natural Gas. We have also received many questions 

indicating that the definition of “Natural gas” is too 

inclusive and in some respects counterintuitive. The 

current definition begins with a statement that natural gas 

is a naturally occurring mixture of hydrocarbon and nonhydrocarbon gases found beneath the earth’s surface. 

However, it ends by equating “process gas” and “fuel gas” 

(neither of which is a naturally occurring gas mixture) 

with natural gas. We are proposing to amend the definition 

of “Natural gas” in 40 CFR 98.6 to be consistent with 

definitions found in 40 CFR Parts 60 and 75. The amended 

definition would remove the references to process gas and 

fuel gas, and would specify that natural gas must be at 

least 70 percent methane or have a high heat value between 

910 and 1150 Btu/scf. 
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We are proposing to add definitions of the following 

terms to 40 CFR 98.6 due to the large number of questions 

received requesting clarification of the definition of 

these terms:

• Agricultural byproducts, 

• Primary fuel, 

• Solid byproducts, 

• Waste oil, and 

• Wood residuals. 

The terms “Agricultural byproducts,” “Solid 

byproducts,” and “Wood residuals” are used to describe 

three types of solid biomass fuels listed in Table C-1 of 

Subpart C, but they are not defined in 40 CFR 98.6. The 

proposed definitions are based on the results of an 

Internet search and IPCC inventory guidelines (see EPA-HQOAR-2008-0508). For the purposes of Part 98, “Agricultural 

byproducts” would include the parts of crops that are not 

ordinarily used for food (e.g., corn straw, peanut shells, 

pomace, etc.). “Solid byproducts” would include plant 

matter such as vegetable waste, animal materials/wastes, 

and other solid biomass, except for wood, wood waste and 

sulphite lyes (black liquor). “Wood residuals” would 

include waste wood recovered primarily from MSW streams, 

construction and demolition debris, and primary timber 

processing. Wastewater process sludge generated at pulp 
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and paper mills would also be included; however, we are 

soliciting comment on whether the default emission factors 

for wood and wood residuals are appropriate for paper mill 

wastewater sludge, and, if not, what those emission factors 

should be.

“Primary fuel” would be defined as the fuel that 

contributes the greatest percentage of the annual heat 

input to a combustion unit. “Waste oil,” which we are 

proposing to add to Table C-1 as a new fuel type, would be 

defined as oil whose physical properties have changed, 

either through storage, handling, or use, so that the oil 

can no longer be used for its original purpose. Waste oil 

would include both automotive and industrial oils of 

various types. 

G. Subpart C (General Stationary Fuel Combustion)

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 proposed 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 to calculate weighted annual 

average HHV.

• Categories of gaseous fuels.
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• 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 units with CEMS.

• Use of Tier 3.

• Tier 4 requirements for units that combust greater 

than 250 tons of MSW per day.

• Applicability of Tier 4 to common stack 

configurations.

• Starting dates for the use of Tier 4.

• CH4 and N2O calculations.

• CO2 emissions from sorbent.

• Biogenic CO2 emissions from biomass combustion.

• Fuel sampling for coal and fuel oil.

• Tier 3 sampling frequency for gaseous fuels.

• CO2 emissions from blended fuel combustion.

• Use of consensus standard methods.

• CO2 monitor span values.

• CEMS data validation.

• Use of 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 proposing 

to add a 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. Section 98.30(a) of 

subpart C defines a stationary fuel combustion source as a 

device that combusts “... solid, liquid, or gaseous fuel, 

generally for the purposes of producing electricity, 
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generating steam, or providing useful heat or energy for 

industrial, commercial, or institutional use, or reducing 

the volume of waste by removing combustible matter ...”. A 

pilot light is small permanent 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 to provide useful 

energy to an industrial process, or to reduce waste by 

removing combustible matter. Therefore, we are clarifying 

that, for the purposes of Part 98, a pilot light is not 

considered to be a stationary fuel combustion source and 

pilot gas consumption would not be required to be included 

in the GHG emissions calculations. 

GHGs to Report. We are proposing to amend 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. 

Calculating GHG emissions. We are proposing to amend 

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 proposing to amend this 

paragraph to point out that certain sources may use the 
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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 Clean Air Act program. Paragraph 

98.33(a) would also be 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. Subpart 

C of Part 98 allows the use of fuel billing records to 

quantify natural gas consumption, for the purposes of 

calculating CO2 mass emissions. On the billing records 

provided by natural gas suppliers, fuel usage is often 

expressed in units of “therms,” rather than standard cubic 

feet (scf). A therm is equal to 100,000 Btu, or 0.1 mmBtu. 

Therefore, the equations for calculating CO2 mass emissions 

in Subpart C (e.g., Equation C-1), which require fuel usage 

to be in units of scf, are not suitable when fuel 

consumption is expressed in therms.

In view of this, we are proposing to amend 40 CFR 

98.33(a)(1) by adding a new equation, C-1a, to Tier 1. 

When natural gas consumption is expressed in therms, 

equation C-1a would enable 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. 
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We are proposing to allow 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), would be added to 40 

CFR 98.33 to reflect this. Section 98.36(e)(2)(i) would 

also be amended to allow gaseous fuel consumption to be 

reported in units of therms.

Use of Equation C-2b. Whenever HHV data are received 

on a monthly or more frequent basis, the Tier 2 CO2

emissions calculation methodology requires the owner or 

operator to use Equation C-2b to calculate the annual 

average HHV, weighted according to monthly fuel usage. The 

fuel-weighted annual average HHV is then substituted into 

Equation C-2a. If HHV data are received less frequently 

than monthly, an arithmetic average HHV is used in the 

emissions calculations (see 40 CFR 98.33(a)(2)(ii)). 

However, we have learned that in cases where a 

facility includes part 75 units (i.e., boilers and/or 

combustion turbines) and small combustion sources such as 

space heaters that share a common natural gas or oil 

supply, the use of Tier 2 may be triggered for the small 

combustion sources when the part 75 units use the appendix 

D methodology to quantify heat input. This is because 

appendix D of Part 75 requires periodic sampling of the 
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heating value of fuel oil and natural gas. Tier 2 will be 

triggered for the small combustion units if the Part 75 

fuel sampling frequency is equal to or greater than the 

minimum frequency specified in §98.34(a). Further, if the 

part 75 fuel sampling frequency is monthly or greater, 

Equation C-2b would have to be used to calculate fuelweighted annual average HHVs for the small combustion 

sources. 

Requiring small, low-emitting combustion sources to 

calculate CO2 mass emissions using fuel-weighted annual 

average HHVs instead of arithmetic average values will not 

significantly enhance data quality. In view of this, we 

are proposing to amend 40 CFR 98.33(a)(2)(ii), to require 

calculation of a weighted HHV 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 §98.36(c)(1) in which all units in the group 

are smaller than 100 mmBtu/hr, the annual arithmetic 

average HHV, rather than the annual fuel-weighted average 

HHV, would be used in Equation C-2a.

Categories of Gaseous Fuels. Section 98.34(a)(2)(iii) 

of subpart C requires quarterly HHV sampling for liquid 
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fuels other than fuel oil, for fossil fuel-derived gaseous 

fuels, and for biogas, when the Tier 2 methodology is used 

to calculate CO2 mass emissions. The term “fossil fuelderived gaseous fuels” has caused considerable confusion 

among regulated sources. The nomenclature and organization 

of Table C-1 of Subpart C makes it hard to determine which 

fuels are included in this category. Currently, only two 

fuels are listed in Table C-1 under the heading of fossil 

fuel-derived gaseous fuels: blast furnace gas and coke oven 

gas. However, a number of other gaseous fuels that are 

derived from petroleum, such as butane, are not listed 

there, but are listed under a different heading for 

“petroleum products.” 

We are proposing to revise 40 CFR 98.33(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 would also be made to 

Table C-1 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) 

currently allows flow meters that measure mass flow rates 

of liquid fuels to be used to quantify fuel consumption, 
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provided that the density of the fuel is determined and the 

measured mass of fuel is converted to units of volume 

(i.e., gallons), for use in Equation C-4. In response to a 

number of requests, we are proposing to amend 40 CFR 

98.33(a)(3)(iv), to conditionally allow flow meters that 

measure mass flow rates of gaseous fuels to be used for 

Tier 3 applications. To use mass flow meters, the density 

of the gaseous fuel would have to be measured, 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. The 

Tier 4 calculation methodology in 40 CFR 98.33(a)(4) 

requires a CO2 CEMS to be used together with a stack gas 

flow rate monitor to measure CO2 mass emissions. If the CO2

monitor measures on a dry basis, corrections for the stack 

gas moisture content are needed, because the flow monitor 

measures on a wet basis. 

Part 98 currently requires that the moisture 

corrections be made either by installing a continuous 

moisture monitoring system or by using a default moisture 

value from 40 CFR Part 75 (specifically 40 CFR 75.11(b)(1)) 

in the calculations. However, the default moisture 
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constants from Part 75 only apply to various grades of 

coal, and to wood and natural gas.

Recently, we have received inquiries from a number of 

sources that currently have dry-basis CO2 monitors in place 

and are required to use Tier 4. These sources have 

requested that EPA allow the use of site-specific default 

moisture values, in cases where no applicable default value 

is specified in Part 75 for the type(s) of fuel(s) 

combusted, or where the Part 75 moisture values are 

believed to be unrepresentative.

EPA has approved many petitions for site-specific 

moisture content default values under the ARP. Therefore, 

we believe it is reasonable to allow Part 98 sources to 

develop such default values, using an approach similar to 

the one that has been approved under the ARP. 

In view of this, we are proposing to amend 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) would have to represent the 

fuel(s) or fuel blends that are combusted in the unit 

during normal, stable operation, and would have to account 

for any distinct difference(s) in stack gas moisture 

content associated with different process operating 

conditions.
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For each site-specific default moisture percentage, at 

least nine runs would be required using EPA Method 4 -

Determination Of Moisture Content In Stack Gases (40 CFR 

Part 60, Appendix A-3). Moisture data from the relative 

accuracy test audit (RATA) of a CEMS could be used for this 

purpose. Each site-specific default moisture value would 

be calculated by taking the arithmetic average of the 

Method 4 runs. 

Each site-specific moisture default value would be 

updated at least annually, and whenever the current value 

is believed to be non-representative, due to changes in 

unit or process operation. The updated moisture value 

would be used in the subsequent CO2 emissions calculations. 

Determining Emissions from an Exhaust Stream Diverted 

from a CEMS Monitored Stack. We are proposing to amend 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 paragraph is intended to address situations where a 

portion of the stack gas generated by the Tier 4 unit is 

diverted for the purpose of drying fuels, recovering heat, 
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or some other process-related activity. The provisions of 

the new paragraph would not apply when CO2 is removed or 

chemically altered in a way that significantly changes the 

CO2 concentration at the outlet of the unmonitored stack, 

compared to the outlet CO2 concentration at the stack 

equipped with a CEMS. The owner or operator would be 

required to use the best available information to estimate 

the hourly stack gas volumetric flow rates exhausting 

through the unmonitored stack. Best available information 

would include, but would not be limited to, correlation of 

operating parameters with flow rate, periodic flow rate 

measurements made with EPA Method 2, engineering analysis, 

etc. The estimated flow rates of the diverted gas stream 

would be made at the point where the diverted stream exits 

the main flue gas exhaust system. Each hourly volumetric 

flow rate value used in Equation C-6 of Subpart C would be 

the sum of the flow rate measured at the stack equipped 

with a CEMS and the estimated flow rate of the diverted gas 

stream. All procedures used to estimate the volumetric 

flow rate of the diverted gas stream would be documented in 

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

Biomass Combustion in Units With CEMS. We are 

proposing to amend 40 CFR 98.33(a)(5)(iii)(D) to 

redesignate it as 40 CFR 98.33(a)(5)(iv). This is to 
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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). As discussed above in 

section II.C of the preamble, we are also proposing 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 Part 75 methodologies to calculate 

CO2 mass emissions, as described in 40 CFR 98.33(a)(5)(i) 

through (a)(5)(iii). As discussed above, separate 

reporting of biogenic CO2 emissions is also optional for 

units subject to subpart D.

Use of Tier 3. Section 98.33(b)(3)(iii) of subpart C 

currently requires the use of Tier 3 when a fuel that is 

not listed in Table C-1 of Subpart C is combusted in a unit 

with a maximum rated heat input capacity greater than 250 

mmBtu/hr, if two conditions are met: (a) the use of Tier 4 

is not required; and (b) the fuel provides at least 10 

percent of the annual heat input to the unit. 

However, 40 CFR 98.33(b)(3)(iii)(B) refers to the 

annual heat input to a group of units served by a common 

supply pipe, in addition to the heat input to an individual 

unit. The text of 40 CFR 98.33(b)(3)(iii) is not 
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consistent with 40 CFR 98.33(b)(3)(iii)(B) because it does 

not mention common pipe configurations.

We are proposing to amend 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. 

The Agency also proposes to add 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 

fuel type or unit size. For example, Subpart Y requires 

certain units that combust refinery fuel gas (RFG) 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 Requirements For Units That Combust Greater 

Than 250 Tons Of MSW Per Day. Owners and operators of 

units that combust municipal solid waste have contended 

that, because Part 98 requires that units that combust MSW 

must follow Tier 4 if they meet the requirements in 40 CFR 

98.33(b)(4)(ii) or 40 CFR 98.33(b)(4)(iii), it entails a 

disproportionate burden for municipal waste combustors 

(MWCs). One element of their argument was that a threshold 

of greater than 250 tons per day of MSW was a more 

stringent threshold than the 250 mmbtu/hr heat input 
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threshold for other stationary combustion units and, 

therefore, a disproportionate burden for MWCs. Further, 

they stated that the industry did not have the necessary 

emission monitoring equipment in place and would, 

therefore, be required to install new equipment in order to 

meet the requirements of the rule. 

Part 98 included a threshold of 250 tons of MSW per 

day because it was consistent with the threshold applied in 

the EPA New Source Performance Standards (NSPS). Under 

that program, units combusting greater than 250 tons per 

day of MSW are considered “large” units. We did not 

believe that subpart C applied a disproportionate burden to 

municipal waste combustors because all “large” units 

(whether 250 tons of MSW per day or with a heat input 

capacity greater than 250 mmBtu/hr) would only be subject 

to Tier 4 if they met the other conditions outlined in 40 

CFR 98.33(b)(4). We have reevaluated this issue based on 

the fact that while a threshold of 250 tons of MSW may be 

appropriate for the purposes of NSPS, it is not necessarily 

appropriate for a GHG emissions reporting program. We also 

recognize that a large majority of the units may have to 

install either a flow meter or a concentration monitor, and 

in some cases both, to comply with subpart C. 
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Based on these concerns, we are proposing to amend 40 

CFR 98.33(b)(4)(ii)(A) to change the 250 tons MSW per day 

threshold to 600 tons MSW per day, based on further 

analysis that this value is approximately equivalent to the 

250 mmBtu/hr heat input requirements for other large 

stationary combustion units. For more information, please 

refer to the Background Technical Support Document (EPA-HQOAR-2008-0508). Units less than 600 tons MSW per day, that 

do not meet the requirements in 40 CFR 98.33(b)(4)(iii) 

could use Tier 2. We believe that this proposal still 

meets the desired goal to obtain high quality data from 

larger units, while not applying unnecessary burden. With 

this proposed amendment, MWCs would be subject to 

comparable monitoring thresholds and conditions as other 

general stationary combustion units. 

Applicability of Tier 4 to Common Stack 

Configurations. Section 98.36(c)(2) of Subpart C allows 

the owner or operator of stationary combustion units that 

share a common stack (or duct) and use the Tier 4 

methodology to calculate CO2 mass emissions to continuously 

monitor and report the combined CO2 mass emissions at the 

common stack (or duct), in lieu of separately monitoring 

and reporting the CO2 emissions from the individual units. 
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Several other Subparts of Part 98 either: (1) allow a 

particular process or manufacturing unit to use Tier 4 to 

quantify CO2 mass emissions, as an alternative to using a 

mass balance approach (for instance, Subpart G allows this 

option for an ammonia manufacturing unit—-see 40 CFR 

98.73(a) and (b)); or (2) require Tier 4 to be used in 

certain instances when a process unit and a stationary 

combustion unit share a common stack (e.g., see 40 CFR 

98.63(g) and 98.73(c)). 

Subpart C sets forth the applicability of Tier 4 in 40 

CFR 98.33(b)(4)(ii) and (b)(4)(iii). However, note that 40 

CFR 98.33(b)(4) focuses exclusively on individual 

stationary fuel combustion units; no mention is made of 

common stack configurations.

In view of this, we are proposing to amend 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) would be 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) would also be added, describing the 

following three distinct common stack configurations to 

which Tier 4 might apply. 
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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 

would apply if:

• 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); and

• 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 would also apply when all of the combustion 

units in the configuration are small (≤ 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 would be 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 
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stationary combustion units and a process unit (or units) 

are vented through a common stack or duct, Tier 4 would be 

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 

an applicable subpart of Part 98, the owner or operator 

could 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 would have to be monitored at the common stack or 

duct, using Tier 4.

Starting Dates For The Use Of Tier 4. Section 

98.33(b)(5) of subpart C currently 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. Recently, a number of sources have asked EPA whether 
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Tier 4 may be used prior to January 1, 2011 if the required 

CEMS are certified some time in 2010, or whether Tier 2 or 

Tier 3 must be used for the entire year.

We believe that it is reasonable for sources to begin 

reporting CO2 emissions data prior to 2011 from CEMS that 

successfully complete certification testing in 2010. 

Therefore, we are proposing to amend 40 CFR 98.33(b)(5) 

accordingly. 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)).

The proposed revisions would 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 tests are passed. CEMS data 

recorded during the certification test period could also be 

used for Part 98 reporting, provided that: (a) all required 

certification tests are passed in sequence, with no test 

failures; and (b) no unscheduled maintenance or repair of 

the CEMS is required during the test period.

We are also proposing to amend 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 
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makes a change that triggers Tier 4 applicability by 

changing: (1) the primary fuel, (2) the manner of unit 

operation, or (3) the installed continuous monitoring 

equipment. In such cases, the owner or operator would be 

required to begin using Tier 4 no later than 180 days from 

the date on which the change is implemented. This would 

allow 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. The equations 

for calculating CH4 and N2O emissions from stationary 

combustion sources are found in 40 CFR 98.33(c). 

Calculation of these emissions is required only for fuels 

listed in Table C-2 of Subpart C. When either the Tier 1 

or the Tier 3 methodology is used to determine CO2 mass 

emissions, Equation C-8 is used to calculate CH4 and N2O 

emissions. Equation C-8 includes the term “HHV,” which is 

defined as the applicable default high heat value (HHV) 

from Table C-1 for a particular type of fuel. Owners and 

operators have asserted that they should be able to use 

actual HHV data for Tier 3 units, in lieu of using the 

Table C-1 default values, and noted that site-specific 

values would be more accurate. 
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We agree that this would result in more accurate 

estimates of emissions and are proposing to revise the 

definition of the term “HHV” in the Equation C-8 

nomenclature. The proposed amendment would allow Tier 3 

units to use actual HHV data to calculate CH4 and N2O 

emissions. If multiple HHV values are obtained during the 

year, the arithmetic average would be used in Equation C-8.

Units that monitor heat input year-round according to 

40 CFR Part 75 or that use the Tier 4 CO2 calculation 

methodology are required to use Equation C-10 in Subpart C 

to calculate CH4 and N2O emissions. When more than one type 

of fuel listed in Table C-2 is combusted in these units 

during normal operation, 40 CFR 98.33(c)(4)(ii) requires 

Equation C-10 to be used separately for each fuel. 

Owners and operators have asked EPA to clarify what is 

meant by “normal operation,” and whether any fuel(s) should 

be excluded from the emissions calculations. Today’s 

proposed amendments would clarify the Agency’s intent by 

removing the term “normal operation” from 40 CFR 

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

CH4 and N2O emissions would simply be required for each 

Table C-2 fuel combusted in the unit during the reporting 

year.
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We are also proposing to further amend 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. For all multi-fuel units 

that use CEMS to comply with Part 98, subpart C requires 

the “best available information” to be used to determine 

the percentage of the annual unit heat input contributed by 

each type of fuel, for the purposes of calculating CH4 and 

N2O mass emissions. 

For part 75 units that use CEMS to quantify unit heat 

input, the fuel-specific annual heat input values needed 

for the CH4 and N2O emissions calculations can, in most 

cases, be determined from information in the part 75 

electronic data reports---specifically, from the “Ffactors” reported for each unit operating hour. These Ffactors, which are fuel-specific, are used in the hourly 

heat input calculations. Therefore, it is possible to use 

the reported F-factors to group the annual unit operating 

hours according to fuel type, and to sum the reported 

hourly heat input values for each group. However, if the 

owner or operator elects to use the reporting option in 

section 3.3.6.5 of part 75, appendix F, the fuel-specific 

heat input values cannot be determined from the emissions 
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reports. This is because section 3.3.6.5 of appendix F 

allows the owner or operator to calculate all hourly heat 

input values using the “worst-case” (highest) F-factor for 

any fuel combusted in the unit. A situation where this 

reporting option is likely to be implemented is for a coalfired utility boiler that uses small amounts of natural gas 

for unit startup. A second example where the worst-case Ffactor option is sometimes used is for a unit that combusts 

a blend of bituminous coal and sub-bituminous coal, in 

varying proportions. The F-factors for these two grades of 

coal are nearly the same. For the examples cited, the 

impact on the reported annual unit heat input is generally 

very small (1 to 2 percent at most). In view of this, we 

are proposing to allow part 75 units that use the worstcase F-factor reporting option to 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), and we are proposing to allow 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 
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determined directly from the part 75 electronic data 

reports.

Carbon Dioxide Emissions from Sorbent. Section 

98.33(d) of subpart C currently requires the following 

sources to use Equation C-11 to calculate and report CO2

mass emissions from sorbent, except where the total CO2

emissions are measured using CEMS: (a) fluidized bed 

combustion units; (b) units with wet flue gas 

desulfurization (FGD) systems; and (c) units equipped with 

“other acid gas emission controls with sorbent injection.” 

Equation C-11 includes the term “R,” which is defined as 

“1.00, the calcium to sulfur stoichiometric ratio.” 

Industry members have noted that some sorbents that 

reduce acid gas emissions do not produce CO2 (for instance, 

Ca(OH)2 does not). Further, the 1.00 value of R in 

Equation C-11 applies only to SO2 removal, indicating that 

one mole of CO2 is produced for every mole of SO2 removed. 

We have also been informed that CO2–producing sorbents such 

as sodium bicarbonate are sometimes injected to remove 

other acid gas species (e.g., HCl). 

In view of these considerations, we are proposing to 

amend 40 CFR 98.33(d) by making it more generally 

applicable to different types of CO2–producing sorbents. 

The term “R” would be redefined as the number of moles of 
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CO2 released upon capture of one mole of acid gas. When the 

sorbent is CaCO3, the value of R would be 1.00. For other 

CO2–producing sorbents, a specific value of R would be 

determined by 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. In 

response to questions about the methodologies in 40 CFR 

98.33(e) for calculating biogenic CO2 mass emissions from 

biomass combustion, we are proposing a number of technical 

corrections and clarifications to that section of the rule.

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

would be amended to more precisely define the requirements 

for reporting biogenic CO2 emissions. In general, biogenic 

CO2 emissions reporting would be 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 proposing to amend 40 CFR 98.33(e) to 

describe three cases in which units that combust biomass 

would not need to report biogenic CO2 emissions separate 

from total CO2 emissions: 

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

biogenic CO2 emissions would need to be reported 

separately from total CO2 emissions only if:
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– 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; and 

– The unit does not use CEMS to quantify its annual 

CO2 mass emissions. 

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

Tier 3 would have to be used to determine the carbon 

content of the biomass fuel and to calculate the biogenic 

CO2 emissions.

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 reporting of biogenic CO2 emissions would be 

optional. 

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

biogenic (typically 10-20 percent biomass, for car and 

truck tires), separate reporting of the biogenic CO2

emissions would be optional, but could be done 

following provisions in 40 CFR 98.33(e).

We are proposing to amend 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. There is no technical basis for 

this restriction, provided that biomass consumption can be 

accurately quantified. However, the use of Tier 1 would 

not be allowed for combustion of MSW, as originally 

specified in 40 CFR 98.33(e)(1) of subpart C, and would 

also not be allowed for the combustion of tires, if 

biogenic CO2 emissions are calculated for tires.
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We are proposing to amend the methodology in 40 CFR 

98.33(e)(2), which is specifically for units using a CEMS 

to measure CO2 mass emissions, by:

1. 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 

2. Prohibiting its use if the unit combusts MSW or tires. 

Section 98.33(e)(2) of subpart C currently requires 

the total volume of CO2 produced from fossil fuel combustion 

(which is based on estimated fuel usage, measured HHVs and 

F-factors) to be subtracted from the total volume of CO2

from the combustion of all fuels (as determined from the 

CEMS data). The difference is assumed to be the volume of 

biogenic CO2. However, this approach is only viable if all 

of the CO2 emissions are from the combustion of fossil fuels 

and biomass, and if no fuels (such as MSW and tires) that 

are a mixture of biomass and fossil fuel derivatives are 

combusted in the unit. 

If there are any process CO2 emissions or CO2 emissions 

from sorbent in the stack effluent, the volumes of those CO2

emissions would have to be subtracted from the total volume 

of CO2 derived from the CEMS data in order to determine the 

biogenic CO2 volume. Further, if any partly biogenic fuels 

(such as MSW and tires) are combusted in the unit, the 
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fossil component of each of these fuels would have to be 

characterized. We are not aware of any method that is 

economically feasible for reporting sources to determine 

the mass percentage of the fossil fuel component of fuels 

such as MSW and tires. In addition, we are not aware of 

any practical method for quantifying CO2 volumes from 

sorbent or from non-combustion industrial processes. For 

these reasons, we are proposing restrictions “1” and “2” 

above on the use of the methodology in 40 CFR 98.33(e)(2).

For sources that are combusting MSW, we are proposing 

to amend 40 CFR 98.33(e)(3) to require the use of ASTM 

methods D7459-08 and D6866-08 quarterly, 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 proposing to further amend 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.

We are also proposing to delete and reserve 40 CFR 

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

98.33(e)(4) allows the ASTM methods to be used to determine 

biogenic CO2 emissions for various combinations of biogenic 

and fossil fuels, we are proposing to delete and reserve it 
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because the paragraph also includes an unnecessary 

restriction, i.e., it only applies to units that use CEMS 

to measure total CO2 mass emissions. The proposed 

amendments to 40 CFR 98.33(e)(3) described above would 

achieve the same intended purpose as 40 CFR 98.33(e)(4), 

without imposing this restriction, so 40 CFR 98.33(e)(4) is 

no longer needed.

Finally, we are proposing to amend 40 CFR 98.33(e)(5) 

so that it would also apply 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 C2a would apply when HHV data for a biomass fuel are 

available at the minimum frequency specified in 40 CFR 

98.34(a)(2).

Fuel Sampling For Coal And Fuel Oil. We are proposing 

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

which the HHV needs to be determined for different types of 

fuels.

In subpart C, the Tier 2 calculation methodology in 40 

CFR 98.33(a)(2) requires periodic fuel sampling and 

analysis to determine HHVs. Section 98.34(a)(2) specifies 
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the minimum required sampling frequency for various fuel 

types. For coal and fuel oil, at least one representative 

sample must be obtained and analyzed for each fuel lot. A 

“fuel lot” is defined as a shipment or delivery of a 

particular type of fuel, and may consist of a ship load, a 

barge load, a group of trucks, or a group of railroad cars. 

Several reporters have noted that some facilities 

receive fuel deliveries by truck, rail or pipeline quite 

frequently—-even daily in some cases. The reporters have 

expressed the concern that, under subpart C, daily fuel 

deliveries appear to trigger a requirement for daily 

sampling and analysis, according to the definition of a 

fuel lot. Reporters have also noted that coal and 

petroleum derivatives such as coke and petroleum coke are 

often delivered in lots. Further, the Agency has received 

inquiries asking why a commonly-used fuel oil sampling 

strategy is not included in subpart C, i.e., taking a 

sample whenever oil is added to the storage tank.

It is not our intent to require an excessive amount of 

HHV sampling for coal and fuel oil (or for any other solid 

or liquid fuel that is delivered in lots), or to prohibit 

the use of viable sampling options. Therefore, we are 

proposing, first, to amend 40 CFR 98.34(a)(2)(ii) to expand 

the list of fuels for which sampling of each fuel lot is 
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sufficient to include other solid or liquid fuels that are 

delivered in lots.

Second, we are proposing to more precisely define the 

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

to facilities that receive multiple deliveries of a 

particular fuel from the same supply source each month, 

either by truck, rail, or pipeline. The proposed amendment 

would clarify that a fuel lot consists of all of the

deliveries for a given calendar month. Thus, for these 

facilities, the required HHV sampling frequency would be no 

greater than once per month. We are proposing to add 

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 proposed revisions to 40 CFR 

98.34(a)(2)(ii). 

Third, we are proposing to further revise 40 CFR 

98.34(a)(2)(ii) and 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 would also be 

allowed. 

Tier 3 Sampling Frequency for Gaseous Fuels. Section 

98.34(b)(3)(ii) of subpart C specifies the minimum required 

frequency for determining the carbon content and molecular 
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weight of various types of fuel, when using the Tier 3 

methodology to calculate CO2 mass emissions. For gaseous 

fuels, daily sampling is required if “the necessary 

equipment is in place to make these measurements.” 

Otherwise, weekly sampling is required.

EPA has received a number of questions from owners and 

operators about the meaning of “necessary equipment.” In 

particular, sources have asked whether this refers only to 

continuous, on-line equipment such as gas chromatographs, 

or whether daily, manual sampling is required where such 

capability exists.

We are proposing to amend 40 CFR 98.34(b)(3)(ii)(E) to 

clarify that daily sampling of gaseous fuels for carbon 

content and molecular weight is only required where 

continuous, on-line equipment is in place; weekly sampling 

would be required in all other cases. This has always been 

the Agency’s intent.

CO2 Emissions from Blended Fuel Combustion. One of the 

most frequently asked questions by the regulated community 

since the October 30, 2009 publication of 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. First, 40 CFR 98.34(a)(3) stated that when 

different types of fuel are blended (e.g., different ranks 
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of coal or different grades of fuel oil), two options could 

be used for determining the HHV for Tier 2 applications: 

(a) use a weighted HHV in the emissions calculations; or 

(b) take a representative sample of the blend and analyze 

it for HHV. Second, 40 CFR 98.34(b)(3)(v) stated that 

these same two options apply to carbon content and 

molecular weight determinations under Tier 3. Third, for 

Tier 3 common pipe applications, 40 CFR 98.34(b)(1)(vi) 

required that fuels either be metered individually before 

blending, or that the blended fuel and a subset of the 

individual fuels be metered so that the volume of each fuel 

in the blend can be determined.

Based on the number of questions received, we have 

concluded that these rule provisions do not adequately 

address the complexities associated with blended fuels. 

Therefore, we are proposing substantive amendments to 40 

CFR 98.34(a)(3), (b)(1)(vi), and (b)(3)(v). The proposed 

amendments would make a clear 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 
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known, the CO2 emissions from combustion of each component 

would be calculated separately. In the latter case, we are 

proposing that the blend be considered to be a distinct 

“fuel type,” and that its mass or volume and essential 

properties (e.g., HHV, carbon content, etc.) be measured 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 would be as follows. For 

smaller combustion units (heat input capacity not more than 

250 mmBtu/hr), we are proposing that Tier 2 (or possibly 

Tier 1) 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 emission factor would be calculated, 

using proposed Equation C-16. For Tier 1 applications, a 

heat-weighted default HHV would also have to be determined, 

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

combustion of the blend would be 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 would be 

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 proposed 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, we are proposing that the owner or operator would 

use Tier 3 to calculate the CO2 mass emissions from 

combustion of a blended fuel. The mathematics for Tier 3 

would be much 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 would be 

to accurately measure the annual consumption of the blended 

fuel and to determine its carbon content and (if 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 would be required in accordance with 40 
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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 

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

Calculation of CH4 and N2O emissions would be 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) would 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 would be required, 

based on the best available information, and the procedures 

in 40 CFR 98.33(c)(6)(ii) would be followed. First, the 

annual consumption of each component fuel in the blend 

would be calculated by multiplying the total quantity of 
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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 would be 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 would 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 would be summed across all components, and these 

sums would be reported as the annual CH4 and N2O mass 

emissions for the blend. 

Use of Consensus Standard Methods. Sections 

98.34(a)(6), (b)(4), and (b)(5) of subpart C specify 

acceptable methods for determining fuel HHV, carbon 

content, and molecular weight, and methods for calibrating 

fuel flow meters. The methods listed in those sections are 

from consensus standards organizations such as ASTM, ASME, 

AGA, and GPA. Although we attempted to assemble a 

comprehensive list of methods and provide appropriate 

alternatives, it is possible that other valid methods from 

these organizations and practices have been overlooked, or 

that in some cases, industry consensus standard methods may 
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be more appropriate than the methods listed. In view of 

this, we are proposing to remove the specific method lists 

from 40 CFR 98.34 and to amend 40 CFR 98.34(a)(6) and 

(b)(1)(i)(A), delete paragraph (b)(4), redesignate 

paragraph (b)(5) as (b)(4), and amend newly designated 

paragraph (b)(4). These proposed amendments would allow 

the owner or operator to either: (1) use appropriate 

methods published by consensus standards organizations such 

as ASTM, ASME, API, AGA, ISO, etc.; or (2) use industry 

standard practice. The methods used would 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 

percent CO2. These CO2 concentration levels are appropriate 

for most stationary combustion applications. For example, 
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a typical span value for a CO2 monitor installed on a coalfired boiler is 20 percent CO2; therefore, the CGA 

concentrations represent 25 to 40 percent of span and 50 to 

70 percent of span. 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 proposing to amend 40 

CFR 98.34(c) by adding a new paragraph (c)(6), which would 

allow the CGAs 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. The Tier 4 methodology in 40 

CFR 98.33(a)(4) requires the use of CEMS to measure CO2 mass 

emissions. For each unit operating hour, the CO2 mass 

emissions are determined using either valid CEMS data or 

appropriate substitute data values when monitors 

malfunction. For a Tier 4 unit, the owner or operator has 
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the option to follow the CEMS certification and QA 

provisions of 40 CFR Part 60, 40 CFR Part 75, or an 

applicable State CEM program. This includes the criteria 

in those regulations pertaining to validation of the hourly 

CEMS data.

The provisions for hourly CEMS data validation in Part 

60 are found in 40 CFR 60.13(h)(2)(i) through (h)(2)(vi). 

For Part 75, hourly data validation is addressed in 40 CFR 

75.10(d)(1). The CEMS data validation criteria in these 

sections of Parts 60 and 75 are virtually identical. The 

basic requirement to validate an hour is that at least one 

data point must be obtained in each 15-minute quadrant of 

the hour in which the unit operates. There is one notable 

exception to this. For operating hours in which required 

maintenance or QA testing is performed, obtaining a valid 

data point in two of the four quadrants is sufficient. 

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 are specified. In view of 

this, we are proposing to add a new paragraph, (c)(7), to 

40 CFR 98.34(c), which would require hourly CEMS data 

validation to be consistent with the sections of Part 60 or 

Part 75 cited in the preceding paragraph. Alternatively, 
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the hourly data validation procedures in an applicable 

State CEM program could 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 municipal solid waste (MSW) and other units 

that combust combinations of fossil fuels and biomass. As 

specified in Part 98, flue gas samples are taken quarterly 

using ASTM Method D7459-08 and analyzed using ASTM Method 

D6866-08. We are proposing to amend 40 CFR 98.34(d) and 

(e), as discussed in the following paragraphs.

The proposed amendments to 40 CFR 98.34(d) would 

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. Quarterly sampling with ASTM 

Method D7459-08 would still be required, for a minimum of 

24 consecutive operating hours. However, we are proposing 

to add 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. This sampling 

approach is recommended by experts on the use of ASTM 

Methods D7459-08 and D6866-08 when the types of fuel and 
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their composition are variable over time, as is the case 

with MSW combustion. For more information please refer to 

the Background Technical Support Document (EPA-HQ-OAR-2008-

0508).

We are proposing to amend 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 

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

would be allowed to determine biogenic CO2 emissions using 

the ASTM methods on a quarterly basis. At least 24 

consecutive hours of sampling is currently specified in 40 

CFR 98.34(e). This is appropriate if the types of fuels 

and their relative proportions are consistent throughout 

the quarter. If the relative proportions are not 

consistent throughout the quarter, it may be more 

appropriate to consider collecting more frequent samples, 

however this is not required. Therefore, we are also 

amending 40 CFR 98.34(e) to recommend that a small (1 to 5 

cc) flue gas sample be taken during each unit operating 

hour in the quarter.

Electronic Data Reporting and Recordkeeping. EPA will 

rely on Agency verification of the electronic data provided 

in the annual GHG emission reports, in lieu of implementing 
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third party verification. In order for Agency verification 

to be effective, sufficient information must be included in 

the electronic reports, at the facility, source category, 

and unit levels, to enable EPA to recalculate the reported 

GHG emissions and to quality-assure the data. 

Section 98.36 of subpart C provides several lists of 

data elements that must be reported for stationary 

combustion units. These lists are specific to the CO2

emissions calculation method employed (e.g., one of the 

four Tiers in 40 CFR 98.33(a) or a method in 40 CFR Part 

75), and to the type(s) of electronic data report(s) that 

are submitted (e.g., individual unit reports, aggregated 

group reports, common pipe reports, etc). 

EPA has begun developing software to check and verify 

the electronic data in the GHG emissions reports. As this 

effort has progressed, it has come to light that a number 

of important data elements are missing from the lists in 40 

CFR 98.36, and that some of the data elements on the lists 

are either not needed or require an excessive amount of 

non-essential data to be reported.

To address these issues, we are proposing to amend 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 
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lists are discussed in paragraphs (a) through (g), below. 

We are also proposing to add an additional alternative

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

burden for certain facilities. This option is described in 

paragraph (h), below. 

(a) We are proposing to add the reporting of 

methodology start and end dates in several places 

throughout 40 CFR 98.36(b), (c), and (d). These data 

elements are needed to accommodate changes in the methods 

used to calculate GHG emissions, when such changes occur 

during a reporting year or from one year to the next. 

(b) We are proposing to amend 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. 

(c) We are proposing to amend 40 CFR 98.36(b)(10) to 

remove the requirement to report the customer meter number 

for units that combust natural gas. 

(d) We are proposing to amend a number of data 

elements to reduce the reporting burden. For example, when 

small combustion units are aggregated into a group, 40 CFR 

98.36(c)(1)(ii) currently requires the ID number of each 

unit in the group to be reported. This requirement is 

unreasonable for facilities that have large numbers of very 
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small combustion sources, many of which do not have unique 

ID numbers. We are, therefore, proposing to amend this 

data element to require that only the total number of units 

in the group be reported, instead of the ID number of each 

unit in the group. As a second example, for the common 

pipe option described in 40 CFR 98.36(c)(3), only the total 

number of units served by the common pipe would be 

reported, instead of reporting an ID number for each unit, 

and only the highest maximum rated heat input capacity of 

any unit served by the common pipe would be reported, 

rather than reporting the rated heat input capacity of each 

individual unit.

(e) We are proposing to amend 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) from 40 CFR 

98.36(b)(9), (c)(1)(ix), (c)(2)(viii), and (c)(3)(viii). 

These data elements are duplicative of requirements in 

subpart A. 

(f) We are proposing to amend 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 proposing to amend 40 

CFR 98.36(e)(2)(iv) to require reporting of the annual 
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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. 

(g) We are proposing to amend 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 III.C of this preamble, the proposed amendments 

to 40 CFR 98.36(d) would state that reporting of biogenic 

CO2 emissions is optional for units using the CO2 mass 

emissions calculation methods in 40 CFR Part 75. 

(h) For units that use the Tier 4 methodology to 

calculate CO2 mass emissions, we are proposing to amend 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 proposed amendments to these sections 

will require the annual “non-biogenic” CO2 mass emissions to 

be reported instead of reporting the annual CO2 mass 

emissions from fossil fuel combustion. These revisions are 

being proposed because the total annual CO2 mass emissions 

measured by CEMS sometimes includes CO2 from sorbent or 

process CO2 emissions in addition to CO2 from fossil fuel 

combustion. The effect of the proposed amendments would be 
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to simplify reporting for Tier 4 units that have sorbent or 

process CO2 emissions in the flue gas stream. These units 

would be required only to report the combined annual nonbiogenic CO2 mass emissions, rather than having to 

separately account for the fossil CO2 emissions. Tier 4 

units that do not have any sorbent or process CO2 emissions 

in the flue gas would be unaffected by these proposed 

revisions, because their non-biogenic CO2 emissions are 

entirely from fossil fuel.

(i) We are proposing to add a new alternative 

reporting option, under 40 CFR 98.36(c)(4). This new 

option would apply to 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, you 

could 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
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• 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. 

Use of company records would be allowed to determine 

the percentage distribution of the shared fuel to the large 

and small units. Facilities using this reporting option 

would be 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 would suffice. 

(j) Finally, we are proposing to simplify the record 

keeping requirements in 40 CFR 98.36(e)(2)(iii), in cases 

where the results of fuel analyses for HHV are provided by 

the fuel supplier. Parallel language would be added in a 

new paragraph, (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 would 

be 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 dates may not be readily available). 

We believe that these proposed amendments to the 

recordkeeping and reporting requirements of 40 CFR 98.36 

are needed for data verification purposes. The proposed 
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amendments are not likely to increase the reporting burden 

on industry. In some cases, as previously noted, the 

proposed amendments would actually reduce the amount of 

information that must be collected or reported and the 

associated burden. 

Common Stack Reporting Option. Section 98.36(c)(2) of 

subpart C currently 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 Part 98. For example, if a Subpart G 

ammonia manufacturing unit shares a common stack with a 

Subpart C stationary combustion unit, the use of Tier 4 may 

be required (see 40 CFR 98.73(c)).

In view of this, we are proposing to amend 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 mixtures of 

combustion products and process off-gases are combined 

together and vented through a common stack or duct. 
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The proposed amendments to 40 CFR 98.36(c)(2) would 

not only apply to ordinary common stack or duct situations 

where the gas streams from multiple units are combined 

together, but would also apply when process and combustion 

gas streams from a single unit (e.g., from a kiln, furnace, 

or smelter) are combined. To accommodate this variation on 

the traditional concept of a common stack, 40 CFR 

98.36(c)(2)(ii) would be amended to require sources to 

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

or duct” when process and combustion emissions from a 

single unit are combined and 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 proposing to amend 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.

Common Fuel Supply Pipe Reporting Option. Section 

98.36(c)(3) of subpart C currently 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
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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 proposing to amend 40 CFR 98.36(c)(3) as 

follows. First, the erroneous citation of “§98.34(a)” 

would be corrected to read “§98.34(b).” Second, we are 

proposing to amend 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 cross-references the accuracy 

specifications in 40 CFR 98.3(i)), so that this calibration 

requirement would apply only when Tier 3 is the required 

tier for calculating CO2 mass emissions. The Agency 

believes that this clarification is needed, since the 

common pipe option can apply to Tier 1, 2, or 3, depending 

on the rated heat input capacities of the units served by 

the common pipe. Tiers 1 and 2 rely on company records to 

quantify fuel usage. Therefore, as noted in today’s 

proposed amendments to 40 CFR 98.3(i), the equipment used 

to generate company records under Tier 1 and 2 is not 
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required to meet the calibration accuracy specifications of

40 CFR 98.3(i). 

As previously noted, 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 proposing to add a second one. First, 40 CFR 

98.33(b)(2)(ii) 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. Second, proposed 40 CFR 98.33(b)(1)(v) would 

allow 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. Therefore, we are 

also proposing to amend 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. 
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Finally, we are proposing to amend the provision in 40 

CFR 98.36(c)(3) regarding the partial diversion of a fuel 

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 proposing 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 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 would be 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 
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1, Tier 2, or Tier 3 calculation methodology (as 

applicable). 

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

HHV values and default CO2 emission factors for various 

types of fuel. These default values are needed to 

calculate CO2 mass emissions when the Tier 1 and Tier 2 

methodologies in 40 CFR 98.33(a) are used. The fuels 

listed in Table C-1 are grouped into general categories 

(e.g., coal and coke, petroleum products, biomass fuels). 

Some distinctions are made within these categories, based 

on the state of matter (e.g., biomass fuels---liquid, 

fossil fuel-derived fuels (solid), etc.).

Since publication of the final Part 98, EPA has 

received many questions about the content and structure of 

Table C-1. Owners and operators in various industries have 

raised a number of issues concerning the way that fuels are 

categorized, the description of certain fuels, the units of 

measure of some of the default HHV values, and the absence 

of some fuels that were listed in Table C-2 of the April 

10, 2009 proposed rule. In particular:

(a) The categories “fossil fuel-derived fuels 

(solid)” and “fossil fuel-derived fuels (gaseous)” did not 

appear in the April 10, 2009 proposed rule and have been 

the source of some confusion. For instance, only two 
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fuels, MSW and tires, are listed under “fossil fuel-derived 

fuels (solid),” and neither of these is derived entirely 

from fossil fuels. Both of these fuels have a biogenic 

component. There are also only two fuels, blast furnace 

gas and coke oven gas, listed in the “fossil fuel-derived 

fuels (gaseous)” category. Several other fuels that are 

derived from petroleum and qualify as fossil fuel-derived 

gaseous fuels (e.g., still gas) are listed in a different 

category, “petroleum products.”

(b) Questions have arisen about the revised 

description of “natural gas” in Table C-1. The word 

“pipeline,” which was not in the April 10, 2009 proposed 

rule, was added in the final subpart C. 

(c) The Agency has received questions about the 

meaning of the terms “wood residuals,” “solid byproducts,” 

and “agricultural byproducts,” none of which appeared in 

the April 10, 2009 proposed rule.

(d) Questions have been asked why certain fuels that 

were listed in Table C-2 of the April 10, 2009 proposed 

rule do not appear in Table C-1. These include waste oil 

and plastics. 

(e) Owners and operators have questioned the 

appropriateness of the units of measure for still gas 

listed under “petroleum products.” The HHV for still gas, 
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which is in the gaseous state at ambient temperatures, is 

given in mmBtu per gallon, as though it were in the liquid 

state.

(f) Some industry questions indicate that reporters 

believe that the footnote beneath Table C-1 appears to 

prohibit MWC units that produce steam from using the 

default CO2 emission factor in the Table. This emission 

factor is needed to apply the Tier 2 CO2 emissions 

calculation methodology (specifically, Equation C-2c) to 

those units.

(g) EPA has received questions regarding the 

significance of indicating one hundred percent for ethanol 

and biodiesel, as well as questions regarding which 

emission factors to use for petroleum-derived ethanol.

In view of these considerations, we are proposing the 

following revisions to Table C-1:

• The categories “fossil fuel-derived fuels (solid)” and 

“fossil fuel-derived fuels (gaseous)” would be 

replaced with more inclusive terms, i.e., “other fuels 

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

fuels (solid)” category would include four fuels: 

plastics, municipal solid waste, tires, and petroleum 

coke. The “other fuels (gaseous)” category would 

include blast furnace gas, coke oven gas, propane gas, 

and fuel gas.

• The word “pipeline” would be removed from the 

description of natural gas.

• The following fuels: “wood residuals,” “agricultural 

byproducts,” and “solid byproducts” would be retained, 

but definitions of these terms would be added to 40 

CFR 98.6.
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• “Waste oil” would be added to the list of petroleum 

products, and a definition would be added to 40 CFR 

98.6.

• Still gas would be removed from the list of petroleum 

products.

• The footnote regarding MWC units would be revised to 

make it clear that MWC units that produce steam are 

only 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.

• The qualifier of one hundred percent for ethanol and 

biodiesel would be removed since these fuel types 

should be treated in the same way as other fuel types 

included in Table C-1. Removing this qualifier would 

clarify this without affecting any other provisions 

the rule.

• A default CO2 emission factor and a default high heat 

value would be added to the Table for petroleumderived ethanol. These would be the same as the 

default values for biomass-derived ethanol.

We are soliciting comment on these proposed amendments 

to Table C-1. Specifically, we request comment on: (1) the 

new and revised fuel categories; (2) the appropriateness of 

the HHVs and CO2 emission factors for the fuels listed in 

these categories; and (3) whether additional fuels should 

be included in Table C-1, and if so, what the HHVs and CO2

emission factors for those fuels should be. 

Table C-2. In the October 30, 2009 publication of 

Part 98, two essentially identical iterations of Table C-2 

of Subpart C were printed. The first iteration of Table C2 was a printing error. We are proposing to remove the 

first iteration of the Table and to make minor corrections 

to the second one. The proposed amendments consist of 
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correcting the exponents of the emission factors. The 

powers of ten in the right-hand column of the Table 

currently have an “underscore” character where there should 

be a minus sign, and one of the exponents is missing a 

zero.

Miscellaneous Proposed Revisions. In addition to the 

more substantive proposed amendments to Subpart C, we are 

proposing to correct a number of typographical errors, and 

to re-word the rule text in a few places for added clarity. 

We are also proposing to amend 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. Although these rule citations were inadvertently 

omitted from the October 30, 2009 publication of Part 98, 

we believe that Tier 4 sources understand that all required 

CEMS, including moisture monitoring systems, must be 

initially certified.

How Would These Amendments to Subpart C Apply to the 

2011 GHG Emissions Reports? EPA plans to address the 

comments on the proposed amendments to Subpart C and to 

publish the final amendments before the end of 2010. 

Therefore, reporters would be expected to use provisions of 

Part 98, as amended, to collect the relevant data and to 

calculate GHG emissions for the reports that are submitted 
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in 2011. We believe it is feasible for the sources to use 

the proposed changes to Subpart C for the 2010 reporting 

year, because the proposed revisions, to a great extent, 

simply clarify existing regulatory requirements. Further, 

the proposed amendments do not substantially affect the 

type of information that must be collected or how emissions 

are calculated. 

The following are examples of how the proposed 

amendments to Subpart C would clarify existing regulatory 

requirements. The amendments would clarify:

• That reporting of biogenic CO2 emissions is optional 

for units using the CO2 mass emissions calculation 

methodologies in 40 CFR Part 75. 

• How CH4 and N2O emissions are calculated for multi-fuel 

units that use the Tier 4 CO2 mass emissions 

calculation methodology.

• How to determine whether Tier 4 applies to various 

common stack configurations.

• How to determine which Tier (i.e., 1, 2, or 3) applies 

to common pipe configurations.

• How to calculate biogenic emissions for various types 

of units and fuels. Unnecessary restrictions on the 

use of certain calculation methods would be removed.

• How to apply the definition of a “fuel lot” at 

facilities that receive frequent deliveries of coal or 

fuel oil.

• How to calculate CO2, CH4, and N2O emissions for 

blended fuels.

The proposed amendments to 40 CFR 98.36, the data 

reporting section of Subpart C, would achieve two main 

purposes: (1) to ensure that enough data are provided to 
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enable the Agency to recalculate and verify the emissions 

data; and (2) to reduce burden, by removing the requirement 

to report certain non-essential data elements and by 

modifying other data elements. 

For example, the proposed amendments would:

• Require methodology start and end dates to be 

reported. This will enable us to track changes in 

emissions calculation methodologies (e.g., switching 

from a lower Tier to a higher Tier).

• Generally require reporting of fuel-specific CH4 and 

N2O emissions. This requirement was inconsistently 

applied in Part 98.

• Eliminate the need to report individual unit ID 

numbers and unit heat input capacities for groups of 

aggregated units, common pipe configurations, and 

common stack configurations.

• Remove the unnecessary requirement to report unitlevel combined CO2, CH4, and N2O emissions from fossil 

fuel combustion. 

• Remove the requirement for natural gas users to report 

their customer meter ID numbers. 

• Emphasize that biogenic CO2 emissions reporting is 

optional for Part 75 units. 

EPA believes that amendments such as these can be 

implemented for the reports submitted to EPA in 2011 

because the proposed changes are either consistent with or 

have no significant effect upon the calculation 

methodologies in Part 98. Since owners or operators are 

not required to report until March 2011, which is several 

months after we expect this proposal to be finalized, 
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sources should have sufficient time to adjust to the 

revisions. 

Several other proposed amendments to Subpart C 

address issues identified as a result of working with the 

affected sources during rule implementation. These 

proposed amendments would add flexibility to the rule. 

Owners or operators would be free to implement these new 

rule provisions once they are finalized. The following are 

examples of how today’s proposed Subpart C amendments would 

make the rule more flexible. The proposed amendments 

would:

• Allow fuel flow meters that measure on a mass basis to 

be used for gaseous fuels as well as liquid fuels, 

provided that the flow rate measurements are corrected 

for density.

• Allow the span of CO2 monitors to be set higher than 20

percent CO2 if necessary, when process CO2 and 

combustion CO2 emissions exit to the atmosphere through 

a common stack. 

• Allow the use of site-specific default moisture values 

for Tier 4 units that measure CO2 concentration on a 

dry basis.

• Provide a new Tier 1 equation for calculating CO2 mass 

emissions when fuel usage data obtained from gas 

billing records is expressed in units of therms.

• Allow smaller Tier 2 units (less than 100 mmBtu/hr) 

that receive monthly (or more frequent) HHV data to 

use an arithmetic average annual HHV in the emissions 

calculations instead of a fuel-weighted average HHV.

• Allow Tier 4 units to use an alternative (non-CEMS) 

method to account for the volumetric flow rate of a 

slip stream, when a portion of the flue gas is 

diverted and exhausts through a separate stack. 
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• Allow fuel oil sampling to be performed upon each 

addition of oil to the storage tank, as an alternative 

to sampling each fuel lot.

• Remove the lists of specific methods for determining 

HHV and carbon content and for fuel flow meter 

calibration, and specify instead that sources must 

either use appropriate methods from consensus 

standards organizations if such methods exist, or 

standard industry practice. 

• Add a new reporting option for configurations in which 

a common supply of gaseous or liquid fuel is shared 

between large combustion units and a group of smaller 

units such as space heaters, hot water heaters, etc. 

If at least 95 percent of the shared fuel is used by 

the large units, 100 percent of the GHG emissions from 

combustion of that fuel may be attributed to the large 

units. 

In some cases, facilities may have been following 

their current data collection practices during 2010, as 

well as using the methods required by Part 98. If a 

facility’s current practice provides the necessary data to 

implement the new options described immediately above, or 

if such data could be obtained and processed prior to the 

March 31, 2011 reporting deadline, the new options could be 

used for the reports submitted to EPA in 2011. 

Finally, the proposed amendments would make minor 

corrections to terms and definitions in certain Subpart C 

equations, and other technical corrections that would have 

no impact on facility’s data collection efforts in 2010. 

In summary, EPA believes that, in general, the 

proposed amendments to Subpart C would not require 
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monitoring or information collection above what is already 

required by Part 98. Therefore, we expect that sources 

will be able to use the same information that they have 

been collecting under Part 98 to calculate and report GHG 

emissions for 2010.

EPA seeks comment on its conclusion that the 

amendments to Subpart C can be implemented and incorporated 

into the initial GHG emissions reports by the due date of

March 31, 2011. Specifically, we seek comment on 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 request that 

commenters provide specific reasons why they believe that 

the proposed implementation schedule would or would not be 

feasible. 

H. Subpart D (Electricity Generation)

We are proposing to amend 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 

categories: (a) ARP units; and (b) non-ARP electricity 

generating units (EGUs) that are required to report CO2 mass 

emissions data to EPA year-round. At present, category 

“(b)” includes only non-ARP units that are subject to the 
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Regional Greenhouse Gas Initiative (RGGI) in the 

northeastern United States. 

Many non-ARP EGUs that are not in the RGGI are subject 

to the Clean Air Interstate Rule (CAIR). Some of these 

CAIR units report CO2 concentration data to EPA year-round, 

for the purposes of calculating NOx emission rates in 

lb/mmBtu and/or heat input rates in mmBtu/hr. However, 

they do not report CO2 mass emissions data to the Agency. 

Therefore, they are subject to Subpart C of Part 98, not 

Subpart D.

Data Reporting Requirements. Section 98.46 of subpart 

D currently specifies 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 are 

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 98.36(b), 40 CFR 98.36(c)(2), or 

40 CFR 98.36(c)(3). We are proposing to amend 40 CFR 98.46 

to correct this error. 

Recordkeeping. We are proposing to amend 40 CFR 98.47 

to state that the records kept under 40 CFR 75.57(h) for 

missing data events satisfy the recordkeeping requirements 
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of 40 CFR 98.3(g)(4) for those same events. We believe 

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). 

I. Subpart F (Aluminum Production)

Throughout Subpart F we are proposing corrections as 

needed for typographical errors and alphanumeric 

sequencing. We are proposing to amend 40 CFR 98.63, 

Calculating GHG Emissions, to clarify that each 

perfluorocarbon (PFC) compound (CF4, C2F6) 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 proposing to amend 40 CFR 98.64, Monitoring and 

QA/QC, 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 which are not measured annually, but are 
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instead measured on a more or less frequent basis. We are 

proposing a modification to 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 proposing to amend Table F-1 to spell out 

the acronyms for the technologies covered by that table; 

i.e., CWPB, side worked prebake (SWPB), vertical stud 

Søderberg (VSS), and horizontal stud Søderberg (HSS).

J. Subpart G (Ammonia Manufacturing)

We are proposing to amend subpart G to remove 

reporting of the waste recycle stream or purge, and to make 

subpart G conform to the proposed amendments to the 

calibration requirements in Subpart A. With respect to the 

waste recycle stream, we are proposing to eliminate 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 proposing to amend 40 CFR 
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98.72(b) so that subpart C does not apply to CO2 emissions 

resulting from the use of purge gas as a fuel. 

With respect to calibration requirements, we are 

proposing to clarify the calibration requirements for gas 

and oil flow meters used in the ammonia manufacturing 

process. Section 98.74(d) of subpart G currently states 

that all oil and gas flow meters except for gas billing 

meters must be calibrated according to the requirements for 

the Tier 3 methodology in 40 CFR 98.34(b). The Agency 

believes that the words “all oil and gas flow meters” in 

this subpart G provision are too inclusive and subject to 

misinterpretation. Therefore, we are proposing to amend 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 would have to be calibrated 

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.
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We are proposing to note through parentheticals in a 

number of places that the CO2 emissions estimates 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 proposed 

change does not impact the total CO2 emissions that are 

quantified and reported to EPA under the calculation 

equations in 40 CFR 98.73. The clarification is proposed 

so that it is transparent for stakeholders who ultimately 

use these data that some CO2 process emissions reported by 

the ammonia manufacturing process unit under this subpart 

may not be released from ammonia manufacturing, but at the 

point of urea application. To further enhance this 

transparency, EPA is also proposing to require reporting 

under 40 CFR 98.76 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 proposing to amend Subpart G to 

correct several typographical errors and an incorrect 

cross-reference to another subpart in Part 98. We are 

proposing to correct 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 proposing to correct 
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40 CFR 98.76(a) by changing the cross-reference from 

“§98.37(e)(2)(vi)” to “§98.37.” 

We are proposing to amend 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 proposing to amend 40 CFR 98.76(b)(6) to change 

“petroleum coke” to “feedstock” because petroleum coke is 

the incorrect term, and to amend 40 CFR 98.76(b)(15) to 

specify that the carbon content analysis method being 

reported is for each month. 

We are proposing to remove 40 CFR 98.76(b)(17) for the 

reporting of urea produced, if known. EPA finalized

reporting of this information to help improve methodologies 

for calculating emissions from ammonia manufacturing, urea 

production and urea consumption. Reporters stated that 

these data are already reported periodically to EPA under 

the Toxic Substances Control Act (TSCA) Inventory Update 

Rule (IUR). Although the TSCA IUR does not provide the 

full range of information that may ultimately be useful for 

informing future policy, EPA believes that the TSCA IUR 

provides adequate information at this time and, therefore,

we are proposing to delete that requirement. 

Finally, 40 CFR part 98, subpart G (Ammonia 

Manufacturing) and subpart V (Nitric Acid Production) 
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require that facilities report total pounds of synthetic 

fertilizer and total nitrogen contained in that fertilizer. 

After considering additional information provided by 

stakeholders, as well as other available information, we 

are proposing to remove the requirement from both subparts. 

EPA’s rationale for removing the requirement is as follows

(i) The data that would be reported under these 

subparts do not provide directly applicable information 

with which to determine N2O emissions from application of 

fertilizer because the data are incomplete. Domestic 

producers of synthetic nitrogen-based fertilizer make up 

less than one-half of the total amount of synthetic 

nitrogen-based fertilizer used in the United States. The 

remaining share is made up by synthetic nitrogen-based 

fertilizer imports, as well as fertilizer produced 

domestically outside of the Nitric Acid and Ammonia 

production industries using imported ammonia and nitric 

acid. 

(ii) EPA has information on the total supply and use 

of synthetic nitrogen-based fertilizer from other data 

sources that addresses near-term analytical needs, 

particularly for calculating national emissions of N2O. We 

obtain current sales data from Association of American 

Plant Food Control Officials (AAPFCO). The sales data is 
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equivalent to fertilizer application since the sales are 

from the last licensed dealer. 

EPA remains very interested in obtaining better data 

on N2O emissions. Nitrous oxide emissions from agricultural 

soils are an important source of greenhouse gas emissions 

in the United States (approximately 3 percent in 2008), and 

the application to soils of synthetic nitrogen-based 

fertilizer represents 26 percent of total N2O emissions from 

this source. 

EPA will continue to assess the need for a fertilizer 

reporting requirement from domestic producers in the future 

in light of new information or identification of policy or 

program needs. Further, EPA recognizes that States play an 

important role in collecting the data EPA currently uses, 

and the AAPFCO has indicated in a published article that 

recent stresses on state budgets potentially threaten the 

continued availability of these data.3 If data collection 

is compromised further due to reduced state funding or 

other circumstances, EPA will need to initiate a fertilizer 

reporting requirement.

EPA will also assess the need for information on the 

total supply of synthetic nitrogen-based fertilizer, 

including imports, production of fertilizer using imported 

 

3 D. Terry, 2006. "Fertilizer Tonnage Reporting in the U.S.— Basis and 

Current Need." Better Crops. 90(4). pp 14-17.
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feedstock, domestically-produced fertilizer that is not in 

the agriculture sector, and fertilizer exports. 

Additionally, EPA will also assess the need for other 

types of information (i.e., not related to fertilizer 

supply) relevant to determining emissions and assessing 

mitigation opportunities for N2O emissions from agricultural 

soils, consistent with the Clean Air Act. Examples of 

other types of information that is relevant to N2O oxide 

emissions from agricultural soils can be found in the 

“Technical Support Document for Biologic Process Sources 

Excluded from this Rule,” and include elements such as 

fertilizer application rates, timing of application, and 

the use of slow-release fertilizers and 

nitrification/urease inhibitors (Docket ID No. EPA-HQ-OAR2008-0508). 

If EPA were to decide in the future to add a 

requirement to report fertilizer production under the 

Mandatory GHG Reporting Rule, or any other new requirement 

related to N2O emissions from agricultural soils, it would 

initiate a new rulemaking process. 

K. Subpart P (Hydrogen Production)

We are proposing several conforming amendments to be 

consistent with the proposed amendments to the calibration 

requirements of 40 CFR 98.3(i). Section 98.164(b)(1) of 
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subpart P currently specifies that all oil and gas flow 

meters (except for gas billing meters), solids weighing 

equipment, and oil tank drop measurements must be 

calibrated according to 40 CFR 98.3(i). We are proposing 

to amend 40 CFR 98.164(b)(1) to make it consistent with 

today’s proposed amendments to 40 CFR 98.3(i). First, we 

would limit 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 

device that are used to provide data for the GHG emissions 

calculations would have to be calibrated 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 would remove 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) would apply only to gas and 

liquid flow meters. For oil tank drop measurements, the QA 

requirements of 40 CFR 98.34(b)(2) would apply. 

L. Subpart V (Nitric Acid Production)

We are proposing to amend 40 CFR 98.226 to remove the 

synthetic fertilizer and total nitrogen reporting 
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requirement in 40 CFR 98.226(o). The detailed rationale 

for this proposed amendment is provided in section II.K of 

this preamble.

M. Subpart X (Petrochemical Production) 

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 proposed 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.

Distillation and Recycling of Waste Solvent. We are 

proposing to add a new paragraph 40 CFR 98.240(g) to 

specify that a process that distills or recycles waste 
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solvent that contains a petrochemical is not part of the 

petrochemical production source category. Some processes 

that distill or recycle waste solvents may produce products 

that contain methanol or another petrochemical. Under the 

current subpart X, such processes might be considered part 

of the petrochemical source category because 40 CFR 

98.240(a) specifies that all processes that produce a 

petrochemical are part of the source category unless 

specifically excluded. Although not specifically excluded 

in subpart X, we did not intend to include waste solvent 

purification processes in the petrochemical source category 

for the following reasons. First, in processes subject to 

subpart X, the petrochemical is formed from other 

chemicals, whereas in waste solvent purification processes 

the petrochemical is not formed because it is present in 

the feedstock. Second, processes that are in the source 

category generate significant amounts of process-based GHG 

emissions as byproducts of reaction and/or from the 

combustion of process off-gas for energy recovery. In 

contrast, the only process-based GHG emissions, if any, 

from waste solvent purification processes are from 

combustion of organic compounds in process vent emissions 

that are routed to a combustion-based air pollution control 

device. 
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Process vent emissions monitored by CEMS. We are 

proposing to add a sentence 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). Section 98.242(a)(1) in 

the current subpart X specified that GHG emissions from 

stationary combustion sources and flares that burn any 

amount of petrochemical off-gas are to be reported under 

subpart X. However, we neglected to specify reporting 

requirements under the CEMS option for process emissions 

that are not associated with combustion units. The 

proposed amendment would correct this oversight.

Process off-gas combustion in flares. We are 

proposing to amend 40 CFR 98.242(b) by removing the 

reference to flares. Section 98.242(b) in subpart X 

specifies that CO2, CH4, and N2O combustion emissions from 

stationary combustion units and flares must be reported. 

However, the intent of 40 CFR 98.242(b) is to identify only 

the GHGs from the combustion of supplemental fuels that are 

to be reported under subpart C. Emissions from the 

combustion of petrochemical process off-gas in a flare are 

process-based emissions that are to be reported under 

subpart X as specified in 40 CFR 98.242(a). Therefore, the 
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reference to flares in 40 CFR 98.242(b) is incorrect and 

should be removed. 

CH4 and N2O Emissions From Combustion Of Process OffGas. We are proposing to amend 40 CFR 98.243(b) to clarify 

procedures for calculating CH4 and N2O emissions from 

combustion units that burn petrochemical process off-gas 

and are monitored with a CO2 CEMS. Section 98.243(b) in 

subpart X specifies that CH4 and N2O emissions from the nonflare combustion of petrochemical process off-gas are to be 

calculated using the Tier 3 procedures in subpart C, with 

the default emission factors for “Petroleum” in Table C-2 

of subpart C. This procedure requires the use of equation 

C-8 to calculate the emissions. One of the inputs for this 

equation is the default HHV of the fuel, and default values 

for various fuels are listed in Table C-1 of subpart C. As 

discussed in section II.H of this preamble, we have added a 

default HHV for fuel gas in Table C-1, and we have revised 

the definition of HHV for equation C-8 to allow the use of 

a site-specific calculated HHV as an alternative to using a 

default value from Table C-1. Using either a default HHV 

or a site-specific calculated value is also acceptable when 

calculating CH4 and N2O emissions from the combustion of 

fuel gas that contains petrochemical process off-gas. 

Therefore, to clarify this point, we are proposing to add 
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language to 40 CFR 98.243(b) specifying that either the 

default HHV for fuel gas in Table C-1 or a site-specific 

calculated HHV is to be used in equation C-8 when 

calculating CH4 and N2O emissions. 

For the ethylene-specific option, 40 CFR 98.243(d) in 

subpart X specifies the same procedures for calculating CH4

and N2O emissions from non-flare combustion of process offgas as in 40 CFR 98.243(b). Therefore, we are proposing 

the same change to 40 CFR 98.243(d) as noted above for 40 

CFR 98.243(b) to clarify that either the default HHV for 

fuel gas or a site-specific calculated HHV should be used 

for Tier 3 calculations. 

Molar volume conversion (MVC) factors. Owners and 

operators have requested that allowance be made for 

alternative standard conditions within the molar volume 

conversion factor (MVC) used in Equation X-1 in 40 CFR 

98.243(c). Equation X-1 of subpart X specified using an 

MVC of 849.5 scf/kgmole, which converts the volumetric flow 

from standard cubic feet to kgmoles assuming the standard 

volume was determined at 68oF. Exhaust stack volumes are 

generally corrected using 68oF as the standard temperature, 

and some petrochemical producers may also use 68oF when 

expressing process volumes at standard conditions. 

However, we recognize that the oil and gas industry and 
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other hydrocarbon processing facilities commonly express 

gaseous volumes using 60°F as the standard temperature. 

Thus, many existing flow monitors for gaseous feedstocks 

and products at petrochemical facilities may be programmed 

to output volumes at standard conditions of 60oF. It is 

impractical and unnecessary to either reprogram these 

monitors to provide volumes corrected to standard 

conditions at 68°F or to require reporters to convert the 

output volumes from one set of standard conditions to 

another before using Equation X-1 because an alternative 

MVC can be provided to yield the identical mass emissions 

from the calculation. 

Consequently, we are proposing to amend Equation X-1 

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 would be amended 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. 

Owners and operators have suggested that EPA should allow 

the use of alternative calculation methods for small

emission sources. Specifically, they have asserted that 
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units subject to only subpart C are allowed to use Tier 1 

or Tier 2 for units less than or equal to 250 mmbtu/hr heat 

input. However, if those same units are at a petrochemical 

production facility and combusting ethylene process offgas, they are required to use Tier 3 or Tier 4. 

We still believe that it is important to use Tier 3 or 

Tier 4 for most units that burn ethylene process off-gas 

because combustion of process off-gas is the primary source 

of GHG process emissions for ethylene processes, the carbon 

content may vary among facilities depending on the type of 

feedstock to the ethylene process units, and the ratio of 

ethylene process off-gas to other fuels may vary in each 

fuel gas system. 

However, we recognize that some ethylene process off 

gas that is burned in process heaters or boilers may not 

enter the fuel gas system and that the lines conveying 

these off-gas streams may not have flow monitors. For 

example, 40 CFR part 63, subpart YY, requires control of 

process vent emissions from ethylene production process 

units; these streams may be controlled by venting to a 

process heater or boiler, but subpart YY does not require 

monitoring of the vent stream flow rate. It was not our 

intent to require the installation of flow meters on these 

ancillary gas streams that do not significantly contribute 
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to the overall heat input of the stationary combustion 

unit. In addition, we recognize that facilities may only 

meter the primary fuel flow at relatively large combustion 

units that are subject to emission limitations that are 

related to the heat input rate. About one-third of the 

ethylene production capacity is at petroleum refineries, 

and much of the rest is at large integrated chemical 

manufacturing facilities. Based on an analysis of process 

heaters at petroleum refineries (see section II.O of this 

preamble), it appears that process heaters less than 30 

mmBtu/hr are often not subject to emission limitations and, 

therefore, may not have metered flow. Furthermore, such 

combustion units appear to represent only a small 

percentage of the total fuel use at refineries. Given the 

large size of most other chemical manufacturing facilities

that make ethylene, it is likely that such combustion units 

represent only a small percentage of total fuel use at 

these facilities as well. Thus, easing the Tier 3 

monitoring requirements for these small combustion units 

would reduce the compliance burden without significantly 

impacting the accuracy of the nationwide GHG emission 

inventories for ethylene production.

Notwithstanding the above discussion, if a flow meter 

is installed in the fuel gas line, including any common 
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pipe, then we consider that the Tier 3 monitoring 

requirements are reasonable and justified. In such cases 

there will not be a significant burden to use the Tier 3 

method, and the reported GHG emissions will be more 

accurate. 

Therefore, we are proposing to amend 40 CFR 98.243(d) 

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, we are proposing that Tier 1 or 

Tier 2 methods may be used for ethylene process off-gas 

streams that meet either of the following conditions:

(1) 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 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 an upstream common pipe; or 

(2) 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. 
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This amendment would also specify 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. 

We are also proposing a number of editorial changes to 40 

CFR 98.243(d) to clearly integrate the proposed option with 

the existing requirements. Finally, we are proposing to 

amend 40 CFR 98.246(c)(2) and 98.247(c) to add reporting 

and recordkeeping requirements that are related to the 

proposed amendments in 40 CFR 98.243(d)(2).

Monitoring Methods for Determining Carbon Content and 

Composition. Owners and operators have suggested that EPA 

should not limit the use of gas chromatograph methods for 

determining the carbon content, composition, and the 

average molecular weight of feedstocks and products to 

those methods listed in 40 CFR 98.244(b)(4). We are 

proposing to add the method, “ASTM D2593-93 (Reapproved 

2009) Standard Test Method for Butadiene Purity and 

Hydrocarbon Impurities by Gas Chromatography,” to 40 CFR 

98.244(b)(4). Butadiene is a by-product of the ethylene 

production process, and after reviewing the method, we have 

determined that it is an acceptable method for determining 

the carbon content of that stream. We will consider 

including additional methods in the final amendments after 
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reviewing comments on this issue. In order to evaluate 

this issue, we seek comments providing copies of 

calibration procedures that gas chromatograph manufacturers 

supply with their equipment, calibration procedures in any 

published or unpublished industry consensus (or sitespecific) methods not currently listed in 40 CFR 

98.244(b)(4), and an assessment of how such procedures 

compare to the currently specified methods and why they are 

applicable for instruments used to measure petrochemical 

feedstocks and products.

We are proposing to further amend 40 CFR 98.244(b)(4) 

by adding a new paragraph that would allow the use of 

industry consensus standard methods to determine the carbon 

content or composition of carbon black feedstock oils and 

carbon black products. Carbon black manufacturers have 

reported that none of the listed methods are specific to 

carbon black materials, and they have stated that such 

methods will provide less accurate results than modified 

versions of some of the methods. For example, the industry 

has reported that when they need to determine the carbon 

content of their feedstocks or products they often use 

modified versions of ASTM D5291-02. One difference is that 

the modified methods use carbon or carbon/sulfur analyzers 

instead of the carbon, hydrogen, and nitrogen analyzer that 
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is specified in ASTM D5291-02. These modified methods have 

been submitted to ASTM for review. If ASTM publishes 

methods before the proposed amendments are finalized, we 

will consider including them in the final amendments. The 

industry has also reported that they often use other 

published methods to determine the sulfur, ash, and water 

content of the material and then calculate the carbon 

content as the difference between the mass of these 

compounds and the total mass of the sample. This approach 

would also be allowed under the proposed change to 40 CFR 

98.244(b)(4). We seek comment on the need for the proposed 

option. In particular, we are interested in data that 

compare specified methods such as ASTM D5291-02 with 

industry consensus methods. We are also interested in 

obtaining copies of industry consensus standard methods.

We are also proposing to amend 40 CFR 98.244(b)(4) to 

provide facilities the option of, under certain 

circumstances, the use of alternative analytical methods in 

addition to the methods listed in 40 CFR 98.244(b)(4)(i) 

through (b)(4)(xi) for determining the carbon content or 

composition of feedstocks or products. We recognize that 

the applicability of the methods listed in 40 CFR 

98.244(b)(4)(i) through (b)(4)(xi) may be restricted for 

certain process streams due to the analytical limitations 
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of those methods and/or the instrumentation. As a result, 

we are proposing to allow a facility to use an alternative 

analytical method in cases where the methods listed in 40 

CFR 98.244(b)(4)(i) through (b)(4)(xi) 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. 

We are proposing to amend the reporting requirements 

in 40 CFR 98.246(a)(11) so that if an alternative method is 

used, facilities would include in the annual report the 

name or title of the method used, and the first time it is 

used, a copy of the method and an explanation of why the 

use of the alternative method is necessary. 

We solicit comment on whether the flexibility provided 

by this option is needed. If commenters believe that to be 

the case, please provide information on the specific need 

for flexibility, why the existing listed analytical methods 

are not sufficient, and whether the proposed flexibility 

meets the needs identified.

We are proposing to make the amendments to 40 CFR 

98.244(b)(4) as described above retroactive to January 1, 

2010. We have received feedback that some reporters are 

using a method currently allowed in Part 98 while 

concurrently also using a method that would be allowed by 
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today’s action. Should these amendments be finalized, 

making these amendments effective January 1, 2010 would 

allow reporters to use the results from the methods 

included in today’s amendments for the entire year of 2010.

QA/QC Requirements. As mentioned in Section II.B of 

this preamble, owners and operators have raised several 

issues regarding the calibration requirements in Part 98, 

and we are proposing a number of changes to 40 CFR 98.3(i) 

of subpart A to address those issues. To maintain 

consistency with the proposed amendments to 40 CFR 98.3(i), 

we are also proposing amendments to the QA/QC provisions 

for weighing devices, flow meters, and tank level 

measurement devices in paragraphs (b)(1), (b)(2), and 

(b)(3) of 40 CFR 98.244. Other proposed amendments to 

these paragraphs are editorial in nature and intended to 

clarify the requirements. Specific changes are as follows:

In 40 CFR 98.244(b), each of the three subparagraphs 

incorrectly required compliance with calibration 

requirements in 40 CFR 98.3(i), or with any of the 

following: procedures specified by equipment manufacturers, 

industry consensus standard procedures, or procedures in 

listed methods. We are proposing to amend these 

subparagraphs such that the procedures in 40 CFR 98.3(i) 

would apply in addition to the other required procedures.
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We are proposing to amend 40 CFR 98.244(b)(1) to allow 

recalibration at the interval specified by the industry 

consensus standard practice used in addition to either 

biennially or at the minimum frequency specified by the 

manufacturer. Note that the requirements of 40 CFR 98.3(i) 

for other measurement devices would apply as well. 

Section 98.244(b)(2) in subpart X specifies that flow 

meters are to be operated and maintained using the 

procedures in 40 CFR 98.3(i) and either any one of several 

listed methods, a method published by a consensus-based 

standards organization, or procedures specified by the flow 

meter manufacturer. Although 40 CFR 98.244(b)(2) 

references 40 CFR 98.3(i), it does not explicitly specify 

calibration requirements, and this reference incorrectly 

implies that 40 CFR 98.3(i) specifies procedures other than 

calibration requirements. In addition, the option to 

follow procedures in any of the listed methods is redundant 

because it overlaps with the option to use a method 

published by a consensus standards-based organization. To 

clarify these requirements we are proposing several 

amendments to 40 CFR 98.244(b)(2). One would specify that 

flow meters are to be operated and maintained according to 

manufacturer’s recommended procedures. A second would 

specify that flow meters are to be calibrated following 
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either an industry consensus standard practice or 

procedures specified by the flow meter manufacturer, and 

must meet the accuracy specification in 40 CFR 98.3(i). 

Finally, the list of specified methods would be deleted.

Section 98.244(b)(2) in subpart X specifies that flow 

meters are to be recalibrated either biennially or at the 

minimum frequency specified by the flow meter manufacturer. 

Since 40 CFR 98.244(b)(2) specifies that flow meters may be 

calibrated following procedures in industry consensus 

standard practices, we are proposing to also allow 

recalibration at the frequency specified in such methods. 

This would also make the recalibration requirements in 40 

CFR 98.244(b)(2) consistent with the proposed amendment in 

40 CFR 98.3(i)(1)(iii)(B). 

Section 98.244(b)(3) in subpart X specifies that tank 

level measurement devices are to be calibrated prior to the 

effective date of the rule. We are proposing to delete 

this statement because 40 CFR 98.3(i) specifies the date by 

which initial calibration must be completed. Note that the 

requirements for other measurement devices in 40 CFR 

98.3(i) apply as well.

Reporting Requirements Under The CEMS Compliance 

Option. We are proposing a number of changes in 40 CFR 
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98.246(b)(1) through (b)(5) to clarify the reporting 

requirements under the CEMS compliance option. 

First, we are proposing to move 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 proposing to add 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 proposed action) for CH4 and N20 do not 

apply under subpart X. This reporting requirement in 

subpart C is not relevant in subpart X because 40 CFR 

98.246(b)(5) specifies the reporting requirements for CH4

and N20 under subpart X. 

Third, in the renumbered 40 CFR 98.246(b)(3), we are 

proposing to delete 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 you still must 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 

proposing to amend the reference to 40 CFR 98.36(e)(2)(vii) 
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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 proposing changes to 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 would be unchanged. We are proposing 

changes to 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 would also include emissions 

from combustion of supplemental fuel (if any). 

Finally, we are proposing 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 proposed 

action). Most of the proposed amendments to 40 CFR 

98.246(b)(5) restate requirements from 40 CFR 

98.36(b)(9)(iii); for example, the proposed amendments 

clarify that emissions are to be reported in metric tons of 
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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, 40 CFR 98.246(b)(5) also would require you 

to estimate the fraction of total CH4 and N20 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) would require 

reporting of the HHV that you use in Equation C-8. This 

change also would delete the erroneous reference to 

Equation C-10 that was included in 40 CFR 98.246(b)(5).

Reporting Requirements For The Ethylene-Specific 

Option. We are proposing several changes to clarify the 

reporting requirements in 40 CFR 98.246(c) for the 

ethylene-specific option. First, we are proposing to add 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 proposing 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 
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for combustion units that are monitored with CEMS. Third, 

because ethylene is the only petrochemical product for 

process units that can comply with the ethylene-specific 

option, we are proposing to replace 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. In 40 CFR 

98.246(a)(7) we are proposing to delete the requirement for 

reporting of the dates and summarized results of 

calibrations of each measurement device under the mass 

balance option. We have determined that maintaining 

records of this information will be sufficient. Thus, we 

are also proposing to add 40 CFR 98.247(b)(4) to require 

retention of these records.

N. Subpart Y (Petroleum Refineries)

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 

proposed 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.
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• Calculating GHG emissions from fuel gas combustion.

• Calculating combustion GHG emissions from flares and 

thermal oxidizers.

• 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. 

• Reactor vessels using methane as a blanket or purge 

gas.

• Monitoring and QA/QC requirements.

• Reporting requirements.

GHG Emissions From Flares. We are proposing several 

corrections to 40 CFR 98.252(a) (GHGs to report) to clarify 

the required emissions methods for flares. From the first 

sentence in 40 CFR 98.252(a), it is clear that CO2, CH4, and 

N2O combustion emissions are to be calculated for stationary 

combustion units and for each flare. However, the second 

sentence suggests that petroleum refinery owners or 

operators are to “[c]alculate and report these emissions 

under subpart C...” (emphasis added). After the first 

sentence, the remainder of 40 CFR 98.252(a) specifically 

addresses how petroleum refinery owners or operators are to 

calculate and report stationary combustion unit emissions. 

Flare emissions are to be calculated using the methods 
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provided in subpart Y, not the methods provided in subpart 

C. Consequently, 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 reports must “Calculate and report the 

emissions from flares under this subpart.” 

GHG Emissions to Report From Combustion Of Fuel Gas. 

We are proposing to amend 40 CFR 98.252(a) to clarify that 

reporting of CH4 and N2O emissions is required for the 

stationary combustion units fired with fuel gas. It was 

always our intent that the emissions of these pollutants be 

reported for stationary combustion sources that used fuel 

gas. However, as no default factors for fuel gas were 

previously included in Table C-1 of subpart C, it could be 

interpreted that these emissions were not required to be 

reported, even though the first sentence clearly indicates 

that emissions of all three pollutants were to be reported 

for stationary combustion units and flares. While the 

proposed amendment to Table C-1 to include default factors 

for “fuel gas” is expected to correct this 

misinterpretation, we are also proposing to add the 

following sentence to 40 CFR 98.252(a) to clarify these 
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reporting requirements: “For CH4 and N2O emissions from 

combustion of fuel gas, use the applicable procedures in 40 

CFR 98.33(c) for the same tier methodology that was used 

for calculating CO2 emissions (use the default CH4 and N20 

emission factors for “Petroleum (All fuel types in Table C1)” in table C-2 of subpart C of this part and for Tier 3, 

either the default high heat value for fuel gas in Table C1 of subpart C of this part or a calculated HHV, as allowed 

in Equation C-8 of subpart C of this part.”. 

GHG Emissions To Report From Non-Merchant Hydrogen 

Production Process Units. We are also proposing to amend

40 CFR 98.252(i) to clarify that reporting of only CO2

emissions from non-merchant hydrogen production process 

units is required. The inclusion of “and CH4” emissions was 

an inadvertent error. We are also proposing to amend 40 

CFR 98.252(i) to clarify that catalytic reforming units 

(although they produce hydrogen as an important by-product) 

are not considered hydrogen production process units that 

are required to report under 40 CFR 98.252(i). 

Calculating GHG Emissions From Fuel Gas Combustion. 

Owners and operators have suggested that EPA should allow 

the use of alternative calculation methods for small

emission sources from the combustion of fuel gas. 

Specifically, they have asserted that units subject to only 
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subpart C may use Tier 1 or Tier 2 if the units are less 

than or equal to 250 mmbtu/hr heat input. However, if 

those same units are at a petroleum refinery and combusting 

fuel gas, they are required to use Tier 3 or Tier 4. We 

still believe that it is important to use Tier 3 or Tier 4 

for most units at a petroleum refinery because of the 

variability in carbon content in fuel gas (both between 

different refineries and at different times within the same 

refinery). However, we recognize that some flows of fuel 

gas to process heaters or boilers may not necessarily enter 

the refinery’s fuel gas system and that these fuel gas 

lines may not have flow monitors. For example, 40 CFR part 

63 subpart UUU requires the control of purging operations 

associated with the catalytic reforming unit. Among the 

control options for these emissions are provisions to vent 

these gases to a boiler or process heater. If the 

stationary combustion source has a design capacity of 44 MW 

or greater or if the gases are introduced into the flame 

zone of the unit, then direct monitoring of these gas 

streams is not required under subpart UUU. Similar 

provisions that may pertain to petroleum refineries are in 

other rules (e.g., 40 CFR part 60, subparts III and NNN; 40 

CFR part 63, subparts G and CC). It is not our intent to 

require direct flow monitoring of these ancillary gas 
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streams, particularly if they do not significantly 

contribute to the overall heat input of the stationary 

combustion unit. 

In addition, while we anticipate that most refineries 

can use a common-pipe monitoring approach for stationary 

combustion sources supplied by the refinery's fuel gas 

system(s), we recognize that some refineries may meter fuel 

usage at the stationary combustion sources and, in some 

cases, only meter fuel usage at the larger units. Based on 

a review of consent decrees and permits pertaining to 

process heaters, it appears that process heaters less than 

30 mmBtu/hr are often not subject to emission limitations, 

and therefore may not have metered flow. We performed an 

analysis of fuel use requirements by process unit. From 

this analysis, we project that more than 95 percent of 

nationwide fuel gas consumption at petroleum refineries 

would occur in process heaters with a rated heat capacity 

of 30 mmBtu/hr or greater. For additional detail on the 

consent decree review as well as the analysis of fuel use 

requirements, please see the Background Technical Support 

Document (EPA-HQ-OAR-2008-0508). While these small process 

heaters represent only a small percentage of the fuel use 

on a national level, most process heaters at petroleum 

refineries with capacities under 25,000 barrels per day 
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(which represents about 20 percent of the refineries, but 

only 2 percent of the refining capacity) are expected to 

have rated heat capacity of less than 30 mmBtu/hr. Thus, 

easing the Tier 3 monitoring requirements for these smaller 

process heaters would significantly ease the burden for 

small refineries without significantly impacting the 

accuracy of the nationwide GHG inventories for petroleum 

refineries. 

If 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. 

There will not be a significant burden to use the Tier 3 

method and the reported GHG emissions will be more accurate 

given the fluctuations expected in fuel gas compositions. 

Therefore, we are proposing to amend 40 CFR 98.252(a) 

so that petroleum refineries subject to subpart Y could use 

the Tier 1 or 2 methodologies for combustion of fuel gas 

when either of the following conditions exists:

(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 scfm at

60°F and 14.7 psia and either of the following conditions 

exist:
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• 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.

(2) The combustion unit has a maximum rated heat 

input capacity of less than 30 mmBtu/hr and either of the 

following conditions exist:

• 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.

These amendments, combined with the revisions to Table 

C-1 of subpart C, reflect our original intent to require 

Tier 3 or 4 monitoring and calculation methods for large 

fuel gas streams such as those anticipated in the 

refinery’s fuel gas system(s), but to allow Tier 1 or 2 

monitoring methods for smaller fuel gas streams that are 

segregated from the fuel gas system or for small combustion 

sources at refineries where flow monitors are installed at 

the majority of individual combustion sources, but not at 

the smaller combustion sources or the common pipe (i.e., 

fuel gas system). 
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Calculating Combustion GHG Emissions From Flares And 

Thermal Oxidizers. It has been brought to our attention 

that it is inappropriate to apply the 98 percent combustion 

efficiency to the carbon as CO2 that already exists in the 

gas stream in Equations Y-1 and Y-16 in 40 CFR 98.253. 

While the correction is expected to be minor in most cases, 

we agree that all of the CO2 that already exists in the gas 

stream will be emitted as CO2 from these sources. However, 

we are concerned that, depending on the method used to 

determine the carbon content, some facilities may not have 

collected the specific CO2 data needed to implement the 

revised equations. Therefore, we are proposing to amend 40 

CFR 98.253 by retaining the existing Equations Y-1 and Y16, re-numbering them as Equations Y-1a and Y-16a, and to 

add the more detailed equations that specifically consider 

the CO2 that already exists in the gas stream prior to the 

flare or thermal combustion device as Equations Y-1b and Y16b. Facilities that were required to or elected to use 

Equation Y-1 to report flare emissions would be able to 

choose to report these emissions using either Equation Y-1a 

or Y-1b, as proposed in today’s amendments. Similarly, we 

are proposing to allow facilities required to report CO2

emissions from asphalt blowing operations controlled by a 

thermal oxidizer or flare to use either Equation Y-16a or 
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Y-16b. We are proposing corresponding amendments in 40 CFR 

98.256 to require reporting of which equation was used and, 

if the new equations are used, reporting of the additional 

equation parameters.

We request comment on the need to retain the 

previously promulgated equations. As gas composition data 

are expected to be determined using gas chromatographic 

methods, the required CO2 data may already be collected. 

Thus, we are particularly interested to determine if there 

are facilities that cannot implement the new equations 

based on the measurement data already collected for these 

sources during the 2010 reporting year.

Molar volume conversion factors. Owners and operators 

have suggested that allowance be made for alternative 

“standard conditions” within the MVC factor used in several 

of the equations in 40 CFR 98.253. We recognize that 

natural gas and fuel gas volumes are commonly determined 

using 60°F as the standard temperature whereas exhaust 

stack volumes are commonly determined using 68°F as the 

standard temperature. Both of these volume measurements 

are specified in subpart Y. It is impractical and 

unnecessary for existing fuel gas monitors, most of which 

have been installed to correct volumes to standard 

conditions at 60°F, to be reprogrammed to output these 
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volumes corrected to standard conditions at 68°F when an 

alternative MVC can be provided to yield the identical mass 

emissions from the calculation. Consequently, we are 

proposing to amend equations Y-1, Y-3, Y-6, Y-12, Y-18, Y19, Y-20, and Y-23 in subpart Y to provide two alternative 

values of MVC depending on the standard conditions output 

by the flow monitors. Additionally, the reporting 

requirements related to each of these equations would be 

amended to include reporting of the value of MVC used to 

support the calculations and to afford verification of the 

reported emissions.

Combined Stacks Monitored By CEMS. We received 

several questions regarding whether or not discharges 

through a combined stack are allowable when CEMS are used, 

particularly for the catalytic cracking unit. We never 

intended to limit the use of combined stacks and CEMS at 

the refinery. In fact, we specifically attempted to 

address this issue in subpart Y with respect to the 

combined catalytic cracking unit and CO boiler emissions in 

40 CFR 98.253(c)(1)(ii). However, we have determined that 

the current language in 40 CFR 98.253(c)(1)(ii) may 

inadvertently be interpreted to exclude other CO2 emission 

sources that may be mixed with the catalytic cracking unit 

process (e.g., coke burn-off) emissions. 
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Consequently, we are proposing to amend the language 

in 40 CFR 98.253(c)(1)(ii) and also the reporting 

requirements in 40 CFR 98.256(f)(6) to generalize the 

language to include other CO2 emission sources, not just a 

CO boiler. The proposed amendments would clarify that when 

a CEMS is used to measure the CO2 emissions from the 

catalytic cracking unit and these emissions are combined 

with “other CO2 emissions,” the owner or operator must 

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), and determine the process 

emissions from the catalytic cracking unit (or fluid coking 

unit) as the difference in the CO2 CEMS measurements and the 

calculated emissions associated with the “other CO2

emissions.” 

Nitrogen Concentration Monitoring To Determine Exhaust 

Gas Flow Rate. We also received questions regarding the 

use of nitrogen (N2) concentration monitoring for Equation 

Y-7 in 40 CFR 98.253(c)(2)(ii). Equation Y-7 uses an inert 

balance to calculate the exhaust gas flow rate, and a 

similar calculation can be performed using a nitrogen 

balance. We agree that the nitrogen monitoring approach 

would provide an equivalent measure of the exhaust gas flow 

rate as Equation Y-7. We promulgated Equation Y-7 because 
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we anticipated several facilities used this monitoring 

approach as this equation is provided in the 40 CFR part 63 

subpart UUU (see Equation 2 of 40 CFR 63.1573). However, 

we note that 40 CFR 63.1573 also allows facilities to 

request alternative monitoring methods. There are no 

similar provisions in subpart A or subpart Y of part 98, so 

this monitoring alternative could not be used without 

amending the rule. As we find the N2 concentration 

monitoring approach to be equivalent to Equation Y-7, we 

are proposing to amend 40 CFR 98.253(c)(2)(ii) to renumber 

Equation Y-7 as Equation Y-7a and adding an Equation Y-7b 

to provide this N2 concentration monitoring approach. We 

are also proposing to add reporting requirements in 40 CFR 

98.256(f) to report the input parameters for Equation Y-7b 

if it is used.

Calculating CO2 Emissions from Catalytic Reforming 

Units. We are proposing to revise the definition of the 

coke burn-off quantity, CBQ, the term “n” in Equation Y-11 

in 40 CFR 98.253(e)(3) to clarify the application of 

Equation Y-11 to continuously regenerated catalytic 

reforming units. Continuously regenerated catalytic 

reforming units do not have specific cycles, so the 

reference to “regeneration cycle” in the definition of 

these terms was ambiguous or meaningless for continuously
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regenerated catalytic reforming units. We are proposing to 

replace the phrase “regeneration cycle” with “regeneration 

cycle or measurement period” in the definition of the coke 

burn-off quantity and to revise the definition of “n” to be 

the “Number of regeneration cycles or measurement periods 

in the calendar year.” A measurement period may be a day, 

week, month, or other time interval over which process 

measurements are made on the unit by which the coke burnoff rate is determined. We are similarly proposing to 

clarify 40 CFR 98.256(f)(13) (formerly designated 40 CFR 

98.256(f)(12)) to require reporting of “...the number of 

regeneration cycles or measurement periods during the 

reporting year, the average coke burn-off quantity per 

cycle or measurement period, and the average carbon content 

of the coke” when Equation Y-11 is used.

Calculating GHG Emissions From Sulfur Recovery Plants. 

With respect to requirements for sour gas sent off-site for 

sulfur recovery and for on-site sulfur recovery plants, we 

intended these requirements to be identical and that the 

petroleum refinery would report these emissions regardless 

of whether the sour gas feed is used at an on-site sulfur 

recovery plant within the refinery facility or the sour gas 

feed is sent to an off-site facility. However, we do note 

that the requirements were developed considering Claus 
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sulfur recovery plants and that the methods in 40 CFR 

98.253(f) may not be appropriate for all other types of 

sulfur recovery plants. To clarify the requirements for

sulfur recovery plants, we are proposing to amend 40 CFR 

98.253(f) 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 nonClaus sulfur recovery plants to alternatively follow the 

requirements in 40 CFR 98.253(j) for process vents. We 

also are proposing to amend the reporting requirements in 

40 CFR 98.256(h) to include the type of sulfur recovery 

plant and an indication of the method used to calculate CO2 

emissions as well as reporting requirements for non-Claus 

sulfur recovery plants that elect to follow the 

requirements in 40 CFR 98.253(j) for process vents. While 

we believe the calculation methodology needs no further 

regulatory text amendments, we do clarify in this preamble 

that the phrase “the sulfur recovery plant” in 40 CFR 

98.253(f) refers to either the on-site or off-site sulfur 

recovery plant, as applicable. We further clarify in this 

preamble that the sour gas flow and carbon content 

measurements for sour gas sent off-site for sulfur recovery 

may be made at either the refinery or the off-site sulfur 
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recovery plant provided these measurements are 

representative of the flow and carbon content of the sour 

gas sent off-site for sulfur recovery.

Calculating CO2 Emissions From Coke Calcining Units. 

We are proposing to amend the definition of Mdust (the mass 

of dust collected in the dust collection system) in 

Equation Y-13 in 40 CFR 98.253(g). It was brought to our 

attention that dust collected by the control systems may be 

recycled back to the coke calciner, raising the issue of 

how Mdust should be determined in this situation: is it the 

mass of dust collected in the dust collection system or is 

it the mass of dust that is discarded from the system? The 

mass balance represented by Equation Y-13 should be applied 

external to this recycle loop, so that Mdust is the quantity 

of dust removed from the overall process, which would be 

the mass of the dust collected in the control system minus 

the mass of dust recycled. We are, therefore, proposing to 

amend the definition of Mdust in Equation Y-13 to clarify 

this interpretation of Mdust when all or a portion of the 

collected dust is recycled back to the coke calciner. We 

also are proposing to amend 40 CFR 98.256(i)(5) to require 

facilities that use Equation Y-13 to indicate whether or 

not the collected dust is recycled to the coke calciner. 
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Calculating CO2 Emissions From Process Vents. We are 

proposing to amend the process vent requirements in 40 CFR 

98.253(j) due to 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). This amendment 

clarifies that the emissions from the sources that elect to 

use the process vent method in 40 CFR 98.253(j), must use 

Equation Y-19 to calculate the emissions for the pollutants 

required to be reported under the cross-referencing 

section, regardless of whether the concentration thresholds 

in 40 CFR 98.253(j) are exceeded. We are also proposing to 

amend the definition of Equation Y-19’s parameters of VR 

(the volumetric flow rate) and MFx (the mole fraction of the 

GHG in the vent). For these parameters we are proposing to 

clarify that these values are to be determined “from 

measurement data, process knowledge, or engineering 

estimates.” We are also proposing to amend the reporting 

requirements for process vents to clarify that the 

requirements apply to each process vent as well as to 

provide an indication of the measurement of estimation 

method.

Finally, we are proposing to amend 40 CFR 98.253(n) to 

delete the words “equilibrium” and “product-specific” to 
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clarify that the true vapor phase of the loading operation 

system should be used when determining whether the vaporphase concentration of methane is 0.5 volume percent or 

more. We affirm that process knowledge may be used to 

determine which loading operations have a vapor-phase 

concentration of methane of 0.5 volume percent, but this 

determination must be made considering both the material 

being loaded and the conditions of the loading operations. 

Equilibrium vapor-phase concentrations can be used as 

process knowledge to determine if the concentration of 

methane is 0.5 volume percent or more. 

Monitoring and QA/QC Requirements. In subpart Y, 40 

CFR 98.254 currently specifies QA/QC requirements for fuel 

flow meters, gas composition monitors, and heating value 

monitors that provide data for the GHG emissions 

calculations. A distinction is made in paragraphs (a) and 

(b) between measurement devices associated with stationary 

combustion sources, which are required to follow the QA/QC 

procedures in 40 CFR 98.34, and devices associated with 

other GHG emissions sources at the refinery, which are to 

be quality-assured according to 40 CFR 98.254(c) through 

(e). Paragraphs (f), (g), and (h) of 40 CFR 98.254 QA/QC 

requirements for: 
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• Stack gas flow rate monitors that are used to comply 

with the requirements of 40 CFR 98.253(c)(2)(ii); 

• CO2/CO/O2 composition monitors used to comply with 40 

CFR 98.253(c)(2); and 

• Weighing devices that are used to measure the mass of 

petroleum coke when CO2 emissions from a coke calcining 

unit are calculated using Equation Y-13. 

In subpart Y, 40 CFR 98.254(l) provides QA/QC 

requirements for CO2 CEMS and flow monitors used for direct 

measurement of CO2 emissions following the Tier 4 

methodology in subpart C. 

We are proposing to amend 40 CFR 98.254(a) through 

(h), and (l) as follows, to make them consistent with 

today’s proposed revisions to 40 CFR 98.3(i), and to make 

some necessary technical corrections and clarifications: 

Paragraph (a) of 40 CFR 98.254 would be amended to 

also include the phrase “sources that use a CEMS to measure 

CO2 emissions according to subpart C of this part...” to 

further separate these sources from those that are covered 

by 40 CFR 98.254(b). Although the CEMS monitoring 

requirements are specified in 40 CFR 98.254(l), these 

requirements are more clearly specified by the proposed 

amendments to 40 CFR 98.254(a) so that all sources required 

to meet the methods provided in subpart C are identified in 

a single paragraph. We also are proposing to re-word the 

phrase “follow the monitoring and QA/QC requirements in 40 

CFR 98.34” with “meet the applicable monitoring and QA/QC 
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requirements in 40 CFR 98.34” to clarify that the monitors 

must meet the requirements for the specific Tier for which 

monitoring was required (Tier 3 sources would comply with 

the Tier 3 requirements; Tier 4 sources would 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) would be included in 

the amended paragraph 40 CFR 98.254(a), we are proposing to 

delete 40 CFR 98.254(l). 

Paragraph (b) of 40 CFR 98.254 would be 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 would correct 

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 would also clarify that the calibration 

requirements in 40 CFR 98.3(i) only apply to gas flow 

meters and to allow 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 would also be amended to 

clarify that gas composition and heating value monitors 
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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 would be 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 would be removed from 40 CFR 

98.254(c), because the accuracy requirement for these flow 

meters is stated in the general provisions at 40 CFR 

98.3(i) and is referenced in 40 CFR 98.254(b). We are also 

proposing to amend 40 CFR 98.254(c) by removing the list of 

methods as this is redundant with the existing phrase, “a 

method published by a consensus-based standards 

organization.” 

Paragraphs (d) and (e) of 40 CFR 98.254 would be 

amended to allow the use of any chromatographic analysis to 

determine flare gas composition and high heat value, as an 

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; and the methods used for operation, 
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maintenance, and calibration of the GC are documented in 

the written monitoring plan for the unit under 40 CFR 

98.3(g)(5). Paragraph (d) in 40 CFR 98.254 would also be 

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. This is needed to address gas 

composition monitors that may already be in place on 

process vents subject to reporting under 40 CFR 98.253(j), 

so that these monitors can use alternatives to the methods 

in 40 CFR 98.254(d).

We are also proposing to amend 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 

proposing to add an additional method (ASTM D2503-92) to 

this section for determining average molecular weight.

Methods for determining average molecular weight were 

inadvertently omitted from this section.

We are proposing a number of amendments to 40 CFR 

98.254(f). First, the applicability of this paragraph 

would be expanded to include all gas flow meters on process 

vents subject to reporting under 40 CFR 98.253(j). The 

term “exhaust gas flow meter” would be replaced with the 

term “gas flow meter,” because not all process vents that 
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would report under 40 CFR 98.253(j) are combustion 

(“exhaust”) related gas streams.

Subpart Y currently allows an option to follow 40 CFR 

63.1572(c) (in the NESHAP for Petroleum Refineries) for 

installation, operation, and calibration of the stack gas 

flow rate monitor or the requirements in 40 CFR 

98.254(f)(1) through (f)(4). In our review of these 

requirements, we found that 40 CFR 98.254(f)(1) and (f)(3) 

were important requirements that were not delineated in 40 

CFR 63.1572(c). However, 40 CFR 98.254(f)(2) is not 

appropriate (accuracy requirements for these flow meters 

are already provided in the general provisions in 40 CFR 

98.3(i) and are referenced in 40 CFR 98.254(b)), and 40 CFR 

98.254(f)(4) is duplicative of the requirements in 40 CFR 

63.1572(c). 

We are proposing to retain portions of 40 CFR 

98.254(f)(1) and (3), but only as general, supplementary 

guidelines for flow monitor installation and operation. 

Thus, we are proposing that these stack flow monitors must: 

• 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 
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• 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 proposing to make a technical correction to 40 

CFR 98.254(g). Subpart Y currently requires the CO2/CO/O2

composition monitors that are used to comply with the 

requirements of 40 CFR 98.253(c)(2) be installed, operated, 

maintained, and calibrated according to either 40 CFR 

60.105a(b)(2) (in the NSPS for Petroleum Refineries) or 40 

CFR 63.1572(a), or according to the manufacturer’s 

specifications and requirements. The reference to 40 CFR 

63.1572(a) was in error and should be 40 CFR 63.1572(c). 

In the NESHAP for Petroleum Refineries (40 CFR part 63 

subpart UUU), these monitors are used to calculate coke 

burn-off rates, which are monitored to ensure the control 

device is operated within specified limits. Thus, these 

monitors are subject to 40 CFR 63.1572(c) within the NESHAP 

for Petroleum Refineries, and this is the level of QA that 

these monitoring systems are expected to be currently 

following. We note that CO2 monitors that are certified and 

calibrated as CEMS (with the appropriate flow monitoring 

system) would be subject to the requirements in 40 CFR 

98.253(c)(1), not 40 CFR 98.253(c)(2). Consequently, we 

specifically refer to the monitors within this 40 CFR 
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98.254(g) as “CO2/CO/O2 composition monitors” rather than 

CEMS to avoid confusion that these monitors must be 

operated according to CEMS requirements. In developing 

Part 98, we required CO2/CO/O2 composition monitors for 

catalytic cracking units and fluid coking units with rated 

capacities greater than 10,000 barrels per stream day 

because these monitors were expected to be in-place to 

comply with the NESHAP for Petroleum Refineries. We did 

not include additional costs to upgrade the existing 

CO2/CO/O2 composition monitors in our impact analysis 

because we intended to use the same monitoring requirements 

as in the NESHAP for Petroleum Refineries. Therefore, we 

are proposing to amend 40 CFR 98.254(g) to refer to 40 CFR 

63.1572(c), rather than 63.1572(a), for these O2/CO/O2

composition monitors.

Paragraph (h) of 40 CFR 98.254 specifies calibration 

procedures for weighing devices that are used to determine 

the mass of petroleum coke fed to the coke calcining unit, 

as required by Equation Y-13. Subpart Y currently provides 

three calibration options: (1) follow the procedures in 

NIST Handbook 44; (2) follow the manufacturer’s recommended 

procedures; or (3) follow the procedures in 40 CFR 98.3(i). 

We are proposing to amend 40 CFR 98.254(h) to require 

calibration according to the procedures specified by NIST 
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Handbook 44 or the procedures specified by the 

manufacturer. Note that the requirements of 40 CFR 98.3(i) 

for other measurement devices would apply as well. 

Reporting Requirements. This section covers reporting 

requirements that have not been described in previous 

sections of this preamble. 

We are proposing to amend the reporting requirements 

for Equation Y-1 (renumbered to Y-1a) and Y-2 to require 

reporting of whether daily or weekly measurement periods 

are used, for verification purposes.

In 40 CFR 98.256(f)(6), 40 CFR 98.256(h)(6), and 40 

CFR 98.256(i)(6), we are proposing to amend the references 

to 40 CFR 98.36(e)(2)(vi) to reference 40 CFR 98.36 more 

generally. This would make the references consistent with 

the associated requirements in 40 CFR 98.253.

In our review of the reporting requirements in 40 CFR 

98.256(f), we noted an inadvertent error in 40 CFR 

98.256(f)(10) and (11) [which would be redesignated 40 CFR 

98.256(f)(11) and (12) due to the proposed reporting 

requirement associated with Equation Y-7b]. In subpart Y, 

facility owners and operators are required to report 

information about unit-specific emission factors for CH4 and 

N2O, but not necessarily report the unit-specific emission 

factor itself. We are proposing to correct this 
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inadvertent error and require direct reporting of the unitspecific emission factor for CH4 and N2O, if used, in the 

newly designated 40 CFR 98.256(f)(11) and (12), 

respectively. 

We are proposing to amend 40 CFR 98.256(i)(8) to make 

it consistent with the information collected in 40 CFR 

98.245(i)(7). 

We are also proposing to amend 40 CFR 98.256(j)(2) to 

clarify that the reporting requirements for asphalt blowing 

apply at the unit level. 

We are also proposing to re-organize the reporting 

requirements in 40 CFR 98.256(o) to clarify, for example, 

that the reporting requirement in 40 CFR 98.256(o)(7) of 

Part 98 pertains specifically to tanks processing 

unstabilized crude oil. 

O. Subpart AA (Pulp and Paper Manufacturing)

We are proposing to amend subpart AA in response to 

questions EPA received since Part 98 was published on 

October 30, 2009. These amendments are intended to provide 

clarification and ensure consistency with other parts of 

the rule. 

EPA received questions regarding the methods specified 

in 40 CFR 98.273 to calculate fossil-fuel based CO2

emissions from chemical recovery furnaces, chemical 
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recovery combustion units, and pulp mill lime kilns. 

Specifically, clarification was requested as to whether an 

owner or operator can choose to use a tier other than Tier 

1 from 40 CFR 98.33 to calculate fossil-fuel based CO2

emissions. While it was our intent to provide this 

flexibility, the rule text indicated that only Tier 1 could 

be used. Therefore, we are proposing to amend 40 CFR 

98.273(a)(1), (b)(1) and (c)(1) to clarify that owners and 

operators may use a higher tier. This flexibility in 

selecting tiers is consistent with 40 CFR 98.34. The 

option to use a higher tier to calculate fossil-fuel based 

emissions provides flexibility to reporters and it only 

affects the reporting requirements if an owner or operator 

chooses to use a higher tier. EPA also received questions 

regarding the prescribed emission factors to calculate 

fossil-fuel based CO2 emissions from lime kilns. 

Specifically, 40 CFR 98.273(c)(1) directed owners and 

operators to use emission factors in Table AA-2 to 

calculate CO2 emissions from lime kilns, but EPA has 

received requests to use the emission factors provided in 

Table C-1. 

The emission factors in Table AA-2 were taken from 

“Calculation Tools for Estimating Greenhouse Gas Emissions 

from Pulp and Paper Mills”, Version 1.1, July 8, 2005, 
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which was prepared by the National Council for Air and 

Stream Improvement (NCASI) for the National Council of 

Forest and Paper Associations (ICFPA). Part 98 

incorporated these factors in Table AA-2 because they were 

developed specifically for pulp and paper lime kilns, which 

operate at different conditions than other general 

stationary combustion units. 

Upon further consideration, we have determined that 

the emission factors provided in Table AA-2 are uniquely 

suited for calculating CH4 and N2O emissions from lime kilns 

given these emissions are significantly influenced by the 

operating conditions. However, EPA has found that the same 

rationale does not support having unique emission factors 

to calculate CO2 emissions from lime kilns. Therefore, EPA 

has removed the CO2 emission factors from Table AA-2 and, in 

40 CFR 98.273(c)(1), has directed owners and operators to 

use the CO2 emission factors from Table C-1 of subpart C to 

calculate CO2 emissions from lime kilns. Modifications to 

Table AA-2 would affect the emissions reported in 2010, but 

would not affect the data that are collected to report 

emissions in 2010.

Related to the calculation of CH4 and N2O emissions 

described above, and consistent with the proposal to allow 

use of higher Tiers than Tier 1 for units subject to 
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subpart AA, EPA is proposing to allow reporters to also use 

site-specific high heating values, as opposed to default 

values, when claculating CH4 and N2O emissions. 

EPA has also received questions from owners and 

operators about whether pulp and paper mills are required 

to calculate emissions from the combustion of their 

wastewater treatment sludge. Specifically, they asked for 

clarification of whether this type of sludge was included 

in Table C-1 and, if not, should they account for emissions 

from the combustion of this material. In our efforts to 

address this question, we have not been able to identify 

emission factors developed specifically for sludge from a 

pulp and paper mill wastewater facility. However, our 

research indicates that the content of 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 proposing to add the definition of “Wood and 

Wood Residuals” to 40 CFR 98.6 and to include wastewater 

process sludge from paper mills in this definition. 

Clarifying that emissions from the combustion of sludge 

from pulp and paper mill wastewater treatment facilities 
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may be calculated using Tier 1 would require that owners 

and operators estimate the volume of sludge combusted using 

company records. Given the broad definition of company 

records, owners and operators should be able to develop 

estimates to report these emissions in 2011. Presuming 

these changes are finalized as proposed, they would be 

incorporated into annual GHG reports due in March 2011.

Finally, EPA received questions regarding which 

emission factors to apply when a pulp and paper mill 

combusts solid petroleum coke given this fuel type was not 

included in Table C-1 and Table AA-2. In response, we are 

proposing to add this fuel type to both tables. However, 

it is noted that emission factors for petroleum coke 

specific to kraft calciners were not available. EPA does 

not believe that any kraft calciners are combusting 

petroleum coke, so we have concluded that it is not 

necessary to have emission factors for this fuel in Table 

AA-2. EPA seeks comment on this conclusion. Further, if 

information is provided that petroleum coke is combusted at 

kraft calciners, please also include any information on 

default CH4 and N2O emission factors. 

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

Liquids) 
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Threshold for natural gas local distribution 

companies. The applicability provision in subpart A at 40 

CFR 98.2(a)(4)(iii)(B) requires all natural gas local 

distribution companies (LDCs), regardless of size, to 

report the GHG emissions that would result from the 

complete combustion or oxidation of the annual volumes of 

natural gas provided to end users on their distribution 

systems. Owners and operators of LDCs potentially subject 

to subpart NN have asserted that this provision results in 

an unfair burden on many small LDCs. 

They have stated that requiring all LDCs to report did 

not adequately balance rule coverage of GHGs reported, 

while excluding small entities. For example, they 

highlighted data from the Energy Information Administration 

that indicated that 82 percent of facilities are estimated 

to deliver less than 460,000 mscf per year of natural gas, 

which is equivalent to approximately 25,000 mtCO2e. They 

further noted that EPA’s own estimates suggest that these 

facilities would be responsible for less than 1 percent of 

the reported GHG emissions associated with LDC supply. The 

owners and operators concluded that this is a 

disproportionate burden for LDCs, particularly if one 

considers that across the rule, applying a 25,000 mtCO2e 

threshold would exclude approximately 10 to 15 percent of 
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GHG emissions, a much larger percentage of emissions than 

would be excluded under LDCs by applying that same 25,000 

mtCO2e threshold. 

The owners and operators noted that inclusion of all 

LDCs in the rule would also impose numerous reporting and 

recordkeeping requirements, even though most of these 

facilities would actually be eligible to stop reporting in 

three or five years, after they could prove to EPA that 

emissions from their supply were less than 15,000 mtCO2e or 

25,000 mtCO2e per year, respectively. 

We note that the threshold requirements for LDCs did

not change between the initial proposal in April 2009 and 

Part 98 promulgated on October 30, 2009. Further, EPA did 

not receive any comments opposed to the “all in” 

designation for LDCs during the public comment period on 

the proposed Part 98 and, in fact, received two comments 

supporting the lack of a threshold of any kind. Therefore, 

EPA retained in Part 98 the provision to require all LDCs 

to report the CO2 emissions associated with their supply. 

EPA retained the provision in order to maximize coverage of 

the GHG emissions from natural gas supplies, and also to be 

consistent with other suppliers of fossil fuels and 

industrial gases covered by Part 98. An “all in” threshold 

was applied to all of these supplier categories. 
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Although we believe that the public had ample 

opportunity to comment on the threshold for LDCs, we have 

reevaluated this issue in light of the information 

received. We are proposing to amend 40 CFR 

98.2(a)(4)(iii)(B) in subpart A to require all LDCs that 

deliver 460,000 mscf or more of natural gas per year to 

report. We are proposing this capacity-based threshold 

because a capacity-based threshold would be more familiar 

to LDCs. Owners and operators of LDCs know how much 

natural gas they deliver to their customers and it would, 

therefore, be easier for facilities to determine if they 

are subject to the rule than if the threshold were 

emissions-based. The proposed annual threshold is 

approximately equivalent to 25,000 mtCO2e. 

After further consideration, we have concluded that 

although a threshold would result in a loss of emissions 

information to EPA, the emissions coverage lost is less 

than 1 percent. It is also true that most of these 

facilities 460,000 mscf would be able to stop reporting to 

EPA in three or five years, raising the question of whether 

the burden associated with instituting a reporting program 

that includes the smaller facilities is necessary. We have 

determined that EPA and other stakeholders would be able to 

use data from external sources (e.g., the Energy 
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Information Administration) to estimate the less than 1 

percent of GHG emissions that would no longer be reported 

to EPA if a 460,000 mscf annual threshold were applied. 

This would minimize any concerns that the loss of emissions 

coverage would inhibit the use of the data for future 

policy making. Finally, we have concluded that LDCs are 

unique among suppliers in that a large majority of 

facilities would be under a 460,000 mscf threshold, and 

collectively these facilities are responsible for a 

relatively low percentage of emissions from the industry. 

Q. Subpart OO (Suppliers of Industrial Greenhouse Gases)

We are proposing several changes to subpart OO to (1) 

respond to concerns raised by producers of fluorinated GHGs 

regarding the scope of the monitoring and reporting 

requirements, and (2) 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 (1) 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, (2) are 

produced and transformed at the same facility, or (3) occur 

as low-concentration constituents (impurities) in 

fluorinated GHG products. The producers also requested 
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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 

under 40 CFR 98.416(c) and (d), which are expressed in CO2-

equivalents. 

Regarding fluorinated GHGs that are emitted or 

destroyed before the product is packaged for sale, the 

producers specifically requested that EPA amend subpart OO 

to remove the requirements of 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 40 CFR 98.413(a) because they are 

removed from the production process as byproducts or 

wastes. 

They noted that measuring the flow of such fluorinated 

GHGs into the destruction device to the precision required 

(1 percent) posed significant technical challenges and that 

such measurement was outside the scope of subpart OO. They 

further stated that subpart OO was intended to address the 

quantities of fluorinated GHGs exiting production units and 
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entering commerce, where commerce includes the packaging 

and marketing or import and export of fluorinated GHGs. 

They stated that the proposed subpart L was the more 

appropriate vehicle for the monitoring and reporting of 

emissions and destruction of fluorinated GHGs still within 

the production process. 

However, the producers noted that it was practical and 

appropriate under subpart OO to measure the quantities of 

fluorinated GHGs that are returned to the production 

facility for destruction after entering into commerce 

(e.g., because they have become irretrievably 

contaminated). 

Regarding fluorinated GHGs that are produced and 

transformed at the same facility, the fluorinated GHG 

producers noted that these fluorinated GHGs never enter the 

U.S. supply of fluorinated GHGs because they never leave 

the facility where they are produced. Thus, it is not 

necessary to track them under subpart OO.

Regarding fluorinated GHGs that occur as lowconcentration constituents of fluorinated GHG products, the 

producers observed that such low-concentration constituents 

generally consist of by-products that are packaged along 

with the main constituent of the product. They noted that 

exempting the production, import, and export of these low-
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concentration constituents from monitoring and reporting 

requirements would be consistent with the exemption of 

“trace” concentrations from other monitoring requirements 

in subpart OO, such as 40 CFR 98.414(f) and (h). 

In response to the concern regarding fluorinated GHGs 

that are emitted or destroyed before the product is 

packaged for sale, we are proposing (1) to modify 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);” (2) to remove 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 40 CFR 98.413(a) 

because they are removed from the production process as 

byproducts or wastes;” and (3) to modify the requirements 

at 40 CFR 98.414(h) and 98.416(a)(3) to limit them to “the 

mass of each fluorinated GHGs that is fed into the 

destruction device and that was previously produced as 

defined at §98.410(b).”

These proposed amendments would clarify that the scope 

of subpart OO is that which EPA has always intended, and 

they would modify the destruction monitoring and reporting 
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requirements to be fully consistent with that scope. As 

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. 

To clarify this in the regulatory text, we are proposing to 

amend the definition of “produce a fluorinated GHG” at 40 

CFR 98.410(b) to exclude the “creation of fluorinated GHGS 

that are released or destroyed at the production facility 

before the production measurement at §98.414(a).”

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). As noted above, emissions 

upstream of the production measurement would be subject to 

proposed subpart L and are not part of the subpart OO 

source category.
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We are also proposing to amend 40 CFR 98.416(a)(3) to 

limit the monitoring and reporting of destroyed fluorinated 

GHGs to those destroyed fluorinated GHGs that were 

previously “produced” under today’s revised definition.4 

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,5 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.

 

4 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.

5

 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.
192 of 392

In response to the concern regarding fluorinated GHGs 

that are produced and transformed at the same facility, we 

are proposing to (1) amend the definition of “produce a 

fluorinated GHG” to exclude “the creation of intermediates 

that are created and transformed in a single process with 

no storage of the intermediates;” (2) amend the definition 

of “produce a fluorinated GHG” 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;” (3) add a definition of “isolated intermediate;” 

and (4) add 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 

proposing to exclude the latter from the definition of 
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“produce a fluorinated GHG,” we are proposing to include 

the former in that definition. This is because the 

manufacture of isolated intermediates, which can lead to 

emissions of those intermediates, is of interest under 

subpart L, and we would like 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 proposing to add 

provisions to exclude it from the subpart OO monitoring, 

reporting, and recordkeeping requirements. We are also 

proposing to add a definition of “isolated intermediate” 

that is the same as that proposed for subpart L (75 FR 

18652, April 12, 2010). 

In response to the concern regarding fluorinated GHGs 

that occur as low-concentration constituents of fluorinated 

GHG products, we are proposing to define and exclude lowconcentration constituents from the monitoring, reporting, 

and recordkeeping requirements for fluorinated GHG 

production, exports, and imports. For purposes of 

production and export, we are proposing to define lowconcentration constituent as a fluorinated GHG constituent 

of a fluorinated GHG product that occurs in the product in 
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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 

refrigerants (AHRI 700), for SF6 used as an insulator in 

electrical equipment (IEC 60376), and for perfluorocarbons 

and other fluorinated GHGs used in electronics 

manufacturing (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 low-concentration constituent occurs in 

concentrations of just under 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 under 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 
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GHG constituent of a product, we are also proposing product 

sampling and analytical requirements at 40 CFR 98.414(n) 

and corresponding calibration requirements at 40 CFR 

98.414(o).

For purposes of fluorinated GHG import, we are 

proposing to define low-concentration constituent 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 proposing 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 proposing 

(1) to exempt such compounds from the general subpart A 

requirement to report supply flows in terms of CO2

equivalents and (2) to recast the reporting exemptions for 

import and export of small shipments in terms of kilograms 

of fluorinated GHGs or N2O rather than tons of CO2-

equivalents. The amendment to subpart A is discussed in 

more detail in section II.G of this preamble. The 

exemptions for import and export would be applied to 
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shipments of less than 25 kilograms of fluorinated GHGs or 

N2O rather than to shipments of less than 250 metric tons of 

CO2e. This would enable small shipments of fluorinated GHGs 

to be exempt from reporting regardless of whether or not 

the fluorinated GHG had a GWP listed in Table A-1. Our 

analysis of import and export data indicates that this 

change would slightly increase both the number and total 

mass of the imports and exports reported under the rule, 

but this analysis does not account for fluorinated GHGs 

whose GWPs are not listed in Table A-1. If those 

fluorinated GHGs were accounted for, we believe that the 

level of reporting would increase even less and might even 

decrease slightly.

Other Corrections. We are also proposing to amend the 

reporting and recordkeeping provisions in subpart OO to 

correct internal inconsistencies in the subpart and to 

clarify those requirements. 

We are proposing to amend 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. 
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We are proposing to amend 40 CFR 98.416(b) and (e) to 

clarify the due dates of the one-time reports required by 

those paragraphs. The proposed 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 April 1, 

2011, and there was no provision for commencing fluorinated 

GHG destruction or production after that date. The 

proposed amendments will make the due dates in 40 CFR 

98.416(b) and (e) consistent with each other, with the due 

date for a similar report required in subpart O, and with 

the due date for other reporting under the rule.

We are proposing to amend 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 proposing to amend 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 proposing to amend 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.” 
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R. Subpart PP (Suppliers of Carbon Dioxide)

In subpart PP, we are proposing to remove the words 

“each” from the list of GHGs to report in 40 CFR 98.422.

This change would align this section with the requirements 

of the rest of subpart PP, which allow for monitoring of an 

aggregated flow of CO2 if it is done at a gathering point 

downstream of individual production wells or production 

process units. 

We are proposing to allow those suppliers that supply 

CO2 in containers 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. As a result of many questions

received during outreach in support of alternative 

procedures for CO2 supplied in containers, we have 

reevaluated the calculation procedures for CO2 suppliers. 

We have concluded that measurements made with weigh bills, 

scales, load cells, or loaded container volume readings 

will continue to meet the level of data quality and 

accuracy needed by EPA with respect to subpart PP. We have 

reached this conclusion with consideration to minimizing 

the burden on and maximizing the flexibility provided to 

industry.
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We are proposing multiple amendments to the regulatory 

text to accommodate this proposed provision. First, we are 

proposing that 40 CFR 98.423(b) be renumbered to 40 CFR 

98.423(c) and that a new 40 CFR 98.423(b) be added with 

calculation procedures for CO2 supplied in containers. 

Second, we are proposing to amend the first sentence of 40 

CFR 98.423(a) to allow suppliers that supply CO2 in 

containers to use the alternative procedures in 40 CFR 

98.423(b). Third, we are proposing to add new QA/QC 

procedures for suppliers that supply CO2 in containers to 40 

CFR 98.424(a). Fourth, we are proposing to add missing 

data procedures for suppliers that supply CO2 in containers 

to 40 CFR 98.425(d). Finally, we are proposing to make 

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 note that under the existing requirements, 

importers and exporters that import and export CO2 in 

containers must measure the mass of CO2 in containers using 

weigh bills, scales, or load cells. In this action, we are 

not proposing that the use of loaded container volume 

readings be allowed for such reporters as an alternative to 

weigh bills, scales, or load cells because we have received 
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no questions from importers or exporters suggesting the 

need for such an allowance. We seek comment on whether 

such an allowance should be extended to importers and 

exporters of CO2 in containers, and if so whether the 

calculation procedures, QA/QC procedures, missing data 

procedures, and reporting requirements for loaded container 

volume readings proposed in this action for suppliers 

should be offered to importers and exporters.

We are proposing to remove 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 proposing to redesignate as 40 CFR 

98.423(c)). This provision created confusion and conflict 

over where to place a flow meter. For example, at least 

one reporter has indicated that only a portion of a CO2

stream is transferred for commercial application while the 

rest is retained for onsite use and emission, and this 

portion of the stream is segregated only after processing. 

As a result of this and other concerns that the requirement 

to install flow meters prior to purification, processing,

or compression could result in a requirement to install the 

flow meter at a technically infeasible point, we 

reevaluated the value of such a constraint on the CO2

calculations. Since the purpose of subpart PP is to 
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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 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 proposing to add language at 40 CFR 

98.424(a) requiring the flow meter to be located after the 

point of segregation. We are also proposing to amend 

existing language in 40 CFR 98.424(a) to reference this new 

requirement.

Because the proposed amendments would allow flow 

meters to be located after purification, compression, or 

processing, we are proposing to add data reporting 

requirements in 40 CFR 98.426 to collect additional 

information on flow meter location. Specifically, we are 

proposing that facilities would report information on the 

placement of each flow meter used in relation to the points 

of CO2 stream capture, deyhdration, compression, and other 

processing. Knowing where in the production process the 
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flow meter is located will enable EPA to effectively 

compare data across and to learn about the efficacy of 

various CO2 stream capture processes.

The current subpart PP regulatory text requires that a 

reporter using a volumetric flow meter to measure the flow 

of a CO2 stream measure density of that CO2 stream in order 

to calculate the mass of CO2 supplied. As a result of new 

analysis, we have concluded that the mass of CO2 in a stream 

can be adequately determined by converting the volumetric 

flow of CO2 from operating conditions to standard conditions 

and then applying the density value for CO2 at standard 

conditions and the measured concentration of CO2 in the 

flow. This approach may also be less burdensome for 

reporters than directly measuring density with equipment. 

Therefore, we are is proposing to amend 40 CFR 98.424(a)(5) 

by replacing the word “measure” with the word “determine.” 

We are also proposing to add a new paragraph 40 CFR 

98.424(c) so that suppliers will be able to calculate the 

mass of CO2 in a stream from the measured volumetric flow 

(converted to standard conditions) and CO2 concentration, 

and the given density of CO2 at standard conditions.

For the calculation in the proposed paragraph 40 CFR 

98.424(c), standard conditions under subpart PP would be a 

temperature and an absolute pressure of 60°F and 1 
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atmosphere. Note that this would be different than the 

standard conditions defined in subpart A (40 CFR 98.6), 

which are 68°F and 14.7 psia. 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, and we seek comment on this conclusion. Given these 

conditions, we are proposing that reporters must use 

0.0018704 metric tons per standard cubic meter as a density 

value for CO2 at standard conditions if this is the industry 

standard practice used to determine density.

The current subpart PP regulatory text also requires 

that an appropriate method published by a consensus-based 

standards organization be used to measure density if such a 

method exists. Where no such method exists, an industry 

standard practice must be followed. We have been unable to 

identify any method published by a consensus-based 

standards organization that accounts for the approach for 

determining density described above and have concluded that 

it would be categorized as an industry standard practice. 

Therefore, we are proposing to amend language in 40 CFR 

98.424(a)(5) and (a)(5)(ii) to allow reporters to choose 

equally from between a method published by a consensusbased standards organization that is appropriate or an 

industry standard practice to determine density.
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We are proposing to amend 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.

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 (EO)12866 (58 FR 51735, 

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

under the EO. 

B. Paperwork Reduction Act 

This action does not impose any new information 

collection burden. These proposed amendments do not make 

any substantive changes to the reporting requirements in 

any of the subparts for which amendments are being 

proposed. In many cases, the proposed amendments to the 

reporting requirements could potentially reduce the 

reporting burden by making the reporting requirements 

conform more closely to current industry practices. The 

Office of Management and Budget (OMB) has previously 

approved the information collection requirements contained 

in the regulations promulgated on October 30, 2009, under 

40 CFR Part 98 under the provisions of the Paperwork 
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Reduction Act, 44 U.S.C. 3501 et seq. and has assigned OMB 

control number 2060-0629. The OMB control numbers for 

EPA’s regulations in 40 CFR are listed in 40 CFR part 9. 

Further information on EPA’s assessment on the impact on 

burden can be found in the Revisions Cost Memo (EPA-HQ-OAR2008-0508). 

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 this proposed 

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

small business as defined by the Small Business 

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

governmental jurisdiction that is a government of a city, 

county, town, school district or special district with a 

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

organization that is any not-for-profit enterprise which is 
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independently owned and operated and is not dominant in its 

field.

After considering the economic impacts of these 

proposed rule amendments on small entities, I certify that 

this action will not have a significant economic impact on 

a substantial number of small entities. The proposed rule 

amendments will not impose any new requirement on small 

entities that are not currently required by the rules 

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

reporting annual GHG emissions). 

EPA took several steps to reduce the impact of Part 98 

on small entities. For example, EPA determined appropriate 

thresholds that reduced the number of small businesses 

reporting. In addition, EPA did not require facilities to 

install CEMS if they did not already have them. Facilities 

without CEMS can calculate emissions using readily 

available data or data that are less expensive to collect 

such as process data or material consumption data. For some 

source categories, EPA developed tiered methods that are 

simpler and less burdensome. Also, EPA required annual 

instead of more frequent reporting. Finally, EPA continues 

to conduct significant outreach on the mandatory GHG 

reporting rule and maintains an “open door” policy for 
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stakeholders to help inform EPA’s understanding of key 

issues for the industries.

We continue to be interested in the potential impacts 

of the proposed rule amendments on small entities and 

welcome comments on issues related to such impacts.

D. Unfunded Mandates Reform Act (UMRA)

This proposed rule does not contain a Federal mandate 

that may result in expenditures of $100 million or more for 

State, local, and tribal governments, in the aggregate, or 

the private sector in any one year. EPA has estimated 

that, overall, the proposed revisions do not significantly 

change the overall costs of compliance with Part 98. The 

proposed amendments include providing additional 

flexibility for reporters, clarifying existing reporting 

requirements, and requiring reporting of information 

already required to be collected under Part 98. EPA 

estimates that the cost for all reporters in reviewing the 

proposed rule and determining if, and if so how, it applies 

to their facility, is approximately $2.5 million in the 

first year. Considering the additional flexibilities 

proposed, in sum, EPA has estimated that the proposed rule, 

if finalized, would reduce the burden to reporters as 

compared to the 2009 final rule. Thus, this rule is not 

subject to the requirements of sections 202 or 205 of UMRA. 
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For more information on the cost analysis, please refer to 

the memorandum titled “Mandatory Greenhouse Gas Reporting:

Changes in National Cost Estimates Associated with the 

Proposed Notice of Revisions” found in the docket at (EPAHQ-OAR-2008-0508). 

This proposed rule is also not subject to the 

requirements of section 203 of UMRA because it contains no 

regulatory requirements that might significantly or 

uniquely affect small governments. EPA determined that the 

proposed rule amendments contain no regulatory requirements 

that might significantly or uniquely affect small 

governments because the amendments will not impose any new 

requirements that are not currently required by the rules 

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

reporting annual GHG emissions). EPA concluded in the 

preamble to that final rule that the rule “...contains no 

regulatory requrements that might significantly or uniquely 

affect small governments” (40 CFR 56260). Because the 

final rule was not determined to significantly or uniquely 

affect small governments, and because this proposed rule 

generally reduces the burden associated with the 2009 final 

rule, these rule amendments would not unfairly apply to 

small governments. 

E. Executive Order 13132: Federalism
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This action does not have federalism implications. It 

will not have substantial direct effects on the States, on 

the relationship between the national government and the 

States, or on the distribution of power and 

responsibilities among the various levels of government, as 

specified in Executive Order 13132. However, for a more 

detailed discussion about how these proposed rule 

amendments would relate to existing State programs, please 

see Section II of the proposal preamble for Part 98 (74 FR 

16457 to 16461, April 10, 2009).

These amendments apply directly to facilities that 

supply fuel or chemicals 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 large stationary combustion source), so relatively few 

government facilities would be affected. This regulation 

also does not limit the power of States or localities to 

collect GHG data and/or regulate GHG emissions. Thus, EO 

13132 does not apply to this action.

Although section 6 of Executive Order 13132 does not 

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

officials or representatives of State and local governments 
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in developing Part 98. A summary of EPA’s consultations 

with State and local governments is provided in Section 

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

October 30, 2009).

In the spirit of Executive Order 13132, and consistent 

with EPA policy to promote communications between EPA and 

State and local governments, EPA specifically solicits 

comment on this proposed action from State and local 

officials. 

F. Executive Order 13175: Consultation and Coordination 

with Indian Tribal Governments

This action does not have tribal implications, as 

specified in Executive Order 13175 (65 FR 67249, November 

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

any changes to the requirements of the 2009 rule. 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 Part 98 (74 FR 56260, October 30, 2009).
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G. Executive Order 13045: Protection of Children from 

Environmental Health Risks and Safety Risks

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

1997) as applying only to those regulatory actions that 

concern health or safety risks, such that the analysis 

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

influence the regulation. This action is not subject to EO 

13045 because it does not establish an environmental 

standard intended to mitigate health or safety risks.

H. Executive Order 13211: Actions that Significantly 

Affect Energy Supply, Distribution, or Use

This action is not subject to Executive Order 13211 

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

significant regulatory action under Executive Order 12866.

I. National Technology Transfer and Advancement Act

Section 12(d) of the National Technology Transfer and 

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

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

standards in its regulatory activities unless to do so 

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 
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bodies. NTTAA directs EPA to provide Congress, through 

OMB, explanations when the Agency decides not to use 

available and applicable voluntary consensus standards.

This proposed rulemaking involves technical standards. 

No new test methods were developed for this proposed rule;

rather, EPA identified existing means of monitoring, 

reporting, and keeping records of greenhouse gas emissions. 

EPA proposes to use two additional voluntary consensus 

standards from ASTM International. Part 98 includes the 

use of over 40 voluntary consensus standards from various 

consensus standards bodies, for example, ASTM 

International, the American Society of Chemical Engineers, 

Gas Processors Association, the American Gas Association, 

and the American Petroleum Institute. The proposed 

addition of these two voluntary consensus standards from 

ASTM International to Part 98 will help petroleum 

refineries and petrochemical facilities monitor, report, 

and keep records of greenhouse gas emissions. The test 

methods are incorporated by reference into the proposed 

rule and are available as specified in proposed amendments 

to 40 CFR 98.7. 

By incorporating voluntary consensus standards into 

this proposed rule, EPA is both meeting the requirements of 
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the NTTAA and presenting multiple options and flexibility 

for measuring greenhouse gas emissions. 

EPA welcomes comments on this aspect of the proposed 

rulemaking and, specifically, invites the public to 

identify potentially-applicable voluntary consensus 

standards and to explain why such standards should be used 

in this regulation. 

J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and LowIncome Populations

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

1994)) establishes federal executive policy on 

environmental justice. Its main provision directs federal 

agencies, to the greatest extent practicable and permitted 

by law, to make environmental justice part of their mission 

by identifying and addressing, as appropriate, 

disproportionately high and adverse human health or 

environmental effects of their programs, policies, and 

activities on minority populations and low-income 

populations in the United States. 

EPA has determined that this proposed rule will not 

have disproportionately high and adverse human health or 

environmental effects on minority or low-income populations 

because it does not affect the level of protection provided 
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to human health or the environment because it is a rule 

addressing information collection and reporting procedures.
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List of Subjects in 40 CFR Part 98

Environmental protection, Administrative practice and 

procedure, Greenhouse gases, Incorporation by reference, 

Suppliers, Reporting and recordkeeping requirements.

Dated:

Lisa P. Jackson, 

Administrator.
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For the reasons stated in the preamble, title 40, 

chapter I, of the Code of Federal Regulations is proposed 

to be amended as follows: 

Part 98—[AMENDED]

1. The authority citation for part 98 continues to 

read as follows:

Authority: 42 U.S.C. 7401, et seq.

Subpart A—[Amended]

2. Section 98.2 is amended by revising paragraph 

(a)(4)(iii)(B) to read as follows:

§98.2 Who must report?

(a) * * *

(4) * * *

(iii) * * *

(B) Local natural gas distribution companies that 

deliver 460,000 thousand standard cubic feet or more of 

natural gas per year.

* * * * *

3. Section 98.3 is amended by:

a. Revising paragraphs (c)(1), (c)(4)(i), (c)(4)(ii), 

(c)(4)(iii) introductory text, (c)(4)(iii)(A), 

(c)(4)(iii)(B), and (c)(5)(i).

b. Revising the third sentence of paragraph (d)(3) 

introductory text.
Page 217 of 392

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

d. Revising paragraphs (g)(4), (g)(5)(iii).

e. Revising paragraph (h).

f. Revising paragraph (i).

g. Adding paragraph (j). 

§98.3 What are the general monitoring, reporting, 

recordkeeping and verification requirements of this part?

* * * * *

(c) * * *

(1) Facility name or supplier name (as appropriate), 

facility or supplier ID number, and physical street address 

of the facility or supplier, including the city, state, and 

zip code.

* * * * *

(4) * * *

(i) Annual emissions (including biogenic CO2) 

aggregated for all GHG from all applicable source 

categories in subparts C through JJ of this part and 

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 in subparts C through JJ 

of this part in metric tons. Units that use the 

methodologies in part 75 of this chapter to calculate CO2
Page 218 of 392

mass emissions are not required to separately report 

biogenic CO2 emissions, but may do so as an option.

(iii) Annual emissions from each applicable source 

category in subparts C through JJ of this part, expressed 

in metric tons of each applicable GHG listed in this 

paragraph (4)(iii)(A) through (4)(iii)(E).

(A) Biogenic CO2. Units that use the methodologies in 

part 75 of this chapter to calculate CO2 mass emissions are 

not required to separately report biogenic CO2 emissions, 

but may do so as an option.

(B) CO2 (including biogenic CO2). 

* * * * *

(5) * * *

(i) Total quantity of GHG aggregated for all GHG from 

all applicable supply categories in subparts KK through PP 

of this part and expressed in metric tons of CO2e calculated 

using Equation A-1 of this subpart. For fluorinated GHGs, 

calculate and report CO2e for only those fluorinated GHGs 

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 
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to the requirements of paragraph (c) of this section 

beginning in calendar year 2012. * * *

* * * * *

(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. 
Page 220 of 392

(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 

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-
Page 221 of 392

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 

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 and 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 
Page 222 of 392

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 

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 
Page 223 of 392

accuracy requirement, the device must be calibrated to an 

accuracy within the appropriate error range for the 

specific measurement technology, based on an applicable 

operating standard, including but not limited to industry 

standards and manufacturer’s specifications. 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 
Page 224 of 392

using the measurement device, and the initial 

calibration(s) required by this paragraph (i) (if any) 

shall be performed no later than that date. 

(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.
Page 225 of 392

x 100

R

R A

CE ! = (Eq. A-2)

Where:

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.
Page 226 of 392

x 100

FS

R A

CE ! = (Eq. A-3)

Where:

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 
Page 227 of 392

location (or locations), provided that the following 

conditions are met:

(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 an industry 

consensus standards or a manufacturer’s specification. 

(C) You must document the methods used for the 

demonstration described in paragraph (i)(3)(ii)(A) of this 

section in the written 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 Monitoring Plan. You must 
Page 228 of 392

maintain all of this information in a format suitable for 

auditing and inspection. 

(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 

Monitoring Plan and recordkeeping provisions of paragraphs 

(g)(5)(i)(C) 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 or ignition are also exempted from the calibration 

requirements of this section. 
Page 229 of 392

(5) For a flow meter that has been previously 

calibrated in accordance with paragraph (i)(1) of this 

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.
Page 230 of 392

(7) If the results of an initial calibration or a 

recalibration fail to meet the required accuracy 

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 relavant 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. 
Page 231 of 392

(2) Requests for extension of the use of best 

available monitoring methods for measurement device 

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 subsquent 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 
Page 232 of 392

date for the planned process equipment or unit shutdown 

that was provided in the original request. 

(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 233 of 392

(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 234 of 392

(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 235 of 392

4. 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.

* * * * *

5. Section 98.6 is amended by:

a. Adding in alphabetical order definitions for 

“Agricultural byproducts,” “Primary fuel,” “Solid 

byproducts,” “Waste oil,” and “Wood residuals.”
Page 236 of 392

b. Revising the definitions for “Bulk natural gas 

liquid or NGL,” “Distillate Fuel Oil,” “Fossil fuel,” 

“Municipal solid waste or MSW,” “Natural gas,” and “Natural 

gas liquids (NGLs).”

c. Removing the definition for “Fossil fuel-fired.”

§98.6 Definitions.

* * * * *

Agricultural byproducts means those parts of arable 

crops that are not used for the primary purpose of 

producing food. Agricultural byproducts 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.

* * * * *

Distillate Fuel Oil means a classification for one of 

the petroleum fractions produced in conventional 
Page 237 of 392

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.

* * * * *

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 

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, 
Page 238 of 392

commercial/retail, and institutional waste does not include 

used oil, wood pellets, construction, renovation, and 

demolition wastes (which includes, but is not limited to, 

railroad ties and telephone poles), clean wood, industrial 

process or manufacturing wastes, medical waste, or motor 

vehicles (including motor vehicle parts or vehicle fluff). 

Household, commercial/retail, and institutional wastes 

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

maintenance materials, limited to vehicle batteries and 

tires, except where a single waste stream consisting of 

tires is combusted in a unit.

* * * * *

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. Natural gas is composed of at 

least 70 percent methane by volume or has a high heat value 

between 910 and 1150 Btu per standard cubic foot.

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. 
Page 239 of 392

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 byproducts means plant matter such as vegetable 

waste, animal materials/wastes, and other solid biomass, 

except for wood, wood waste, and sulphite lyes (black 

liquor).

* * * * *

Waste oil means a petroleum-derived or syntheticallyderived oil whose physical properties have changed as a 

result of storage, handling or use, such that the oil 

cannot be used for its original purpose. Waste 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 wood waste recovered from three 

principal sources: municipal solid waste (MSW); 
Page 240 of 392

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 

wood residuals include, but are not limited to, railroad 

ties, telephone and utility poles, pier and dock timbers, 

wastewater process sludge from paper mills, and logging 

residues.

* * * * *

6. Section 98.7 is amended by:

a. Removing and reserving paragraph (b).

b. Revising paragraphs (d)(1) and (d)(2).

c. Removing and reserving paragraph (d)(3).

d. Revising paragraphs (d)(4) and (d)(5).

e. Removing and reserving paragraph (d)(6).

f. Revising paragraphs (d)(7) and (d)(8).

g. Removing and reserving paragraph (d)(9).

h. Revising paragraph (d)(10).
Page 241 of 392

i. Removing and reserving paragraph (d)(11).

j. Revising paragraph (e)(4).

k. Removing and reserving paragraph (e)(7).

l. Revising paragraphs (e)(8), (e)(10), (e)(11), 

(e)(14), (e)(15), (e)(19), (e)(20), (e)(24) through 

(e)(27). 

m. Removing and reserving paragraph (e)(28).

n. Revising paragraph (e)(30), (e)(33), and (e)(36).

o. Adding paragraphs (e)(43) and (e)(44).

p. Removing and reserving paragraph (f)(1) and 

(g)(3).

q. Revising paragraph (f)(2)

r. Removing and reserving paragraph (g)(3).

§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 §98.344(c) and §98.364(e).

(2) ASME MFC-4M–1986 (Reaffirmed 1997) Measurement of 

Gas Flow by Turbine Meters, IBR approved for §98.344(c) and 

§98.364(e).

(3) [Reserved]
Page 242 of 392

(4) ASME MFC-6M–1998 Measurement of Fluid Flow in 

Pipes Using Vortex Flowmeters, IBR approved for §98.344(c) 

and §98.364(e).

(5) ASME MFC-7M–1987 (Reaffirmed 1992) Measurement of 

Gas Flow by Means of Critical Flow Venturi Nozzles, IBR 

approved for §98.344(c) and §98.364(e).

(6) [Reserved]

(7) ASME MFC-11M-2006 Measurement of Fluid Flow by 

Means of Coriolis Mass Flowmeters, IBR approved for 

§98.344(c).

(8) ASME MFC-14M-2003 Measurement of Fluid Flow Using 

Small Bore Precision Orifice Meters, IBR approved for 

§98.344(c) and §98.364(e).

(9) [Reserved]

(10) ASME MFC-18M-2001 Measurement of Fluid Flow 

Using Variable Area Meters, IBR approved for §98.344(c), 

and §98.364(e).

(11) [Reserved]

(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 243 of 392

(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), 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), §98.344(b), 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).

* * * * *
Page 244 of 392

(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).

(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 

Nitrogen in Laboratory Samples of Coal, IBR approved for 

§98.74(c), §98.114(b), §98.164(b), §98.174(b), §98.184(b), 
Page 245 of 392

§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),§98.224(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).

* * * * *

(43) ASTM D2503-92(2007) Standard Test Method for 

Relative Molecular Mass (Molecular Weight) of Hydrocarbons 

by Thermoelectric Measurement of Vapor Pressure, IBR 

approved for §98.254(d).
Page 246 of 392

(44) ASTM D2593-93(2009) Standard Test Method for 

Butadiene Purity and Hydrocarbon Impurities by Gas 

Chromatography, IBR approved for §98.244(b).

* * * * *

(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), and §98.344(b).

* * * * *

(k) The following material is available from the U.S. 

Environmental Protection Agency, 1200 Pennsylvania Avenue, 

NW, Washington, D.C. 20460, (202) 272-0167, www.epa.gov. 

(1) Protocol for Measuring Destruction or Removal 

Efficiency (DRE) of Fluorinated Greenhouse Gas Abatement 

Equipment in Electronics Manufacturing, Version 1, EPA-430-

R-10-003.

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) * * *
Page 247 of 392

(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:

* * * * *

(d) You are not required to report GHG emissions from 

pilot lights. A pilot light is a small permanent 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 paragraphs (a) introductory text and 

(a)(1).

b. Revising the definition of “HHV” in Equation C-2a 

of paragraph (a)(2)(i).
Page 248 of 392

c. Revising and 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” and “MW” in 

Equation C-5 of paragraph (a)(3)(iii).

g. Revising paragraphs (a)(3)(iv), (a)(4)(iii), and 

(a)(4)(iv).

h. Adding a new 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), (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 paragraph (b)(1)(v).

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).
Page 249 of 392

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 a new paragraph (b)(4)(iv).

r. Revising paragraph (b)(5) and the third sentence 

of paragraph (b)(6).

s. In paragraph (c)(1), revising the second sentence, 

and revising the definition of “HHV” in Equation C-8.

t. Revising the second sentence of paragraph (c)(2).

u. In paragraph (c)(4) introductory text, revising 

the only sentence and revising the definition of “(HI)A” in 

Equation C-10.

v. Revising paragraphs (c)(4)(i) and (c)(4)(ii).

w. Adding a new paragraph (c)(6).

x. In paragraph (d)(1), revising the first sentence, 

adding a second sentence, and revising the definition of 

“R” in Equation C-11.

y. Revising paragraphs (d)(2), (e) introductory text, 

(e)(1), and (e)(2) introductory text.

z. Revising the definition of “Fc” in Equation C-13 of 

paragraph (e)(2)(iii).

aa. Revising paragraphs (e)(2)(iv), (e)(2)(vi)(C), 

and (e)(3).

bb. Reserving paragraph (e)(4).
Page 250 of 392

cc. Revising the first sentence of paragraph (e)(5).

§98.33 Calculating GHG emissions. 

* * * * *

(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 or C-1a 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. In that case, use 

Equation C-1a.
Page 251 of 392

CO 1x 10 * Fuel *HHV *EF 3

2

! = (Eq. C-1)

Where: 

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 consumption, 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.

(2) * * *
Page 252 of 392

(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 

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”, 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).
Page 253 of 392

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 be computed as the 

arithmetic average HHV for all values for the year 

(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.

* * * * *

(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 
Page 254 of 392

frequency as the carbon content. For liquid fuels, you 

must measure the density using one of the following

appropriate methods. You may use a method published by a 

consensus standards organization, if such a method exists, 

or you may use industry standard practice. Consensus-based 

standards organizations include, but are not limited to, 

the following: ASTM International, the American National 

Standards Institute (ANSI), the American Gas Association 

(AGA), the American Society of Mechanical Engineers (ASME), 

the American Petroleum Institute (API), and the North 

American Energy Standards Board (NAESB). The method(s) 

used shall be documented in the Monitoring Plan required 

under §98.3(g)(5). Alternatively, for fuel oil, you may 

use an applicable default density value provided in 

paragraph (a)(3)(v) of this section. For gaseous fuels, 

you may determine the density using any of the following 

methods. You may use a density meter calibrated according 

to the manufacturer’s instructions, a method published by a 

consensus standards organization, or an industry standard 

practice. Document the method used to determine the fuel 

density in the Monitoring Plan under §98.3(g)(5).

* * * * *

(4) * * * 
Page 255 of 392

(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 as 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. 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. 

Moisture data from the relative accuracy test audit (RATA) 

of a CEMS may be used for this purpose. Calculate each 

site-specific default moisture value by taking the 

arithmetic average of the Method 4 runs. Each sitespecific moisture default value shall be updated whenever 
Page 256 of 392

the owner or operator believes the current value is nonrepresentative, 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 

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 
Page 257 of 392

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, provided that the CO2 concentration in 

the diverted stream is not altered in any way (e.g., by 

chemical reaction or dilution) before the diverted stream 

exits to the atmosphere, an estimate of the hourly average 

volumetric flow rate (scfh) of the diverted gas stream 

shall be made at the point where it exits the main exhaust 

system, by using the best available information (e.g., 

correlations of operating parameters versus flow 

measurements made with EPA Method 2 in appendix A-2 to part 

60 of this chapter, engineering analysis, or other 

methods). Each hourly average volumetric flow rate (scfh) 
Page 258 of 392

measured at the main flue gas stack shall then be added to 

the corresponding estimate of the hourly average flow rate 

of the diverted gas stream, to determine the total hourly 

average stack gas volumetric flow rate "Q", for use in 

Equation C-6 of this section. The method use to estimate 

the hourly flow rate of 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 
Page 259 of 392

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 chapterto calculate the quarterly and 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:
Page 260 of 392

(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 

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. 

(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 
Page 261 of 392

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 

paragraphs (b)(1)(ii) and (b)(1)(v) 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. 

(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) * * *

(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 
Page 262 of 392

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) * * *

(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 
Page 263 of 392

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 

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 all of the conditions 

in paragraph (b)(4)(iv)(A)(2) of this section are met.
Page 264 of 392

 (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 

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 either 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 
Page 265 of 392

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 

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:
Page 266 of 392

(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. 

(c) * * *

(1) * * * 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).

* * * * *
Page 267 of 392

(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 

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 
Page 268 of 392

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: 

(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 
Page 269 of 392

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 

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. 

* * * * *

(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 
Page 270 of 392

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:

(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-9a, or C-10 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 
Page 271 of 392

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

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 
Page 272 of 392

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 

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, separate 

reporting of biogenic CO2 emissions is optional 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 provisons 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 
Page 273 of 392

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 

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).

* * * * *
Page 274 of 392

(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 sitespecific 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. 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 275 of 392

(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. 

(4) [Reserved]

(5) 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. * * *

* * * * *

10. Section 98.34 is amended by:
Page 276 of 392

a. Revising paragraphs (a)(2), (a)(3), (a)(6), (b)(1) 

introductory text, (b)(1)(i) introductory text, 

(b)(1)(i)(A), (b)(1)(i)(B), (b)(1)(i)(C), (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).

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), and (f)(5).

h. Adding new 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. 
Page 277 of 392

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.

(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. For the 

purposes of this section, a fuel lot is defined as either:

(A) A shipment or delivery of a single fuel (e.g., 

ship load, barge load, group of trucks, group of railroad 

cars, oil delivery via pipeline from a tank farm, etc.); or 

(B) 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 are 

considered, collectively, to comprise a fuel lot, requiring 

only one representative sample. 
Page 278 of 392

(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.

(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, 

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. 
Page 279 of 392

(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, 

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), 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). 
Page 280 of 392

(B) Calculate a heat-weighted CO2 emission factor, 

(EF)B, for the blend, using Equation C-16 of this section. 

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) 
Page 281 of 392

(iii) Note that for the case described in paragraph 

(a)(3)(ii) of this section, if measured HHV values for the 

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

HHVB HHV i Fuel i

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 282 of 392

(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 283 of 392

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. You may use a method 

published by a consensus standards organization if such a 

method exists, or you may use industry consensus standard 

practice to determine the high heat values. Consensusbased standards organizations include, but are not limited 

to, the following: ASTM International, the American 

National Standards Institute (ANSI), the American Gas 

Association (AGA), the American Society of Mechanical 

Engineers (ASME), the American Petroleum Institute (API), 

and the North American Energy Standards Board (NAESB). 

Alternatively, for gaseous fuels, 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. The 

method(s) used shall be documented in the Monitoring Plan 

required under §98.3(g)(5). 

(b) * * *
Page 284 of 392

(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 an appropriate flow meter calibration 

method published by a consensus standards organization, if 

such a method exists. Consensus-based standards 

organizations include, but are not limited to, the 

following: ASTM International, the American National 

Standards Institute (ANSI), the American Gas Association 

(AGA), the American Society of Mechanical Engineers (ASME), 

the American Petroleum Institute (API), and the North 

American Energy Standards Board (NAESB).

(B) You may use the calibration procedures specified 

by the flow meter manufacturer.

(C) You may use an industry-accepted or industry 

consensus standard calibration 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) either annually, at the minimum frequency 
Page 285 of 392

specified by the manufacturer, or at the interval specified 

by industry consensus standard practice.

(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) 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 or ignition 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 
Page 286 of 392

in this paragraph. When the sampling frequency is based on 

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 upn 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. For the purposes of this 

section, a fuel lot is defined as either of the following:

(1) A shipment or delivery of a single fuel (e.g., 

ship load, barge load, group of trucks, group of railroad 

cars, oil delivery via pipeline from a tank farm, etc.). 

(2) 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 are 

considered, collectively, to comprise a fuel lot, requiring 

only one representative sample. 
Page 287 of 392

(C) For liquid fuels other than fuel oil and for 

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.

(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 
Page 288 of 392

equipment is in place to make these measurements. 

Otherwise, weekly sampling and analysis shall be performed.

* * * * *

(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. You may use a method 

published by a consensus standards organization if such a 

method exists, or you may use industry consensus standard 
Page 289 of 392

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, the American National 

Standards Institute (ANSI), the American Gas Association 

(AGA), the American Society of Mechanical Engineers (ASME), 

the American Petroleum Institute (API), and the North 

American Energy Standards Board (NAESB). 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. 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 

certified prior to the applicable deadline specified in 

§98.33(b)(5). 

(1) * * *

(i) Sections 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
Page 290 of 392

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 ongoing 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. 
Page 291 of 392

(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 

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; 
Page 292 of 392

§75.10(d)(1) of this chapter; or the hourly data validation 

requirements of an applicable State CEM regulation. 

(d) 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 

during normal unit operating conditions for at least 24 

consecutive hours or for as long as is deemed necessary to 

obtain a representative sample. One suggested alternative 

sampling approach would be 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 nonbiogenic fractions using the average proportion of biogenic 
Page 293 of 392

emissions of all samples analyzed during the reporting 

year. Express the results as 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 and ASTM D7459-

08 may be used to determine the biogenic portion of the CO2

emissions. Perform the ASTM D7459-08 sampling and the ASTM 

D6866-08 analysis in every calendar quarter in which 

biomass and non-biogenic fuels are co-fired in the unit. 

Collect each gas sample using ASTM D7459-08 during normal 

unit operation for at least 24 consecutive hours or for as 

long as is necessary to obtain a representative sample. If 

the types of fuels combusted in the unit and their relative 

proportions are not consistent throughout the quarter, more 

frequent, periodic sampling of the flue gas should be 

considered. For example, an integrated sample could be 

collected by extracting a small amount of the flue gas 

(e.g., 1 to 5 cc) in each unit operating hour of the 

quarter. If the primary fuel for multiple units at the 
Page 294 of 392

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.

* * * * *

(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.* * * * *

(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).

 
Page 295 of 392

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 in accordance with 

part 75 of this chapter, the missing data substitution 

procedures in part 75 of this chapter shall be 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. Revising paragraphs (c)(1)(ii), (c)(1)(vi), and 

(c)(1)(vii).
Page 296 of 392

g. Redesignating paragraph (c)(1)(viii) as paragraph 

(c)(1)(x), and revising newly designated paragraph 

(c)(1)(x).

h. Removing paragraph (c)(1)(ix).

i. Adding new paragraphs (c)(1)(viii) and (c)(1)(ix).

j. Revising paragraphs (c)(2) introductory text, 

(c)(2)(ii), (c)(2)(iii), and (c)(2)(v).

k. Removing paragraph (c)(2)(viii).

l. Redesignating paragraphs (c)(2)(vi) and 

(c)(2)(vii) as paragraphs (c)(2)(viii) and (c)(2)(ix), and 

revising newly designated paragraphs (c)(2)(viii) and 

(c)(2)(ix).

m. Adding new paragraphs (c)(2)(vi) and (c)(2)(vii).

n. Revising paragraphs (c)(3) introductory text, 

(c)(3)(ii), (c)(3)(iii), and (c)(3)(vii).

o. Removing paragraph (c)(3)(viii).

p. Adding new paragraphs (c)(3)(viii), (c)(3)(ix), 

and (c)(4).

q. Revising paragraph (d).

r. Revising paragraphs (e)(1)(iii), (e)(2)(i), 

(e)(2)(ii)(C), (e)(2)(ii)(D), (e)(2)(iii), and 

(e)(2)(iv)(A), (e)(2)(iv)(C).

s. Adding new paragraphs (e)(2)(iv)(F) and 

(e)(2)(v)(E).
Page 297 of 392

t. Revising paragraphs (e)(2)(vii)(A), (e)(2)(ix) 

introductory text, and (e)(2)(x) introductory text.

u. Removing paragraphs (e)(2)(x)(B) and (e)(2)(x)(C).

v. Redesignating paragraph (e)(2)(x)(D) as 

(e)(2)(x)(B), and revising newly designated paragraph 

(e)(2)(x)(B).

w. Revising paragraph (e)(2)(xi).

§98.36 Data reporting requirements. 

* * * * *

(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:
Page 298 of 392

(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) If the total annual CO2 mass emissions measured 

by the CEMS includes both biogenic and non-biogenic CO2, 

separately report the annual non-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) The number of units in the group.

* * * * *
Page 299 of 392

(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.

(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, 
Page 300 of 392

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 

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 both combustion products and 

process off-gases, and all of the effluent comes from a 

single unit (e.g., a furnace, kiln, 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.
Page 301 of 392

(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 

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 

liquid-fired or gaseous-fired stationary combustion units 

at a facility combust the same type of 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 
Page 302 of 392

line using a fuel flow meter. For Tier 3 applications, the 

flow meter shall be calibrated in accordance with 

§98.34(b). If a portion of the fuel measured at the main 

supply line is diverted to either: a flare; or another 

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 

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 
Page 303 of 392

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 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:

* * * * *

(ii) The number of units served by the common pipe.

(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 situations where a common liquid or gaseous fuel 
Page 304 of 392

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 small 

combustion sources on-site, including but not limited to 

space heaters and hot water heaters. 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 
Page 305 of 392

combustion sources on-site, a description of the types of 

units and the approximate number of units is sufficient.

(d) Units subject to part 75 of this chapter. 

(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. Reporting of 

biogenic CO2 emissions under §98.3(c)(4)(ii) and 

§98.3(c)(4)(iii)(A) is optional. Subpart D units are not 

required to report biogenic CO2 emissions under 

§§98.3(c)(4)(ii) and (c)(4)(iii)(A).

(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 
Page 306 of 392

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. 

(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 (optional).

(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.
Page 307 of 392

(B) The methodology used to calculate the CO2 mass 

emissions for each fuel type.

(C) Methodology start date.

(D) Methodology end date.

(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 emisions 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 (optional).

(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:
Page 308 of 392

(A) Each type of fuel combusted during the reporting 

year.

(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 emisions 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 (optional).

(e) * * *

(1) * * *

(iii) Are not in the Acid Rain Program, but are 

required to monitor and report CO2 mass emissions and heat 
Page 309 of 392

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 or, if applicable, 

therms for gaseous fuels.

(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 310 of 392

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 311 of 392

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).

(v) * * *

(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) * * *

(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 
Page 312 of 392

§98.33(e)(2), you shall report the following additional 

information, as applicable:

* * * * *

(x) When ASTM methods D7459-08 and D6866-08 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 and D6866-08 are used 

in accordance with §98.34(e) to determine the biogenic 

portion of the annual CO2 emissions from a unit that cofires biogenic fuels (or partly-biogenic fuels, including 

tires if you are electing 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 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.”
Page 313 of 392

b. Revising the entry for “Pipeline (Weighted U.S. 

Average).”

c. Removing the entry for “Still Gas.”

d. Adding an entry for “Waste Oil” to follow the 

entry for “Residual Fuel Oil No. 6.”

e. Adding an entry for “Ethanol” to follow the entry 

for “Ethane.”

f. Revising the entry for “Fossil fuel-derived fuels 

(solid).”

g. Revising the entry for “Municipal Solid Waste.”

h. Adding entries for “Plastics” and “Petroleum Coke” 

to follow the entry for “Tires.”

i. Revising the entry for “Fossil fuel-derived fuels 

(gaseous).”

j. Adding entries for “Propane Gas” and “Fuel Gas” to 

follow the entry for “Coke Oven Gas.”

k. Revising the entry for “Biomass fuels - solid.”

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 a new footnote “2.”
Page 314 of 392

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

* * * * * * *

Waste Oil 0.135 74.00

* * * * * * *

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

Biomass fuels - solid mmBtu/short 

ton

kg CO2 /mmBtu

* * * * * * *

Ethanol 0.084 68.44

Biodiesel 0.128 73.84

* * * * * * *

1

 Use of this default HHV is allowed only for units that combust 

MSW, do not generate steam, and are allowed to use Tier 1.

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, Tier 3 (Equation C-5) or Tier 4 must be used.

14. The first Table C-2 is removed, and the second 

Table C-2 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)
Page 315 of 392

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 

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 98.46 is revised to read as follows:

§98.46 Data reporting requirements. 
Page 316 of 392

The annual report shall comply with the data reporting 

requirements specified in §98.36(d)(1).

17. 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 

recordkeeping requirements of §98.3(g)(4) for those same 

events.

Subpart F—[Amended]

18. 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.

* * * * *

19. 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.
Page 317 of 392

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:

* * * * *

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.
Page 318 of 392

* * * * *

20. 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 one year after publication of the rule 

for smelters with no prior measurement or effective three 

years after publication for facilities with historic 

measurements, the smelter-specific 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), 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. 
Page 319 of 392

(iii) Smelter-specific slope coefficients, 

overvoltage emission factors, and weight fractions 

according to paragraph (a) of this section. 

* * * * *

21. Section 98.65 is amended by revising the only 

sentence of paragraph (a) to read as follows:

§98.65 Procedures for estimating missing data.

* * * * *

(a) Where anode or paste consumption data are 

missing, CO2 emissions can be estimated from aluminum 

production per Equation F-8 of this section.

* * * * *

22. 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. 

* * * * *

23. Table F-1 is revised to read as follows:

Table F-1 to Subpart F—Slope and Overvoltage Coefficients 

for the Calculation of PFC Emissions from Aluminum 

Production
Page 320 of 392

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

24. Table F-2 is amended by revising the entry for 

“CO2 Emissions from Pitch Volatiles Combustion (VSS and 

HSS)” to read as follws:

Table F-2 to Subpart F—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]

25. Section 98.72 is amended by revising paragraphs 

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

§98.72 GHGs to report.

* * * * *
Page 321 of 392

(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).

* * * * *

26. 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 322 of 392

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 323 of 392

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)).

* * * * *

27. Section 98.74 is amended by revising paragraph 

(d) and by removing and reserving paragraph (f) to read as 

follows:

§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).

* * * * *

28. 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. 

* * * * *
Page 324 of 392

(a) For missing data on monthly carbon contents of 

feedstock, the substitute data value shall be the 

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.

29. 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 a new 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):
Page 325 of 392

* * * * *

(b) * * *

(6) Sampling analysis results of carbon content of 

feedstock as determined for QA/QC of supplier data under 

§98.74(e).

* * * * *

(12) Annual urea production (metric tons) and method 

used to determine urea production.

(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]

30. Section 98.164 is amended by revising paragraph 

(b)(1) 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 
Page 326 of 392

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).

* * * * *

Subpart V—[Amended]

31. Section 98.226 is revised by removing paragraph 

(o).

Subpart X—[Amended]

32. 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 onsite production of other chemicals as well as 

processes that produce the petrochemical as an end product 

for sale or shipment offsite.

* * * * *

(g) A process that solely distills or recycles waste 

solvent that contains a petrochemical is not part of the 

petrochemical production source category.
Page 327 of 392

33. 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. 

* * * * *

34. Section 98.243 is amended by:

a. Revising the second sentence of paragraph (b).

b. Revising the definition of “MVC” in Equation X-1 

in paragraph (c)(5)(i).

c. Revising paragraph (d).

§98.243 Calculating GHG emissions.
Page 328 of 392

* * * * *

(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) * * *

(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 each combustion unit 

that burns fuel that contains any off-gas from the ethylene 

process as specified in paragraphs (d)(1) through (d)(5) of 

this section. 
Page 329 of 392

(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.

(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 
Page 330 of 392

is not installed at any point in the line supplying fuel 

gas (that contains ethylene process off-gas) or an upstream 

common pipe.

(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).

35. Section 98.244 is amended by revising paragraphs 

(b)(1) through (b)(3) and (b)(4) introductory text; and by 
Page 331 of 392

adding paragraphs (b)(4)(xi) through (b)(4)(xiii) to read 

as follows:

§98.244 Monitoring and QA/QC requirements.

* * * * *

(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 biennially (i.e., 

once every two years) or at the minimum frequency specified 

by the manufacturer.

(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 according to one of the 

following. You may use either an industry consensus 

standard method or methods specified by the flow meter 

manufacturer. 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). You must 
Page 332 of 392

recalibrate each flow meter according to one of the 

following frequencies. You may recalibrate either 

biennially, at the minimum frequency specified by the 

manufacturer, 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 

(e.g., ASTM, API, etc.) or you may use industry standard 

practice.

(4) Use any applicable methods specified in 

paragraphs (b)(4)(i) through (b)(4)(xiii) 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)(xiii), 

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 
Page 333 of 392

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)(xiii) of this section may be performed by 

the owner or operator, by an independent laboratory, or by 

the supplier of a feedstock.

* * * * *

(xi) ASTM D2593-93 (Reapproved 2009) Standard Test 

Method for Butadiene Purity and Hydrocarbon Impurities by 

Gas Chromatography, (incorporated by reference, see §98.7), 

effective as of January 1, 2010. 

(xii) An industry standard practice for carbon black 

feedstock oils and carbon black products, effective as of 

January 1, 2010.

(xiii) Modifications of existing analytical methods 

or other analytical methods that are applicable to your 

process provided that the methods listed in 

§98.244(b)(4)(i) through §98.244(b)(4)(xii) 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, 

effective as of January 1, 2010.

36. Section 98.246 is amended by:
Page 334 of 392

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 

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 temperture (in °F) 

at which the gaseous feedstock and product volumes used in 

Equation X-1 of this subpart were determined. Indicate 
Page 335 of 392

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)(xiii), report the information listed in 

paragraphs (a)(11)(i) through (a)(11)(iii) 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 

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 

(xii), you may provide a copy of only the sections that 

differ from the listed method.
Page 336 of 392

(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).

(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 
Page 337 of 392

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.

(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).
Page 338 of 392

* * * * *

(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 

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).

37. Section 98.247 is amended by:

a. Revising paragraph (a).
Page 339 of 392

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) * * *

(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]
Page 340 of 392

38. 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 

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 
Page 341 of 392

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.

(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:
Page 342 of 392

(i) A flow meter is not installed at any point in the 

line supplying fuel gas or an upsteam 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. * * *

39. Section 98.253 is amended by:

a. Revising paragraph (b)(1)(ii)(A).

b. Revising the definition of “MVC” in Equation Y-3 

in paragraph (b)(1)(iii)(C).

c. Revising paragraph (c)(1)(ii).

d. Revising the definition of “MVC” in Equation Y-6 

in paragraph (c)(2)(i).

e. Revising paragraph (c)(2)(ii).

f. Revising the definition of “CBQ” and “n” in 

Equation Y-11 in paragraph (e)(3).

g. Revising the first sentence of paragraph (f) 

introductory text and the last sentence of paragraph 

(f)(1).
Page 343 of 392

h. Revising the definition of “MVC” in Equation Y-12 

in paragraph (f)(4).

i. Revising the definition of “Mdust” in Equation Y-13 

in paragraph (g)(2).

j. Revising paragraphs (h) introductory text and 

(h)(2).

k. In paragraph (i)(1), revising the first two 

sentences and the definition of “MVC” in Equation Y-18.

l. In paragraph (j), revising both sentences; and 

revising the definitions of “(VR)p,” “(MFx)p,” and “MVC” in 

Equation Y-19.

m. In paragraph (k), revising the first sentence and 

the definition of “MVC” in Equation Y-20.

n. Revising paragraph (m) introductory text.

o. Revising the definitions of “MFCH4” and “MVC” in 

Equation Y-23 in paragraph (m)(2).

p. 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 
Page 344 of 392

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); 

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).
Page 345 of 392

(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.

( ) ( ) ( ) ! ! = = "

"

#

$

%

%

&

'

(

(

)

*

+

+

,

-

.

/

0

1

2

3 = 4 4 4 + 4 4

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.

(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.
Page 346 of 392

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. 

* * * * *

(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. 
Page 347 of 392

(2) * * *

(i) * * * * *

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.

( )

100 % 2 % % 2

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).
Page 348 of 392

%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).

%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 
Page 349 of 392

cracking unit regenerator or fluid coking unit 

burner (percent by volume – dry basis). 

* * * * *

(e) * * *

(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. 
Page 350 of 392

* * * * *

(4) * * * * *

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 
Page 351 of 392

flare emissions calculated in paragraph (b) of this section 

or in the stationary combustion unit emissions required 

under subpart C of this part (General Stationary Fuel 

Combustion Sources). 

!

"

# $

%

& = ' ' '

12

44 CO2 0.98 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).
Page 352 of 392

12 = Atomic weight of C (kg/kg-mole).

( ) 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 353 of 392

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 be reasonably 

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 354 of 392

* * * * *

(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 Y-20 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.

(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 
Page 355 of 392

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 Section 5.2 of the AP-42: “Compilation of Air Pollutant 

Emission Factors, Volume 1: Stationary Point and Area 

Sources.” For loading operations in which the vapor-phase 

concentration of methane is less than 0.5 volume percent, 

you may assume zero methane emissions.

40. Section 98.254 is amended by:

a. Revising paragraph (a).

b. Revising paragraph (b).

c. Revising paragraph (c).

d. Revising paragraphs (d) introductory text and

(d)(6).

e. Revising paragraph (e) introductory text.

f. Revising paragraph (f) introductory text and 

(f)(1).

g. Removing and reserving paragraph (f)(2).

h. Removing paragraph (f)(4).

i. Revising paragraph (g).

j. Revising the second sentence of paragraph (h).

k. Removing paragraph (l).

§98.254 Monitoring and QA/QC requirements. 
Page 356 of 392

(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 in the applicable methods specified in 

paragraphs (c) through (g) of this section or the 

procedures specified by the manufacturer. In the case of 

gas flow meters, all gas flow meters must meet the 

calibration accuracy requirements in §98.3(i). You must 

recalibrate each gas flow meter according to one of the 

following frequencies. You may recalibrate either 

biennially (every two years), at the minimum frequency 

specified by the manufacturer, or at the interval specified 

by the industry consensus standard practice used. You must 

recalibrate each gas composition monitor and heating value 

monitor according to one of the following frequencies. You 

may recalibrate either annually, at the minimum frequency 
Page 357 of 392

specified by the manufacturer, or at the interval specified 

by the industry consensus standard practice used. 

(c) For flare or sour gas flow meters, operate, 

calibrate, and maintain the flow meter according to one of 

the following. You may use a method published by a 

consensus-based standards organization or the procedures 

specified by the flow meter manufacturer. Consensus-based 

standards include, but are not limited to, the following: 

ASTM International, the American Society of Mechanical 

Engineers (ASME), and the American Gas Association (AGA).

(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).

* * * * *

(6) ASTM D2503-92 (Reapproved 2007) Standard Test 

Method for Relative Molecular Mass (Molecular Weight) of 
Page 358 of 392

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) or §98.253(j), 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.

* * * * *

(g) For exhaust gas CO2/CO/O2 composition monitors 

used to comply with the requirements in §98.253(c)(2), 
Page 359 of 392

install, operate, calibrate, and maintain exhaust gas 

composition monitors according to the 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 

or the procedures specified by the 

manufacturer. * * *

* * * * * 

41. 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 a new 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 a new paragraph (f)(9).

h. Revising newly designated paragraphs (f)(11) 

through (f)(13).

i. Revising paragraphs (g)(5), (h)(2), (h)(4), and 

(h)(6).
Page 360 of 392

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 a new paragraph (j)(8).

n. Revising paragraphs (k)(1), (k)(3), (l) 

introductory text, (l)(5), and (m).

o. Revising paragraph (o). 

§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 

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
Page 361 of 392

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) and the annual average higher 

heating value of the flare gas (in MMBtu per MMscf).

(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 

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 
Page 362 of 392

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. 

(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 
Page 363 of 392

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 

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) * * *
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(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). 

* * * * *

(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) * * *
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(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). * * *

* * * * *

(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) * * *
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(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 

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:

* * * * *
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(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.

(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).
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(4) For uncontrolled blowdown systems reporting under 

§98.253(j), the relevant information required under 

paragraph (l)(5) of this section.

* * * * *

(o) * * *

(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 (Section 7.1 of the AP-42: 

“Compilation of Air Pollutant Emission Factors, Volume 1: 

Stationary Point and Area Sources”, including TANKS Model 

(Version 4.09D) or similar programs, or Equation Y-22 of 

this section, other).

(ii) The total quantity (in MMbbl) of crude oil plus 

the quantity of intermediate products received from offsite 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 
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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 

rate data used to estimate the cumulative CH4 emissions for 

storage tanks used to process unstabilized crude oil.

* * * * *

42. 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 
Page 370 of 392

§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]

43. Section 98.273 is amended by:

a. Revising paragraphs (a)(1) and (a)(2).

b. Revising paragraphs (b)(1) and (b)(2).

c. 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 

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).

* * * * *
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(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. 

(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.
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(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.

* * * * *

44. Section 98.276 is amended by revising the 

introductory text 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:

* * * * *

45. 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
Page 373 of 392

a

Emission factors for kraft calciners are not available.

Subpart OO—[Amended]

46. Section 98.410 is amended by revising paragraph 

(b) to read as follows:

§98.410 Definition of the source category.

* * * * *

(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). 

* * * * *
Page 374 of 392

47. Section 98.414 is amended by:

a. Revising the second sentence of paragraph (a).

b. Revising paragraph (h).

c. Removing and reserving paragraph (j).

d. Adding new paragraphs (n) through (q).

§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 
Page 375 of 392

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 

the concentrations of 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 destroyed.

* * * * * 

(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 
Page 376 of 392

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 

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 
Page 377 of 392

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. 

(3) Frequency of measurement. Perform the 

measurements at least once by [INSERT DATE 60 DAYS AFTER 

DATE OF PUBLICATION IN THE FEDERAL REGISTER] if the 

fluorinated GHG product is being produced on [INSERT DATE 

OF PUBLICATION 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 DATE OF PUBLICATION 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 
Page 378 of 392

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 

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.
Page 379 of 392

(q) Low-concentration constituents are exempt from 

the monitoring and QA/QC requirements of this section.

48. Section 98.416 is amended by:

a. Revising paragraph (a)(3). 

b. Removing and reserving paragraph (a)(4).

c. Revising paragraph (a)(11).

d. Revising paragraphs (c) introductory text and

(c)(1).

e. Revising paragrap (d) introductory text.

f. 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 380 of 392

(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.

* * * * *

(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.

* * * * *
Page 381 of 392

(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 

report shall contain the following information for each 

export: 

* * * * *

(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 382 of 392

(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.

49. Section 98.417 is amended by revising paragraph 

(a)(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 

industry standards or manufacturer directions used for 

calibration pursuant to §98.414(m) and (o).

* * * * *

(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.

50. Section 98.418 is revised to read as follows:
Page 383 of 392

§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 

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 
Page 384 of 392

that are deliberately combined with the product (e.g., to 

affect the performance characteristics of the product).

Subpart PP—[Amended]

51. 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.

* * * * *

52. Section 98.423 is amended by:

a. Revising the first sentence of paragraph (a) 

introductory text.

b. Revising the first sentence of paragraphs (a)(1) 

and (a)(2).

c. Redesignating paragraph (b) as paragraph (c) and 

revising the only sentence in newly designated paragraph 

(c).

d. Adding a new 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 
Page 385 of 392

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. * * *

* * * * * 

(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.
Page 386 of 392

(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. 

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,u = Quarterly CO2 concentration measurement of CO2

stream u that delivers CO2 to containers in 

quarter p (vol. %CO2).

Qp = Quarterly volume of contents supplied in all 

containers delivered by CO2 stream u in quarter 

p (metric tons) (standard cubic meters).

Dp = Quarterly CO2 stream density determination for 

CO2 stream u in quarter p (metric tons per 

standard cubic meter). 

p = Quarter of the year.

u = CO2 stream that delivers to containers. 
Page 387 of 392

(3) To aggregate data, sum the mass of CO2 supplied in 

containers delivered by all CO2 streams in accordance with 

Equation PP-3 of this section. 

Where: 

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.

53. Section 98.424 is amended by revising paragraph 

(a) and the second sentence of paragraph (b)(2); and by 

adding paragraph (c) to read as follows:

§98.424 Monitoring and QA/QC requirements.

(a) * * *

(1) Reporters following the procedures in paragraph 

(a) of §98.423 shall determine quantity using a flow meter 

or meters located in accordance with this paragraph. 

(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 after the point 

of segregation.
Page 388 of 392

(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. 

(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 

delivered, sum the mass of contents supplied in all 

containers to which the CO2 stream 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.
Page 389 of 392

(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 

delivered, sum the volume of contents supplied in all 

containers to which the CO2 stream delivered during each 

quarter, sample the CO2 stream on a quarterly basis to 

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 

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: 

* * * * *

(ii) You shall follow industry standard practices. 

(b) * * *

(2) * * * Acceptable methods include 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 (incorporated by 

reference, see §98.7 of subpart A of this part).

(c) If you measure the flow of the CO2 stream with a 

volumetric flow meter, you shall convert all measured 
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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 

must use 0.0018704 metric tons per standard cubic meter.

54. Section 98.425 is amended by adding a new 

paragraph (d) to read as follows:

§98.425 Procedures for estimating missing data.

* * * * *

(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 
Page 391 of 392

according to the reporter’s established procedures may be 

substituted for any period during which measurement 

equipment is inoperable.

55. Section 98.426 is amended by:

a. Revising paragraphs (a) introductory text and 

(a)(2).

b. Adding a new paragraph (a)(5).

c. Revising paragraphs (b) introductory text and 

(b)(2).

d. Adding a new 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, 

deyhdration, compression, and other processing. 
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(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:

* * * * *

(2) Quarterly volume in standard cubic meters of CO2.

* * * * *

(7) The location of the flow meter in your process 

chain in relation to the points of CO2 stream capture, 

deyhdration, compression, and other processing. 

(c) If you use Equation PP-3 of this subpart report 

the annual CO2 mass in metric tons from all flow meters and 

CO2 streams that delivers CO2 to containers.

* * * * *

(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.

* * * * *