79092 Federal Register / Vol. 75, No. 242 / Friday, December 17, 2010 / Rules and Regulations 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 98 

[EPA–HQ–OAR–2008–0508; FRL–9234–7] 

RIN 2060–AQ33 

Mandatory Reporting of Greenhouse 

Gases 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Final rule. 

SUMMARY: EPA is amending specific 

provisions in the greenhouse gas 

reporting rule to clarify certain 

provisions, to correct technical and 

editorial errors, and to address certain 

questions and issues that have arisen 

since promulgation. These final changes 

include generally providing additional 

information and clarity on existing 

requirements, allowing greater 

flexibility or simplified calculation 

methods for certain sources, amending 

data reporting requirements to provide 

additional clarity on when different 

types of greenhouse gas emissions need 

to be calculated and reported, clarifying 

terms and definitions in certain 

equations and other technical 

corrections and amendments. 

DATES: The final rule is effective on 

December 31, 2010. The incorporation 

by reference of certain publications 

listed in the final rule amendments are 

approved by the director of the Federal 

Register as of December 31, 2010. 

ADDRESSES: EPA has established a 

docket under Docket ID No. EPA–HQ– 

OAR–2008–0508 for this action. All 

documents in the docket are listed in 

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

Although listed in the index, some 

information is not publicly available, 

e.g., confidential business information 

(CBI) or other information whose 

disclosure is restricted by statute. 

Certain other material, such as 

copyrighted material, is not placed on 

the Internet and will be publicly 

available only in hard copy form. 

Publicly available docket materials are 

available either electronically through 

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

copy at EPA’s Docket Center, Public 

Reading Room, EPA West Building, 

Room 3334, 1301 Constitution Ave., 

NW., Washington, DC. This Docket 

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

p.m., Monday through Friday, excluding 

legal holidays. The telephone number 

for the Public Reading Room is (202) 

566–1744, and the telephone number for 

the Air Docket is (202) 566–1742. 

FOR FURTHER INFORMATION CONTACT: 

Carole Cook, Climate Change Division, 

Office of Atmospheric Programs (MC– 

6207J), Environmental Protection 

Agency, 1200 Pennsylvania Ave., NW., 

Washington, DC 20460; telephone 

number: (202) 343–9263; fax number: 

(202) 343–2342; e-mail address: 

GHGReportingRule@epa.gov. For 

technical information and 

implementation materials, please go to 

the Greenhouse Gas Reporting Program 

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

change/emissions/ghgrulemaking.html. 

To submit a question, select Rule Help 

Center, followed by Contact Us. 

SUPPLEMENTARY INFORMATION: Regulated 

Entities. The Administrator determined 

that this action is subject to the 

provisions of Clean Air Act (CAA) 

section 307(d). See CAA section 

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

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

the Administrator may determine’’). 

These are final amendments to existing 

regulations. These amended regulations 

affect owners or operators of certain 

suppliers and direct emitters of 

greenhouse gases (GHGs). Regulated 

categories and entities include those 

listed in Table 1 of this preamble: 

TABLE 1—EXAMPLES OF AFFECTED ENTITIES BY CATEGORY

Category NAICS Examples of affected facilities 

General Stationary Fuel Combustion 

Sources.

........................ 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. 

611 Educational services. 

Electricity Generation ................................ 221112 Fossil-fuel fired electric generating units, including units owned by Federal and municipal governments and units located in Indian Country. 

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

Aluminum Production ................................ 331312 Primary aluminum production facilities. 

Ammonia Manufacturing ........................... 325311 Anhydrous and aqueous ammonia production facilities. 

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

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

Glass Production ...................................... 327211 Flat glass manufacturing facilities. 

327213 Glass container manufacturing facilities. 

327212 Other pressed and blown glass and glassware manufacturing facilities. 

HCFC–22 Production and HFC–23 Destruction.325120 Chlorodifluoromethane manufacturing facilities. 

Hydrogen Production ................................ 325120 Hydrogen production 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. 

331492 Secondary lead smelting and refining facilities. 

Lime Production ........................................ 327410 Calcium oxide, calcium hydroxide, dolomitic hydrates manufacturing facilities. 

Nitric Acid Production ............................... 325311 Nitric acid production facilities. 

Petrochemical Production ......................... 32511 Ethylene dichloride production facilities. 


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Federal Register / Vol. 75, No. 242 / Friday, December 17, 2010 / Rules and Regulations 79093 

TABLE 1—EXAMPLES OF AFFECTED ENTITIES BY CATEGORY—Continued 

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. 

Pulp and Paper Manufacturing ................. 322110 Pulp mills. 

322121 Paper mills. 

322130 Paperboard mills. 

Silicon Carbide Production ....................... 327910 Silicon carbide abrasives manufacturing facilities. 

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

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

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

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

331492 Zinc dust reclaiming facilities, recovering from scrap and/or alloying purchased metals. 

Municipal Solid Waste Landfills ................ 562212 Solid waste landfills. 

221320 Sewage treatment facilities. 

Manure Management a .............................. 112111 Beef cattle feedlots. 

112120 Dairy cattle and milk production facilities. 

112210 Hog and pig farms. 

112310 Chicken egg production facilities. 

112330 Turkey Production. 

112320 Broilers and other meat type chicken production. 

Suppliers of Natural Gas and NGLs ......... 221210 Natural gas distribution facilities. 

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. 

aEPA will not be implementing subpart JJ of 40 CFR part 98 using funds provided in its FY2010 appropriations or Continuing Appropriations 

Act, 2011 (Pub. L. 111–242), due to a Congressional restriction prohibiting the expenditure of funds for this purpose. 

Table 1 of this preamble is not 

intended to be exhaustive, but rather 

provides a guide for readers regarding 

facilities and suppliers likely to be 

affected by this action. Table 1 of this 

preamble lists the types of facilities and 

suppliers that EPA is now aware could 

be potentially affected by the reporting 

requirements. Other types of facilities 

and suppliers than those listed in the 

table could also be subject to reporting 

requirements. To determine whether 

you are affected by this action, you 

should carefully examine the 

applicability criteria found in 40 CFR 

part 98, subpart A or the relevant 

criteria in the subparts. If you have 

questions regarding the applicability of 

this action to a particular facility or 

supplier, consult the person listed in the 

preceding FOR FURTHER INFORMATION

CONTACT section. 

What is the effective date? The final 

rule is effective on December 31, 2010. 

Section 553(d) of the Administrative 

Procedure Act (APA), 5 U.S.C. Chapter 

5, generally provides that rules may not 

take effect earlier than 30 days after they 

are published in the Federal Register. 

EPA is issuing this final rule under 

section 307(d)(1) of the Clean Air Act, 

which states: ‘‘The provisions of section 

553 through 557 * * * of Title 5 shall 

not, except as expressly provided in this 

section, apply to actions to which this 

subsection applies.’’ Thus, section 

553(d) of the APA does not apply to this 

rule. EPA is nevertheless acting 

consistently with the purposes 

underlying APA section 553(d) in 

making this rule effective on December 

31, 2010. Section 5 U.S.C. 553(d)(3) 

allows an effective date less than 30 

days after publication ‘‘as otherwise 

provided by the agency for good cause 

found and published with the rule.’’ As 

explained below, EPA finds that there is 

good cause for this rule to become 

effective on December 31, 2010, even 

though this results in an effective date 

fewer than 30 days from date of 

publication in the Federal Register. 

While this action is being signed prior 

to December 1, 2010, there is likely to 

be a significant delay in the publication 

of this rule as it contains complex 

equations and tables and is relatively 

long in length. As an example, EPA 

signed a shorter technical amendments 

package related to the same underlying 

reporting rule on October 7, 2010, and 

it was not published until October 28, 

2010 (75 FR 66434), three weeks later. 

The purpose of the 30-day waiting 

period prescribed in 5 U.S.C. 553(d) is 

to give affected parties a reasonable time 

to adjust their behavior and prepare 

before the final rule takes effect. Where, 

as here, the final rule will be signed and 

made available on the EPA Web site 

more than 30 days before the effective 

date, but where the publication is likely 

to be delayed due to the complexity and 

length of the rule, that purpose is still 

met. Moreover, most of the revisions 

being made in this package provide 

flexibilities to sources covered by the 

reporting rule, or otherwise relieve a 

restriction. Thus, a shorter effective date 

in such circumstances is consistent with 

the purposes of APA section 553(d), 

which provides an exception for any 

action that grants or recognizes an 

exemption or relieves a restriction. 

Accordingly, we find good cause exists 

to make this rule effective on December 

31, 2010, consistent with the purposes 

of 5 U.S.C. 553(d)(3). 

Judicial Review. Under section 

307(b)(1) of the CAA, judicial review of 

this final rule is available only by filing 

a petition for review in the U.S. Court 

of Appeals for the District of Columbia 

Circuit (the Court) by February 15, 2011. 

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

an objection to this final rule that was 

raised with reasonable specificity 

during the period for public comment 

can be raised during judicial review. 

CAA section 307(d)(7)(B) also provides 

a mechanism for EPA to convene a 

proceeding for reconsideration, ‘‘[i]f the 

person raising an objection can 

demonstrate to EPA that it was 

impracticable to raise such objection 

within [the period for public comment] 

or if the grounds for such objection 

arose after the period for public 


srobinson on DSKHWCL6B1PROD with RULES2
79094 Federal Register / Vol. 75, No. 242 / Friday, December 17, 2010 / Rules and Regulations 

1Consolidated Appropriations Act, 2008, Pub. L. 

110–161, 121 Stat. 1844, 2128. 

comment (but within the time specified 

for judicial review) and if such objection 

is of central relevance to the outcome of 

the rule.’’ Any person seeking to make 

such a demonstration to us should 

submit a Petition for Reconsideration to 

the Office of the Administrator, 

Environmental Protection Agency, 

Room 3000, Ariel Rios Building, 1200 

Pennsylvania Ave., NW., Washington, 

DC 20460, with a copy to the person 

listed in the preceding FOR FURTHER

INFORMATION CONTACT section, and the 

Associate General Counsel for the Air 

and Radiation Law Office, Office of 

General Counsel (Mail Code 2344A), 

Environmental Protection Agency, 1200 

Pennsylvania Ave., NW., Washington, 

DC 20004. Note, under CAA section 

307(b)(2), the requirements established 

by this final rule may not be challenged 

separately in any civil or criminal 

proceedings brought by EPA to enforce 

these requirements. 

Acronyms and Abbreviations. The 

following acronyms and abbreviations 

are used in this document. 

API American Petroleum Institute 

ARP Acid Rain Program 

ASME American Society of Mechanical 

Engineers 

ASTM American Society for Testing and 

Materials 

BAMM best available monitoring method 

CAA Clean Air Act 

cc cubic centimeters 

CE calibration error 

CEMS continuous emission monitoring 

system 

CFR Code of Federal Regulations 

CGA Cylinder gas audit 

CH4 methane 

CO carbon monoxide 

CO2 carbon dioxide 

CO2e CO2-equivalent 

CWPB center worked prebake 

FR Federal Register 

FTIR Fourier transform infrared 

GC gas chromatography 

GHG greenhouse gas 

GHGRP Greenhouse Gas Reporting Program 

GPA Gas Processors Association 

GWP global warming potential 

HFCs hydrofluorocarbons 

HHV high heat value 

HSS horizontal stud S<derberg 

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 

NESHAP National Emission Standards for 

Hazardous Air Pollutants 

NIST National Institute of Standards and 

Technology 

NMR nuclear magnetic resonance 

NSPS New Source Performance Standards 

N2O nitrous oxide 

NAICS North American Industry 

Classification System 

NGLs natural gas liquids 

O2 oxygen 

OMB Office of Management and Budget 

PFC perfluorocarbon 

psia pounds per square inch absolute 

QA quality assurance 

QA/QC quality assurance/quality control 

RATA relative accuracy test audit 

RFA Regulatory Flexibility Act 

scf standard cubic feet 

scfm standard cubic feet per minute 

SF6 sulfur hexafluoride 

SO2 sulfur dioxide 

SWPB side worked prebake 

U.S. United States 

VSS vertical stud S<derberg 

Table of Contents 

I. Background 

A. How is this preamble organized? 

B. Background on This Action 

C. Legal Authority 

D. How will these amendments apply to 

2011 reports? 

II. Final Amendments and Responses to 

Public Comments 

A. 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 Low-Income 

Populations 

K. Congressional Review Act 

I. Background 

A. How is this preamble organized? 

The first section of this preamble 

contains the basic background 

information about the origin of these 

rule amendments. This section also 

discusses EPA’s use of our legal 

authority under the CAA to collect data 

on GHGs. 

The second section of this preamble 

describes in detail the rule changes that 

are being promulgated to, among other 

things, correct technical errors, provide 

clarification, and address 

implementation issues identified by 

EPA and others. This section also 

presents a summary and EPA’s response 

to the major public comments submitted 

on the proposed rule amendments, and 

significant changes, if any, made since 

proposal in response to those 

comments. 

Finally, the last (third) section 

discusses the various statutory and 

executive order requirements applicable 

to this rulemaking. 

B. Background on This Action 

The final Mandatory Reporting of 

Greenhouse Gases Rule was signed by 

EPA Administrator Lisa Jackson on 

September 22, 2009 and published in 

the Federal Register on October 30, 

2009 (74 FR 56260–56519). This rule, 

which added Part 98 to chapter 40 of the 

Code of Federal Regulations (CFR) as 

well as amending other parts of 40 CFR, 

became effective on December 29, 2009, 

and included reporting of GHG 

information from facilities and 

suppliers, consistent with the 2008 

Consolidated Appropriations Act.1

These source categories capture 

approximately 85 percent of U.S. GHG 

emissions through reporting by direct 

emitters as well as certain suppliers 

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

industrial gases and CO2) and 

manufacturers of mobile sources. 

EPA published a notice proposing 

these amendments to Part 98 to, among 

other things, correct certain technical 

and editorial errors that have been 

identified since promulgation and 

clarify or propose amendments to 

certain provisions that have been the 

subject of questions from reporting 

entities. The proposal was published on 


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Federal Register / Vol. 75, No. 242 / Friday, December 17, 2010 / Rules and Regulations 79095 

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 3 75 FR 48747 (August 11, 2010). 

August 11, 2010 (75 FR 48744). The 

public comment period for the proposed 

rule amendments ended on September 

27, 2010. EPA did not receive any 

requests to hold a public hearing. 

This is the second time that EPA has 

published a notice promulgating 

amendments to Part 98 to, among other 

things, correct certain technical and 

editorial errors identified since Part 98 

was originally promulgated and to 

clarify and amend certain provisions 

that have been the subject of questions 

from reporting entities. The first final 

rule amendments were published on 

October 28, 2010 (75 FR 66434). This 

final rule complements the final rule 

published on October 28, 2010 and is 

not intended to duplicate or replace 

those amendments. 

C. Legal Authority 

EPA is promulgating these rule 

amendments under its existing CAA 

authority, specifically authorities 

provided in CAA section 114. 

As stated in the preamble to the 2009 

final rule (74 FR 56260, October 30, 

2009), CAA section 114 provides EPA 

broad authority to require the 

information mandated by Part 98 

because such data would inform and are 

relevant to EPA’s obligation to carry out 

a wide variety of CAA provisions. As 

discussed in the preamble to the initial 

proposal (74 FR 16448, April 10, 2009), 

CAA section 114(a)(1) authorizes the 

Administrator to require emissions 

sources, persons subject to the CAA, 

manufacturers of process or control 

equipment, and persons whom the 

Administrator believes may have 

necessary information to monitor and 

report emissions and provide such other 

information the Administrator requests 

for the purposes of carrying out any 

provision of the CAA. For further 

information about EPA’s legal authority, 

see the preambles to the proposed and 

final rule, and Response to Comments 

Documents.2

D. How will these amendments apply to 

2011 reports? 

We have determined that it is feasible 

for sources to implement these changes 

for the 2010 reporting year because the 

revisions primarily provide additional 

clarifications regarding the existing 

regulatory requirements, generally do 

not affect the type of information that 

must be collected and do not 

substantially affect how emissions are 

calculated. Our rationale for this 

determination is explained in the 

preamble to the proposed rule 

amendments.3 In response to general 

comments submitted on the proposed 

rulemaking, we have again reviewed the 

final amendments and determined that, 

with one limited exception, they can be 

implemented, as finalized, for the 2010 

reporting year. 

The one new requirement, regarding 

reporting of biogenic CO2 emissions 

from units subject to 40 CFR Part 75, is 

being phased in, so that it remains 

optional for reporting year 2010, but 

becomes mandatory for each subsequent 

year. Therefore this revision, as 

finalized, already accommodates 

implementation for the 2010 reporting 

year. 

In summary, except for the exception 

discussed above regarding biogenic CO2

emissions, these amendments do not 

require any additional monitoring or 

data collection above what was already 

included in Part 98. Therefore, we have 

determined that reporters can use the 

same information that they have been 

collecting under Part 98 for each subpart 

to calculate and report GHG emissions 

for 2010 and submit reports in 2011 

under the amended subparts. 

Following is a brief summary of major 

comments and responses. Several 

comments were received on this topic. 

Responses to additional significant 

comments received can be found in the 

document, ‘‘Response to Comments: 

Revision to Certain Provisions of the 

Mandatory Reporting of Greenhouse 

Gases Rule’’ (see EPA–HQ–OAR–2008– 

0508). 

Comment: Several commenters 

requested that we make use of the 

amendments optional for the 2010 

reporting year and mandatory beginning 

with the 2011 reporting year. The 

commenters expressed concern that in 

2010, sources may not have been 

collecting the required data to 

implement certain amendments. 

Response: We sought comment on the 

feasibility of incorporating the proposed 

revisions for the 2010 reporting year. In 

the proposal, we explained that we felt 

implementation for the 2010 reporting 

year would be feasible because the 

proposed revisions, to a great extent, 

would simply clarify existing regulatory 

requirements or add flexibility to the 

rule. Further, the proposed amendments 

would not substantially affect the type 

of information that must be collected or 

how emissions are calculated. We 

sought comment on this conclusion and 

whether this timeline is feasible or 

appropriate, considering the nature of 

the proposed changes and the way in 

which data have been collected thus far 

in 2010. We requested that commenters 

provide specific reasons why they 

believe that the proposed 

implementation schedule would or 

would not be feasible. We received 

some comments about making optional 

the use of the amendments in 2010, as 

well as comments proposing to extend 

submission of the first reports until June 

1, 2011. We received a few industryspecific examples providing a rationale 

for extending the deadline for reporting, 

or making use of the amendments 

optional for the 2010 reporting year. For 

example, some commenters expressed 

concern that the proposed clarification 

of the definition of natural gas, as well 

as the introduction of fuel gas into Table 

C–1, could affect applicability under the 

rule and the use of the tiers under 

subpart C. We have addressed the 

underlying concerns expressed by these 

commenters, as EPA did not intend to 

change applicability or force facilities to 

use higher tiered calculation 

methodologies. Therefore, because we 

addressed the underlying concerns, we 

are finalizing requirements to 

incorporate the amendments into 2010 

reporting year data. 

II. Final Amendments and Responses to 

Public Comments 

We are amending various subparts in 

Part 98 to correct errors in the regulatory 

language that were identified as a result 

of working with reporters to implement 

the various subparts of Part 98. We are 

also amending certain rule provisions to 

provide greater clarity. The amendments 

to Part 98 include the following types of 

changes: 

• Additional information to 

understand better or more fully 

compliance obligations in a specific 

provision, such as the reference to a 

standardized method that must be 

followed. 

• Amendments to certain equations to 

better reflect actual operating 

conditions. 

• Corrections to terms and definitions 

in certain equations. 

• Corrections to data reporting 

requirements so that they more closely 

conform to the information used to 

perform emission calculations. 

• Amendments, in limited cases, to 

allow for the use of simplified emissions 

calculation methods. 

• Changes to correct cross references 

within and between subparts. 

• Other amendments related to 

certain issues identified as a result of 

working with reporters during rule 

implementation and outreach. 

• Applying a threshold for reporting 

for local distribution companies of equal 

to or greater than 460,000 thousand 


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79096 Federal Register / Vol. 75, No. 242 / Friday, December 17, 2010 / Rules and Regulations 

standard cubic feet (mscf) of natural gas 

delivered per year. 

• Requiring separate reporting of 

biogenic CO2 emissions for units that 

are also subject to 40 CFR part 75, 

beginning with the 2011 reporting year. 

The final amendments promulgated 

by this action reflect EPA’s 

consideration of the comments received 

on the proposal. The major public 

comments and EPA’s responses for each 

subpart are provided in this preamble. 

Our responses to additional significant 

public comments on the proposal are 

presented in a comment response 

document available in Docket ID No. 

EPA–HQ–OAR–2008–0508. 

A. Subpart A—General Provisions: Best 

Available Monitoring Methods 

1. Summary of Final Amendments and 

Major Changes Since Proposal 

EPA is finalizing the petition process 

established in 40 CFR 98.3(j) that allows 

use of Best Available Monitoring 

Methods (BAMM) past December 31, 

2010 for owners and operators required 

to report under subpart P (Hydrogen 

Production), subpart X (Petrochemical 

Production), or subpart Y (Petroleum 

Refineries), under limited 

circumstances. Owners or operators 

subject to these subparts can petition 

EPA to extend use of BAMM past 

December 31, 2010, if compliance with 

a specific provision in the regulation 

requires measurement device 

installation, and installation would 

necessitate an unscheduled process 

equipment or unit shutdown, or could 

be installed only through a ‘‘hot tap.’’ If 

the application is approved, the owner 

or operator can postpone installation of 

the measurement device until the next 

scheduled maintenance outage, but 

initially no later than December 31, 

2013. If, in 2013, owners or operators 

still determine and certify that a 

scheduled shutdown will not occur by 

December 31, 2013, they may re-apply 

to use best available monitoring 

methods for an additional two years. 

Process for requesting an extension of 

best available monitoring methods. We 

are adding a similar petition process to 

that recently concluded for the use of 

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

process is for quantifying emissions 

from any source category at facilities 

subject to subparts P, X and/or Y, and 

solely for the installation of 

measurement devices that cannot be 

installed safely except during full 

process equipment or unit shutdown or 

through installation via a hot tap. 

BAMM is allowable initially no later 

than December 31, 2013. Subpart P, X, 

and/or Y owners or operators requesting 

to use BAMM beyond 2010 are required 

to electronically notify EPA by January 

1, 2011 that they intend to apply for 

BAMM for installation of measurement 

devices and certify that such installation 

will require a hot tap or unscheduled 

shutdown. 

Owners or operators must submit the 

full extension request for BAMM by 

February 15, 2011. The full extension 

request must include a description of 

the measurement devices that could not 

be installed in 2010 without a process 

equipment or unit shutdown, or through 

a hot tap, a clear explanation of why 

that activity could not be accomplished 

in 2010 with supporting material, an 

estimated date for the next planned 

maintenance outage, and a discussion of 

how emissions will be calculated in the 

interim. More specifically, the full 

extension request must identify the 

specific monitoring instrumentation for 

which the request is being made, 

indicate the locations where each piece 

of monitoring instrumentation will be 

installed, and note the specific rule 

requirements (by rule subpart, section, 

and paragraph numbers) for which the 

instrumentation is needed. The 

extension requests must also include 

supporting documentation 

demonstrating that it is not practicable 

to isolate the equipment and install the 

monitoring instrument without a full 

process equipment or unit shutdown, or 

through a hot tap, as well as providing 

the dates of the three most recent 

process equipment or unit shutdowns, 

the typical frequency of shutdowns for 

the respective equipment or unit, and 

the date of the next planned shutdown. 

Once subpart P, X, and/or Y owners 

or operators have notified EPA of their 

plan to apply for BAMM for 

measurement device installation, by 

January 1, 2011, and subsequently 

submitted a full extension request, by 

February 15, 2011, they can 

automatically use BAMM consistent 

with their request through June 30, 

2011. This automatic extension is 

necessary because the current BAMM 

requests submitted by these facilities 

will end no later than December 31, 

2010. The BAMM must be extended 

automatically to provide EPA the time 

to review thoroughly the BAMM 

requests submitted for post-2010, while 

ensuring that the petitioning facilities 

are not out of compliance with the rule 

during that review process. All 

measurement devices must be installed 

by July 1, 2011 unless EPA approves the 

BAMM extension request before that 

date. 

Approval of extension requests. In any 

approval of an extension request, EPA 

will approve the extension itself, 

establish a date by which all 

measurement devices must be installed, 

and indicate the approved alternate 

method for calculating GHG emissions 

in the interim. 

If EPA approves an extension request, 

the owner/operator has until the date 

approved by EPA to install the relevant 

remaining meters or other measurement 

devices, however initial approvals will 

not grant extensions beyond December 

31, 2013. An owner/operator that 

already received approval from EPA to 

use BAMM during part or all of 2010 is 

required to submit a new request for use 

of BAMM beyond 2010. Unless EPA has 

approved an extension request, all 

owners or operators that submit a timely 

request under this new process for 

BAMM will be required to install all 

measurement devices by July 1, 2011. 

We recognize that occasionally a 

facility may plan a scheduled process 

equipment or unit shutdown and the 

installation of required monitoring 

equipment, but the date of the 

scheduled shutdown is changed. We are 

adding a process by which owners or 

operators who receive an extension will 

have the opportunity to extend the use 

of BAMM beyond the date approved by 

EPA if they can demonstrate to the 

Administrator’s satisfaction that they 

are making a good faith effort to install 

the required equipment. At a minimum, 

facilities that determine that the date of 

a scheduled shutdown will be 

postponed are required to notify EPA 

within 4 weeks of such a determination, 

but no later than 4 weeks before the date 

for which the planned shutdown was 

scheduled. 

One-time request to extend best 

available monitoring methods past 

December 31, 2013. If subpart P, X, and/ 

or Y owners or operators determine that 

a scheduled shutdown will not occur by 

December 31, 2013 and thus they want 

to continue to use BAMM, they are 

required to re-apply to use BAMM for 

one additional time period, not to 

extend beyond December 31, 2015. To 

obtain an extension for the use of 

BAMM past December 13, 2013, owners 

or operators are required to submit a 

new extension request by June 1, 2013 

that contains the information required 

in 40 CFR 98.3(j)(4). All owners or 

operators that submit a request under 

this paragraph to extend the use of best 

available monitoring methods for 

measurement device installation are 

required to install all measurement 

devices by December 31, 2013, unless 

the additional extension request under 

this paragraph is approved by EPA. 


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Federal Register / Vol. 75, No. 242 / Friday, December 17, 2010 / Rules and Regulations 79097 

2. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. 

Several comments were received on this 

topic. Responses to additional 

significant comments received can be 

found in the document, ‘‘Response to 

Comments: Revision to Certain 

Provisions of the Mandatory Reporting 

of Greenhouse Gases Rule’’ (see EPA– 

HQ–OAR–2008–0508). 

Comment: EPA received several 

comments, both in support of and in 

opposition to, the proposed extension of 

BAMM for facilities subject to subparts 

P, X and Y. Some commenters that 

supported the new BAMM process also 

recommended that EPA extend the 

process beyond hydrogen producers, 

petrochemical facilities and petroleum 

refineries. They suggested that the same 

logic should apply to all facilities, that 

installation of monitoring equipment 

should not require process equipment or 

unit shutdown. 

Other commenters were concerned 

that the new BAMM process conflicts 

with the need for consistent data. The 

commenters urged that if EPA 

nevertheless decides to finalize the 

requirements, there should be only a 

one-time application process with 

BAMM ending no later than December 

2013. Further, they asserted that EPA 

should require facilities to make use of 

unplanned shutdowns as an 

opportunity to install equipment. 

Response: EPA carefully considered 

the issues raised by commenters and 

decided to retain the BAMM extension 

process, as proposed, only for facilities 

subject to subparts P, X and Y. The 

proposal preamble sought comment on 

this very issue and requested that 

commenters provide information on 

additional subparts, if any, that would 

need this flexibility, and include 

information on why installation could 

not be done in the absence of such a 

shutdown or why such shutdowns did 

not or could not occur in 2010 without 

unreasonable burden on the facility. 

Commenters did not provide the 

requested information to support their 

position that the provision should be 

extended to other industries. In 

summary, the commenters argued only 

that EPA should provide this flexibility, 

but did not provide a rationale as to 

why additional industries needed the 

flexibility. 

Regarding concerns that the new 

BAMM process would lead to 

inconsistent data, EPA has determined 

that this limited opportunity for a 

BAMM extension will provide 

sufficiently consistent data for these 

industries without causing the 

unnecessary burden or potential safety 

concerns that would be associated with 

installation of monitoring devices 

during unplanned shutdowns or hot 

taps. EPA notes that the BAMM process 

will still require facilities to follow the 

calculation methods in the rule, but will 

allow owners or operators to use 

alternative methods to provide the 

inputs to those calculations. Further, 

unlike the BAMM process that was 

established by promulgation of the 

October 30, 2009 reporting rule (74 FR 

56379–56380), any request for BAMM 

after 2010 will require EPA approval of 

a facility’s proposed approach to be 

implemented in lieu of the requirements 

in the rule. This further ensures that 

EPA will continue to receive data of the 

appropriate quality. 

EPA decided not to limit BAMM to a 

one-time extension through 2013, 

because we determined that the reasons 

supporting extension through 2013 were 

still valid post 2013. Specifically, 

facilities in these particularly complex 

industries should not have to shut down 

unnecessarily in order to install 

equipment. Data provided by these 

industries show that some units, for 

example crude distillation units, are 

shut down only every 4 to 7 years. Other 

units such as vacuum distillation units, 

fluid catalytic cracking units, distillate 

hydrotreating units, catalytic feed 

hydrotreaters, hydrocrackers, coking 

units, sulfur recovery units and 

cogeneration units can be shut down as 

infrequently as every 5 years (see final 

Background Technical Support 

document to the Revision of Certain 

Provisions of the Mandatory Reporting 

of Greenhouse Gases Rule). Thus, 

providing a potential end date for 

BAMM of December 31, 2015, is 

appropriate based on information 

presented for these industries on the 

typical frequency of shutdown for these 

facilities. 

We also are not requiring a facility to 

order the measurement equipment early 

and have it on hand in the event of an 

unplanned shutdown before the 

scheduled shutdown. First, it would be 

hard to enforce a requirement to install 

equipment during an unplanned 

shutdown ‘‘if feasible’’ because it would 

be hard to objectively determine 

whether a facility should have installed 

equipment during an unplanned 

shutdown. Moreover, during an 

unplanned shutdown, the priority is 

often to get the equipment up and 

running as quickly and safely as 

possible; therefore, there is not 

necessarily time to install the 

measurement equipment. 

Comment: In a related comment, one 

commenter raised concerns about Tier 3 

monitoring requirements for a stream at 

its facility that is dangerous to monitor 

due to the presence of hydrogen 

cyanide. They indicated that they used 

BAMM to implement an approach other 

than direct sampling of the inputs to the 

equations for the 2010 reporting year, 

and now are considering implementing 

the Tier 4 method for future years. 

However, they argued the rule should 

provide a mechanism to address these 

dangerous streams. 

Response: No rule change has been 

made as a result of the comment. For the 

2010 reporting year, the BAMM 

provisions were designed for use where 

it was not possible to acquire, install 

and operate a required piece of 

equipment during the early months of 

the GHG Reporting Program. Safety 

concerns were a valid reason for 

approving these early BAMM 

applications. 

Although the commenter notes 

concerns with conducting the Tier 3 

method for quantifying emissions from 

stationary combustion at the facility due 

to the presence of a hydrogen cyanide 

stream, EPA notes that the rule does not 

limit them to use of a Tier 3 approach. 

As acknowledged by the commenter, 

they also have the opportunity to use 

Tier 4 to meet the requirements of the 

rule and, by taking advantage of BAMM 

for 2010, had one year to install the Tier 

4 equipment. The commenter merely 

wants additional time beyond that 

already provided in the rule to comply 

with the Tier 4 requirements. The 

commenter does not justify the 

requested extension by pointing to 

issues like unplanned shutdowns or hot 

taps, as discussed in the proposal. EPA 

has determined the unique situation 

raised by the commenter does not 

warrant expanding the BAMM process 

generally beyond industries subject to 

subparts P, X and Y. 

B. Subpart A—General Provisions: 

Calibration Requirements 

1. Summary of Final Amendments and 

Major Changes Since Proposal 

EPA has finalized amendments to 40 

CFR 98.3(i)(1) to specify that the 

calibration accuracy requirements of 40 

CFR 98.3(i)(2) and (i)(3) are required 

only for flow meters that measure liquid 

and gaseous fuel feed rates, feedstock 

flow rates, or process stream flow rates 

that are used in the GHG emissions 

calculations, and only when the 

calibration accuracy requirement is 

specified in an applicable subpart of 

Part 98. For instance, the QA/QC 

requirements in 40 CFR 98.34(b)(1) of 


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79098 Federal Register / Vol. 75, No. 242 / Friday, December 17, 2010 / Rules and Regulations 

subpart C require all flow meters that 

measure liquid and gaseous fuel flow 

rates for the Tier 3 CO2 calculation 

methodology to be calibrated according 

to 40 CFR 98.3(i); therefore, the 

accuracy standards in 40 CFR 98.3(i)(2) 

and (i)(3) will continue to apply to these 

meters. 

We are also amending 40 CFR 98.3(i) 

to clarify that the calibration accuracy 

specifications of 40 CFR 98.3(i)(2) and 

(i)(3) do not apply where the use of 

company records or the use of best 

available information is specified to 

quantify fuel usage or other parameters, 

nor do they apply to sources that use 

Part 75 methodologies to calculate CO2

mass emissions because the Part 75 

quality-assurance 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. 

We are also amending 40 CFR 

98.3(i)(1) to clarify that the calibration 

accuracy specifications in 40 CFR 

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

measurement devices (e.g., weighing 

devices) that provide data for the GHG 

emissions calculations. Rather, these 

devices must be calibrated to meet the 

accuracy requirements of the relevant 

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

requirements, meet appropriate, 

technology-based 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 must be 

documented in the written monitoring 

plan. 

We are adding a new paragraph 40 

CFR 98.3(i)(1)(ii) to clarify that flow 

meters and other measurement devices 

need to be installed and calibrated by 

the date on which data collection needs 

to begin, if a facility or supplier 

becomes subject to Part 98 after April 1, 

2010. 

We are adding new paragraph 40 CFR 

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

which subsequent recalibrations of flow 

meters and other measurement devices 

must be performed. Recalibration must 

be at the frequency specified in each 

applicable subpart, or at the frequency 

recommended by the manufacturer or 

by an industry consensus standard 

practice, if no recalibration frequency 

was specified in an applicable subpart. 

We are adding new paragraph 40 CFR 

98.3(i)(7) to specify the consequences of 

a failed flow meter calibration. Data 

become invalid prospectively, beginning 

at the hour of the failed calibration and 

continuing until a successful calibration 

is completed. Appropriate substitute 

data values must be used during the 

period of data invalidation. 

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

adding absolute value signs to the 

numerators of Equations A–2 and A–3. 

These were inadvertently omitted in the 

October 30, 2009 Part 98. 

We are also amending 40 CFR 

98.3(i)(3) to increase the alternative 

accuracy specification for orifice, 

nozzle, and venturi flow meters (i.e., the 

arithmetic sum of the three transmitter 

calibration errors (CE) at each 

calibration level) from 5.0 percent to 6.0 

percent, since each transmitter is 

individually allowed an accuracy of 2.0 

percent. We are also amending 40 CFR 

98.3(i)(3) for orifice, nozzle, and venturi 

flow meters to account for cases where 

not all three transmitters for total 

pressure, differential pressure, and 

temperature are located in the vicinity 

of a flow meter’s primary element. 

Instead of being required to install 

additional transmitters, reporters are, as 

described below, conditionally allowed 

to use assumed values for temperature 

and/or total pressure based on 

measurements of these parameters at 

remote locations. If only two of the three 

transmitters are installed and an 

assumed value is used for temperature 

or total pressure, the maximum 

allowable calibration error is 4.0 

percent. If two assumed values are used 

and only the differential pressure 

transmitter is calibrated, the maximum 

allowable calibration error is 2.0 

percent. 

We are also amending 40 CFR 

98.3(i)(3) to add five conditions that 

must be met in order for a source to use 

assumed values for temperature and/or 

total pressure at the flow meter location, 

based on measurements of these 

parameters at a remote location (or 

locations). 

• The owner or operator must 

demonstrate that the remote readings, 

when corrected, are truly representative 

of the actual temperature and/or total 

pressure at the flow meter location, 

under all expected ambient conditions. 

Pressure and temperature surveys can 

be performed to determine the 

difference between the readings 

obtained with the remote transmitters 

and the actual conditions at the flow 

meter location. 

• All temperature and/or total 

pressure measurements in the 

demonstration must be made with 

calibrated gauges, sensors, transmitters, 

or other appropriate measurement 

devices. 

• The methods used for the 

demonstration, along with the data from 

the demonstration, supporting 

engineering calculations (if any), and 

the mathematical relationship(s) 

between the remote readings and the 

actual flow meter conditions derived 

from the demonstration data must be 

documented in the monitoring plan for 

the unit and maintained in a format 

suitable for auditing and inspection. 

• The temperature and/or total 

pressure at the flow meter must be 

calculated on a daily basis from the 

remotely measured values, and the 

measured flow rates must then be 

corrected to standard conditions. 

• The mathematical correlation(s) 

between the remote readings and actual 

flow meter conditions must be checked 

at least once a year, and any necessary 

adjustments must be made to the 

correlation(s) going forward. 

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

include an additional exemption from 

the calibration requirements of 40 CFR 

98.3(i) for flow meters that are used 

exclusively to measure the flow rates of 

fuels used for unit startup. For instance, 

a meter that is used only to measure the 

flow rate of startup fuel (e.g., natural 

gas) to a coal-fired unit is exempted. 

Section 98.3(i)(4) is being further 

amended to clarify that gas billing 

meters are exempted from the 

monitoring plan and recordkeeping 

provisions of 40 CFR 98.3(g)(5)(i)(c), 

(g)(6) and (g)(7), which require, 

respectively, that a description of the 

methods used to quality-assure data 

from instruments used to provide data 

for the GHG emissions calculations be 

included in the written monitoring plan, 

that the results of all required 

certification and QA tests be kept, and 

that maintenance records be kept for 

those instruments. 

We are amending 40 CFR 98.3(i)(5) to 

clarify that flow meters that were 

already calibrated according to 40 CFR 

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

recommended calibration schedule or 

an industry consensus calibration 

schedule do not need to be recalibrated 

by the date specified in 40 CFR 

98.3(i)(1) as long as the flow meter is 

still within the recommended 

calibration interval. This paragraph is 

also being amended to clarify that the 

deadline for successive calibrations will 

be according to the manufacturer’s 

recommended calibration schedule or 

an industry consensus calibration 

schedule. 

We are amending 40 CFR 98.3(i)(6) to 

account for units and processes that 

operate continuously with infrequent 

outages and cannot meet the flow meter 

calibration deadline without disrupting 


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Federal Register / Vol. 75, No. 242 / Friday, December 17, 2010 / Rules and Regulations 79099 

normal process operation. Part 98 

allowed the owner or operator to 

postpone the initial calibration until the 

next scheduled maintenance outage. 

Although the rule allowed 

postponement of calibration, it did not 

specify how to report fuel consumption 

for the entire time period extending 

from January 1, 2010 until the next 

maintenance outage. We are amending 

40 CFR 98.3(i)(6) to permit sources to 

use the best available data from 

company records to quantify fuel usage 

until the next scheduled maintenance 

outage. This revision addresses 

situations where the next scheduled 

outage is in 2011, or later. 

The major change since proposal is 

identified in the following list. The 

rationale for this and any other 

significant changes can be found in this 

preamble or the document, ‘‘Response to 

Comments: Revision to Certain 

Provisions of the Mandatory Reporting 

of Greenhouse Gases Rule’’ (see EPA– 

HQ–OAR–2008–0508). 

• Removed the words ‘‘ignition’’ and 

‘‘ignition fuel’’ from 40 CFR 98.3(i)(4), so 

that only fuel flow meters that are used 

exclusively for startup are exempted 

from the calibration requirements of 40 

CFR 98.3(i). 

2. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. 

Several comments were received on this 

topic. Responses to additional 

significant comments received can be 

found in the document, ‘‘Response to 

Comments: Revision to Certain 

Provisions of the Mandatory Reporting 

of Greenhouse Gases Rule’’ (see EPA– 

HQ–OAR–2008–0508). 

Comment: We received several 

comments relating to the proposed 

changes to the calibration accuracy 

requirements set in 40 CFR 98.3(i). 

Commenters expressed concern that 

removing the rule-wide 5 percent 

calibration accuracy requirement would 

compromise the rule’s data quality. The 

commenters noted that a global 

calibration accuracy requirement is 

necessary to provide data that are 

accurate and comparable within and 

across industries. By dropping this 

requirement, the commenters believed 

small calibration errors will 

systematically produce major errors in 

reported data. For measuring devices 

other than flow meters they argued that 

it is not clear what an ‘‘appropriate’’ 

error range is, or what calibration 

standards a reporter would deem 

‘‘applicable,’’ and suggest that by stating 

calibration standards are ‘‘not limited to 

industry standards * * *, ’’ EPA is 

waiving calibration requirements for 

other measuring devices altogether. 

They acknowledge that there is a 

requirement to document the calibration 

procedure used in the monitoring plan, 

but they believe it is not enforceable and 

severely reduces transparency. The 

commenters contend that the use of 

different calibration methods and 

varying levels of accuracy would make 

it difficult to correctly interpret and 

compare the emissions data, and would 

render future policy development very 

difficult. 

In summary, commenters that were 

concerned about our removal of the 

blanket 5 percent calibration accuracy 

requirements asserted that EPA has a 

mandate to implement the rule and 

cannot promulgate any subsequent rule 

that would compromise the quality of 

the data reported. They further argue 

that it is arbitrary and capricious, in 

light of EPA’s reporting mandate, to 

waive the calibration accuracy 

requirements for any flow meters. All 

such meters, they contend, should be 

required to meet these minimum 

accuracy requirements, with no 

exceptions. 

Response: We acknowledge the 

concerns of the commenters and agree 

that a high level of data quality is a 

valuable component of any 

environmental program. However, we 

believe the changes to the calibration 

accuracy requirements of 40 CFR 98.3(i) 

do not jeopardize the integrity of the 

reporting program nor compromise 

EPA’s ability to use the data in the 

future to support climate policy 

development. 

As originally promulgated, 40 CFR 

98.3(i) required that ‘‘all measurement 

devices shall be calibrated to an 

accuracy of 5 percent.’’ However, as 

promulgated, 40 CFR 98.3(i)(2) and (i)(3) 

only provided calibration procedures for 

flow meters. No specific procedures 

were provided for other measurement 

devices. As a result, measurement 

devices other than flow meters would 

necessarily be calibrated according to 

procedures specified in other subparts, 

industry consensus methods, or 

manufacturer specifications. 

In the ‘‘Technical Support Document 

for Revision of Certain Provisions: 

Proposed Rule for Mandatory Reporting 

of Greenhouse Gases,’’ dated July 8, 

2010 (the TSD), vendor information on 

various types of measuring devices 

shows accuracy ranges of significantly 

less than 5 percent. Requiring the 

calibrations to be performed according 

to the accuracy specified by the device 

manufacturer, rather than 5 percent, 

would likely actually increase the data 

accuracy of the rule. In addition, we 

recognize that other programs to which 

reporters may be subject impose 

calibration standards that will affect 

many of the instruments used for 

reporting under Part 98. For example, 

the tested accuracy of fuel flow meters 

and transmitter transducers used in the 

Acid Rain Program from 2005 through 

2009 was well below 1 percent. 

As a result of the wide range of 

industries and measuring devices used 

within each industry, we have 

determined it is not practical to set a 

global calibration standard or method 

that would apply generically to every 

measurement device. Replacing the 5 

percent requirement from the 2009 fine 

rule with manufacturer’s specifications 

or industry specific standards will 

provide a higher level of data certainty 

across the rule while accommodating 

the wide variety of industries and 

equipment covered by the rule. We 

think it is highly unlikely that 

companies will choose to use arbitrary 

standards, as the procedures and 

methods used to quality-assure the 

measurement data must be listed in the 

facility or supplier’s monitoring plan. 

The commenters correctly note that 

the calibration accuracy requirements of 

40 CFR 98.3(i) have been removed 

where company records or best 

available information are used. Since 

promulgation, we have consistently 

affirmed that meters used to generate 

company records are not required to be 

calibrated according to 40 CFR 98.3(i). 

The purpose behind allowing the use of 

company records and best available 

information was to permit companies to 

use fuel billing receipts or other quality 

assured information they currently 

maintain. EPA authorized the use of 

company records to alleviate burden 

and did not intend for such data to be 

subject to additional calibration 

requirements, which would defeat the 

purpose of this flexibility. 

To be clear, we disagree with the 

commenter’s assertions that we are 

‘‘waiving’’ any calibration accuracy 

requirements or that certain types of 

flow meters would not have to be 

calibrated. All measurement 

technologies, except for the limited 

exceptions in 40 CFR 98.3(i) must meet 

calibration accuracy requirements. 

Further, most major emission sources 

should be covered by either the 

requirements of 40 CFR 98.38(i) or 

another program that provides a 

similarly, if not significantly more, 

stringent accuracy requirement. We 

have concluded that the amendments to 

the calibration accuracy requirements 

do not compromise our ability to 

implement successfully this reporting 

rule. 


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79100 Federal Register / Vol. 75, No. 242 / Friday, December 17, 2010 / Rules and Regulations 

Comment: One commenter pointed 

out an inconsistency in the proposed 

rule regarding the term ‘‘ignition fuel.’’ 

EPA proposed to amend 40 CFR 

98.3(i)(4) to exempt fuel flow meters 

that are used exclusively for startup and 

ignition fuel from the calibration 

requirements of 40 CFR 98.3(i). 

However, EPA also proposed in 40 CFR 

98.30(d) to exempt pilot lights from 

GHG emission reporting requirements. 

The commenter noted that pilot lights 

are essentially the same as ignitors, and 

the reference in 40 CFR 98.3(i)(4) to 

flow meters that measure ignition fuel 

appears to imply that GHG emissions 

from the combustion of ignition fuel 

must be reported. 

Response: The GHG emissions 

reporting exemption for pilot lights in 

40 CFR 98.30(d) refers to emissions from 

combustion of the fuel that supplies the 

pilot light. Therefore, in the final rule, 

we have removed the words ‘‘ignition’’ 

and ‘‘ignition fuel’’ from 40 CFR 

98.3(i)(4). Paragraph (i)(4) now refers 

only to startup fuel, which is distinctly 

different from ignition fuel. For 

instance, at startup, a coal-fired boiler 

may burn natural gas for several hours 

at high heat input values, whereas a 

pilot light is a small flame that simply 

ignites or initiates combustion of the 

main fuel (e.g., fuel oil). 

C. Subpart A—General Provisions: 

Reporting of Biogenic Emissions 

1. Summary of Final Amendments and 

Major Changes Since Proposal 

Under the proposed amendments, 

EPA’s goal was to reflect in regulatory 

language clarifications that have been 

issued stating that separate reporting of 

biogenic emissions for units subject to 

40 CFR part 75 was optional. To clarify 

this optional reporting, we proposed to 

amend the data elements in subpart A 

(specifically 40 CFR 98.3(c)(4)) and 

subpart C that currently require separate 

accounting and reporting of biogenic 

CO2 emissions so that it is optional for 

units that are subject to subpart D of this 

part or units that use the methods in 

part 75 to quantify CO2 mass emissions 

in accordance with 40 CFR 98.33(a)(5) 

(40 CFR part 75 units or ‘‘part 75 units’’). 

More specifically, to effect this 

clarification, we proposed to revise the 

reporting for all facilities such that all 

facilities would report combined nonbiogenic and biogenic CO2, and all 

facilities, except those with ‘‘part 75 

units,’’ would still have been required to 

calculate and report biogenic CO2

emissions separately. 

We received numerous adverse 

comments on the proposed amendments 

that would re-structure 40 CFR 

98.3(c)(4) and clarify that separate 

reporting of biogenic CO2 emissions was 

optional for ‘‘part 75 units’’. Most 

commenters urged EPA to make 

separate reporting of biogenic emissions 

mandatory for all reporters. Many 

commenters also objected to the 

restructuring of 40 CFR 98.3(c)(4), 

which would have had all units 

reporting combined biogenic and nonbiogenic CO2 emissions. 

Based on the comments received, we 

have decided to withdraw the proposed 

re-structuring of 40 CFR 98.3(c)(4). We 

have also reconsidered the optional 

reporting of biogenic CO2 emissions 

reporting for ‘‘part 75 units’’. In the final 

rule, a new paragraph, (c)(12), has been 

added to 40 CFR 98.3(c), which states 

that reporting biogenic CO2 is optional 

for ‘‘part 75 units’’ only for the first year 

of the program (i.e., for the 2010 

reporting year). Thereafter, all ‘‘part 75 

units’’ must separately report their 

biogenic CO2 emissions. We are 

allowing the optional biogenic CO2

emissions reporting for the 2010 

reporting year in light of the 2009 final 

rule, as well as our previous statements 

and guidance on the issue. It is likely 

that at least some 40 CFR part 75 

sources are following that policy 

guidance and have elected not to 

separately report biogenic CO2

emissions. It is equally likely that these 

sources have not been keeping the 

necessary records or performing the 

required emission testing to enable them 

to report these emissions for 2010. 

Major changes since proposal are 

identified in the following list. The 

rationale for these and any other 

significant changes can be found in this 

preamble or the document, ‘‘Response to 

Comments: Revision to Certain 

Provisions of the Mandatory Reporting 

of Greenhouse Gases Rule’’ (see EPA– 

HQ–OAR–2008–0508). 

• Retaining the facility level reporting 

requirements from the 2009 final rule 

(74 FR 56373) in 40 CFR 98.3(c)(4) that 

requires reporting of CO2 emissions 

(excluding biogenic CO2) and separate 

reporting of biogenic emissions. 

• Introducing new paragraph 40 CFR 

98.3(c)(12) that allows facilities with 40 

CFR part 75 units the option to include 

biogenic emissions in their facility totals 

for the 2010 reporting year only. 

2. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. 

Several comments were received on this 

topic. Responses to additional 

significant comments received can be 

found in the document, ‘‘Response to 

Comments: Revision to Certain 

Provisions of the Mandatory Reporting 

of Greenhouse Gases Rule’’ (see EPA– 

HQ–OAR–2008–0508). 

Comment: EPA received a large 

number of comments related to the 

proposed amendments to make separate 

reporting of biogenic CO2 emissions 

optional for units subject to 40 CFR part 

75. The three main concerns, each 

raised by multiple commenters, were 

that (1) all reporters should be required 

to separately report biogenic CO2

emissions; (2) reporters should never be 

required to combine fossil CO2 and 

biogenic CO2; and, (3) if EPA 

nevertheless finalizes requirements 

allowing separate reporting of biogenic 

CO2 to be optional for units subject to 

40 CFR part 75, then EPA’s 

implementation of the proposed 

revisions should be narrower in scope 

and not affect reporting requirements for 

all reporters. 

Regarding the first issue, some 

commenters argued that the 

requirements of the Acid Rain Program 

(ARP) should not constrain EPA in the 

GHG context and that all reporters 

under 40 CFR part 98 should be 

required to report biogenic CO2

emissions, regardless of the fact that 

such separate reporting is not a 

requirement in ARP. Commenters 

suggested that this is important for 

consistency across the GHG Reporting 

Program. 

Several commenters suggested that it 

is never appropriate to combine fossil 

CO2 and biogenic CO2 into a single 

reported value. Commenters noted that 

there is a distinction between fossil CO2

and biogenic CO2 and that in order to 

ensure transparency for future climate 

policy these two values should not be 

combined into a single reported 

emissions value. Further, they argued 

that EPA’s proposed requirement for 

sources to combine fossil and biogenic 

emissions together in one total ignores 

the natural biomass carbon cycle and is 

counter to the principle of ‘‘carbon 

neutrality,’’ thereby overstating net CO2

entering the atmosphere. 

The commenters suggested that 

requiring separate reporting of biogenic 

CO2 is consistent with the 

Intergovernmental Panel on Climate 

Change and national, regional, and 

corporate GHG protocols and that EPA 

should not depart from this established 

accounting convention. These 

commenters also pointed out that EPA 

uses this same rationale for requiring 

separate reporting of biogenic CO2

emissions in its own response to 

comments to the GHG Reporting Rule 

(74 FR 56351). Further, the commenters 

articulated that separate reporting of 

biogenic emissions is necessary to 


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4EPA requested comment on approaches to 

accounting for GHG emissions from bioenergy and 

other biogenic sources earlier this year. The Call for 

Information (75 FR 41173 and 75 FR 45112), 

supporting information and comments can be found 

in docket EPA–HQ–OAR–2010–0560. Please refer to 

those documents for more information about this 

issue. 

5Mandatory Greenhouse Gas Reporting Rule, 

EPA’s Response to Public Comments, Volume 16, 

Subpart D Electricity Generation. Found at http:// 

www.epa.gov/climatechange/emissions/

downloads09/documents/SubpartD–Comment

Reponses.pdf. 

provide the public and policymakers 

with information on the extent of 

biomass combustion and the sectors of 

the economy where biomass fuels are 

used, which is information important 

for developing future climate policy. 

Several organizations also commented 

that an accurate, economy-wide 

inventory of biogenic CO2 emissions is 

important because the evidence to date 

demonstrates that biomass is not 

inherently carbon neutral. 

Finally, commenters noted that if EPA 

nevertheless decides to finalize the rule 

allowing optional reporting of biogenic 

CO2 emissions for 40 CFR part 75 units, 

EPA should modify the proposed rule so 

the amendments affect only facilities 

with part 75 units, and do not change 

the reporting requirements for all other 

reporters. Commenters were concerned 

that EPA’s proposed change required all 

reporters to report total CO2 (including 

biogenic CO2 emissions), but only 

required facilities with non-part 75 

units to report their biogenic emissions 

separately. Facilities with part 75 units 

would have the option to report 

separately biogenic CO2 from those 

units. The commenters suggested that if 

EPA chooses to finalize optional 

separate reporting for part 75 units, then 

EPA should revert to the reporting 

requirements in subpart A that were in 

the 2009 final rule (i.e., report CO2

excluding biogenic CO2) (74 FR 56379) 

for all other reporters and add a new 

paragraph specifically for facilities with 

part 75 units. 

Response: We appreciate the 

significant feedback generated by the 

proposed amendments designed to 

clarify that separate reporting of 

biogenic emissions was optional for 

units subject to 40 CFR part 75. We also 

recognize that many industry and 

environmental groups have significant 

interest in the treatment of biomass in 

GHG reports, and specifically in the 

accounting of biogenic CO2 emissions. 

Based on the significant feedback 

received, including comments received 

from facilities with 40 CFR part 75 

units, as well as the fact that one of the 

fundamental goals of the Greenhouse 

Gas Reporting Program (GHGRP) is to 

collect data to support a range of 

potential future climate policies, we 

have reconsidered our position and 

decided to make the separate reporting 

of biogenic emissions mandatory for 

part 75 units beginning in the 2011 

reporting year. Separate reporting of 

biogenic CO2 emissions is optional for 

these units in the 2010 reporting year. 

Per the requirements in the new 

paragraph 40 CFR 98.3(c)(12), facilities 

with one or more part 75 units must 

elect in the 2010 reporting year whether 

to report biogenic CO2 emissions from 

40 CFR part 75 units separately, or 

report only total CO2 emissions 

(including biogenic CO2) for the 40 CFR 

part 75 units at their facility. Beginning 

in the 2011 reporting year, these 

facilities must separately report biogenic 

CO2 emissions for the entire facility per 

the requirements in 40 CFR 98.3(c)(4), 

like all other facilities. 

In addition, the final rule does not 

adopt the proposed restructuring of 40 

CFR 98.3(c)(4) and leaves in place the 

facility-level reporting requirements in 

40 CFR 98.3(c)(4) for any facility in 2010 

or for future years. All other facilities, 

except those with part 75 units, must, as 

finalized in the 2009 final rule, report 

CO2 (excluding biogenic CO2) and then 

report separately biogenic CO2

emissions. We would note that neither 

the original proposed amendments, nor 

the amendments finalized today, affect 

the fact that biogenic CO2 emissions are 

excluded from the applicability 

determination under 40 CFR 98.2. 

Commenters provided many reasons 

for supporting mandatory separate 

reporting of biogenic CO2 emissions 

from all facilities, including the 

increased transparency that such 

reporting brings. Some commenters 

supported the assumption of the carbon 

neutrality of biomass while others 

dispelled it, but both sides were united 

in their comments that it is important to 

understand the GHG emissions 

associated with biomass consumption. 

Our decision to also require separate 

reporting of biogenic emissions for units 

that use the methods in 40 CFR part 75 

is founded solely on the principle that 

having data available at a more 

disaggregated level for a reporting 

program like this one improves 

transparency and better enables us and 

other stakeholders to use the data to 

evaluate future potential policy options, 

without prejudging what those policies 

might be. This decision is not based on 

any conclusions about ‘‘carbon 

neutrality’’ or the appropriateness of 

combining fossil CO2 and biogenic CO2

into a single value.4 Rather, EPA’s 

approach preserves the flexibility for the 

Agency and for stakeholders to 

understand reported CO2 emissions in 

multiple ways. Despite the benefits of 

having separate data with which to 

distinguish biogenic CO2 emissions, 

which we do not dispute, the 2009 final 

rule did not require this reporting for 

units subject to 40 CFR part 75. This is 

consistent with the Response to 

Comments document for subpart D of 

the final rule 5 where it states ‘‘It is 

EPA’s intent that Acid Rain Program 

units will be able to continue to 

measure and report CO2 emissions as 

they do under the Acid Rain Program’’ 

which did not require separate reporting 

of biogenic CO2. However, when we 

opened the relevant paragraphs to 

notice and comment, we received 

overwhelming support for making the 

separate reporting of biogenic CO2

emissions mandatory, including from 

facilities with part 75 units. This 

support, in combination with the value 

of having the data for policy analysis, 

led us to reconsider our position and 

require separate reporting of biogenic 

CO2 emissions beginning in the 2011 

reporting year for the 40 CFR part 75 

units. We decided to retain optional 

reporting for the 2010 reporting year 

due to the fact that we have provided 

guidance indicating that separate 

reporting was optional for these part 75 

units, and therefore, some facilities may 

not have incorporated procedures into 

their monitoring plans or developed 

internal systems for collecting the 

necessary information to facilitate the 

biogenic CO2 emissions calculations. 

To implement the changes described 

above, we are adding new paragraph 40 

CFR 98.3(c)(12), as well as amending 

paragraphs 40 CFR 98.33(e) (to provide 

an additional option for part 75 units to 

calculate the biogenic CO2 emissions), 

40 CFR 98.34(f), several paragraphs in 

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

D. Subpart A—General Provisions: 

Requirements for Correction and 

Resubmission of Annual Reports 

1. Summary of Final Amendments and 

Major Changes Since Proposal 

Subpart A, as promulgated in October 

2009, required that an ‘‘owner or 

operator shall submit a revised report 

within 45 days of discovering or being 

notified by EPA of errors in an annual 

GHG report. The revised report must 

correct all identified errors. * * *’’ We 

are amending 40 CFR 98.3(h) to clarify 

the types of errors that trigger a 

resubmission and the process for 

resubmitting annual GHG reports. 

First, reports only have to be 

resubmitted when the owner or operator 

or the Administrator determines that a 


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substantive error exists. A substantive 

error is defined as one that impacts the 

quantity of GHG emissions reported or 

otherwise prevents the reported data 

from being validated or verified. This 

clarification is important because some 

errors are not significant (e.g., an error 

in the zip code) and do not impact 

emissions. Such non-significant errors 

will not obligate the owner or operator 

to resubmit the annual report. 

The owner or operator is required to 

resubmit the report within 45 days of 

identifying the substantive error, or of 

being notified by the Administrator of a 

substantive error, unless the owner or 

operator provides information 

demonstrating that the previously 

submitted report does not contain the 

identified substantive error or that the 

identified error is not a substantive 

error. This amendment provides owners 

and operators the opportunity to 

demonstrate whether an error the 

Administrator has deemed to be a 

substantive error is not, in fact, a 

substantive error. 

Finally, we are also allowing owners 

and operators to request an extension of 

the 45-day resubmission deadline to 

address facility-specific circumstances 

that arise in either correcting an error or 

determining whether or not an 

identified error is, in fact, a substantive 

error. Owners and operators are 

required to notify EPA by e-mail at least 

two business days prior to the end of the 

45-day resubmission deadline if they 

seek an extension. An automatic 30-day 

extension will be granted if EPA does 

not respond to the extension request by 

the end of the 45-day period. 

We are including the opportunity to 

extend the period for resubmission in 

recognition that the data system is still 

under development and we do not yet 

fully know the full range of errors that 

will be identified and, therefore, the 

time required to address such errors. 

Verification and quality assurance and 

quality control checks are currently 

under development in the data system. 

Some flags that the data system might 

generate will not necessarily reflect 

substantive errors, but rather will be 

flags to alert the owner or operator to 

review the submission carefully to make 

sure the information provided is correct. 

On the other hand, some flags could 

identify substantive errors that affect the 

overall GHG emissions reported to EPA. 

Although we have concluded that it is 

important to provide facilities and 

suppliers the opportunity to extend this 

deadline, we believe that the 45-day 

time period is a sufficient time period 

for the vast majority of facilities and 

suppliers. 

There have been no major changes 

from proposal regarding requirements 

for correction and resubmission of 

annual reports. 

2. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. 

Several comments were received on this 

subpart. Responses to additional 

comments received can be found in the 

document, ‘‘Response to Comments: 

Revision to Certain Provisions of the 

Mandatory Reporting of Greenhouse 

Gases Rule’’ (see EPA–HQ–OAR–2008– 

0508). 

Comment: One commenter, 

representing several organizations, was 

concerned that the amended process for 

submitting revised annual GHG reports 

upon identification or notification by 

EPA of an error was too complex and 

would substantially slow down 

correction of reported errors. Generally, 

they asserted that the 45-day process 

that was in the final Part 98 (74 FR 

56381) should be appropriate for most 

reporters, and to the extent there were 

any outliers, then EPA could use 

enforcement discretion for those 

specific reporters as opposed to 

changing the rule for all reporters. The 

commenter was further concerned that 

EPA proposed to allow reporters to 

extend their resubmission deadline in 

the event of a disagreement between 

EPA and the reporter, by at least 30 

days. The commenters suggested that 

the process does not give EPA a clear 

method to dispute these points with 

operators, does not specify that EPA’s 

view trumps the operator’s opinion, and 

does not allow members of the public to 

argue that an error is, in fact, 

substantive, and must be corrected. 

They contended that the overall process 

could take months or years to correct 

errors, and the operators may still refuse 

to correct some of them. They argued 

this is a departure from the existing 

rule, and serves only to hinder what was 

a straightforward and effective process. 

Response: The process in these final 

rule amendments for submission of 

revised annual GHG reports to correct 

any substantive errors in these reports is 

reasonable and consistent with the 

purpose of the GHG Reporting Program. 

The purpose of these reporting 

requirements is to provide EPA with 

accurate and timely information on 

greenhouse gases in order to gain a 

better understanding of the relative 

emissions of specific industries and 

facilities, the factors that influence 

emission rates, and the actions that 

facilities could in the future, or already 

take, to reduce emissions. In light of this 

purpose, it is reasonable to focus an 

ongoing requirement to correct errors in 

an annual report on ‘‘substantive errors,’’ 

i.e., errors that affect emissions data 

quality, validation, or verification. 

Further, because this is a new program 

covering a wide variety of industries 

and processes, some of whom may not 

be familiar with GHG accounting and 

reporting, we have determined that 

under these circumstances it is 

reasonable to establish a procedure 

engaging owners and operators on 

whether the annual report actually 

contains identified ‘‘substantive errors.’’ 

The commenters’ claims that this 

procedure provides no ‘‘clear method’’ of 

determining what are substantive errors, 

may take ‘‘months, perhaps years,’’ may 

result in owners refusing to correct 

errors, and is unnecessary are 

unsupported and speculative. First, EPA 

has concluded that the definition of 

‘‘substantive error’’—an error that 

impacts emissions data quality or 

otherwise prevents the data from being 

validated or verified—is reasonably 

clear and is consistent with the 

purposes of GHG emissions reporting. 

The commenter fails to show what is 

unclear about this definition, nor why it 

is unreasonable to focus corrections on 

substantive errors, versus insignificant 

ones that do not impact the accuracy of 

submitted information. 

Second, these final rule amendments 

set time limits for correction of 

substantive errors, i.e., correction 

through submission of a revised annual 

GHG report within 45 days of discovery 

(or notification by EPA of the errors) 

plus any ‘‘reasonable extensions’’ of time 

(including one automatic 30 day 

extension). The commenter fails to 

provide any basis for conflating these 

limited time frames into periods of 

many months or years. Further, because 

refusal by an owner or operator to 

correct substantive errors within the 

appropriate time frame would be a 

violation of the CAA and subject to 

significant civil penalties, the 

commenter has no basis for assuming 

that owners and operators would simply 

refuse to make the corrections. 

Third, the error correction process 

provides a standard process that is 

applicable to all owners and operators 

and that owners and operators and EPA 

can use to attempt to resolve issues 

concerning error correction. EPA has 

determined that this process will likely 

result in more efficient error correction 

and resolution of error correction issues 

by setting a limited time for contesting 

EPA’s identification of substantive 

errors. In addition, EPA’s provision of a 

standard process provides more 

certainty for owners and operators of an 


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opportunity to resolve issues than if 

EPA were simply to rely on enforcement 

discretion, as recommended by a 

commenter. 

The commenters also claimed the 

public will have no opportunity to argue 

that errors are substantive and should be 

corrected. However, this does not 

represent a change from the error 

correction process under the 2009 final 

rule. The amendments for resubmission 

of annual reports did not change public 

involvement in the resubmission 

process. 

The process in today’s rule better 

focuses the resources of EPA, regulated 

industries and the public on those errors 

that are most relevant to generating 

accurate data. 

Comment: Several commenters 

requested that EPA provide a numerical 

determination of what is a ‘‘substantive 

error.’’ One commenter proposed a +/¥ 

10 percent change in the reported GHG 

emissions value as a result of the 

identified error. Another commenter 

requested that EPA clarify that 

substantive errors are only those that 

exceed 1 percent to 5 percent of the total 

annual CO2 equivalent emissions. 

One commenter requested that, in the 

final preamble, EPA clarify that any 

error not be considered substantive 

unless it exceeds 1 percent to 5 percent 

of the total annual CO2 equivalent 

(‘‘CO2e’’) emission amount reported by 

an individual reporting facility. The 

commenter also requested that EPA 

modify the ‘‘contains one or more 

substantive errors’’ language to allow the 

agency flexibility to investigate 

potential as well as documented errors. 

Response: The final rule defines 

substantive error as an error that 

impacts the quantity of GHG emissions 

reported or otherwise prevents the 

reported data from being validated or 

verified. EPA has determined that it is 

not appropriate to establish a threshold 

below which errors do not have to be 

corrected and resubmitted. EPA has 

determined that if an error in the GHG 

emissions estimate occurs, then that 

emissions error should be corrected and 

the annual GHG emissions report 

resubmitted. If a facility were to go 

through the process of identifying the 

estimate in GHG emissions, calculating 

what the GHG emissions total should 

have been, and then determining the 

percent difference between the original 

reported estimate and the revised 

estimate, then the reporter has all of the 

information necessary to report that 

revised estimate. 

E. Subpart A—General Provisions: 

Information To Record for Missing Data 

Events 

1. Summary of Final Amendments and 

Major Changes Since Proposal 

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

removing requirements to maintain 

records on the duration of a missing 

data event and actions taken to 

minimize future occurrences, while 

retaining the requirement that records 

be kept of the cause of each missing data 

event and the corrective actions taken. 

We are also clarifying that the records 

retained pursuant to 40 CFR 75.57(h) 

may be used to meet the recordkeeping 

requirements under Part 98 for the same 

missing data events. 

There have been no major changes 

from proposal regarding recordkeeping 

requirements for missing data events. 

2. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. 

Several comments were received on this 

subpart. Responses to additional 

significant comments received can be 

found in the document, ‘‘Response to 

Comments: Revision to Certain 

Provisions of the Mandatory Reporting 

of Greenhouse Gases Rule’’ (see EPA– 

HQ–OAR–2008–0508). 

Comment: Some commenters stated 

that although EPA has justified this 

proposal by noting that 40 CFR part 75 

does not require separate accounting of 

‘‘the duration of missing data events or 

* * * actions taken to minimize 

occurrence in the future,’’ that alone is 

not sufficient justification for not 

including these requirements under the 

reporting program. The commenters 

asserted that part 75’s requirements do 

not constrain EPA’s obligations in the 

GHG context. The commenters wrote 

that reporting the duration of a missing 

data event cannot be considered overly 

burdensome because reporters that 

accurately use missing data procedures 

must know the duration of missing data 

events and so must be collecting this 

information regardless. Also, the 

commenters indicated that most 

facilities covered by the rule do not use 

CEMS, and thus, EPA should not change 

the ‘‘minimize occurrence’’ requirement 

for all reporters (CEMS users and nonCEMS users) because missing data 

events associated with the use of CEMS 

often have no clear measures to avoid 

similar occurrences in the future. 

Response: With respect to removal of 

the requirement to record the duration 

of a missing data event, EPA determined 

that the requirement in 40 CFR 

98.3(c)(8) to report the total number of 

hours in the year that missing data are 

used for each data element provides 

sufficient information for purposes of 

the GHG Reporting Program. Although 

the ‘‘total number of hours’’ will not 

provide information on the duration of 

each missing data event, EPA will know 

the total fraction of the year for which 

missing data are used for a particular 

data element. We have determined that 

this information provides EPA sufficient 

information on the extent of use of the 

missing data provisions for any given 

reporter. 

EPA also decided to remove 

recordkeeping requirements related to 

‘‘actions taken to prevent or minimize 

occurrence in the future’’ after 

considering the value of the potential 

loss of data as compared to the burden 

of compliance with the rule as written. 

As described below, we determined that 

sufficient information is available 

regarding missing data without 

requiring this additional information. 

First, reporters must report annual 

hours for each missing data element. 

Through this reported data, EPA can 

identify whether missing data is 

particularly prevalent for a given data 

element at a given facility. Second, 

records must be retained on the cause of 

the event and actions taken to restore 

malfunctioning equipment. If EPA elects 

to review these records, this 

information, along with reported 

information on the total hours of 

missing data for each data element, will 

suggest whether the source is taking 

action to prevent or minimize 

occurrence in the future. Therefore, we 

have determined that it is not necessary 

to collect information specifically on 

actions taken to prevent or minimize 

occurrence of missing data in the future. 

EPA acknowledges the point made by 

the commenters that most facilities 

subject to the rule do not use CEMS, and 

therefore, this fact can not be used as a 

justification for removing requirements 

related to minimizing future occurrence. 

Further, EPA agrees that information on 

duration would likely be collected when 

following the applicable missing data 

procedures. Nevertheless, based on the 

preceding discussion, EPA has 

concluded that sufficient data will be 

available on missing data through the 

required reporting of total number of 

hours in the year that missing data are 

used for each data element (per 40 CFR 

98.3(c)(8)), and the recordkeeping 

requirements on cause of the event and 

actions taken to restore malfunctioning 

equipment. EPA has determined that 

requiring collection and retention of 

additional data on duration and actions 

taken to prevent or minimize occurrence 


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in the future is not necessary under the 

reporting program at this time. 

F. Subpart A—General Provisions: Other 

Technical Corrections and Amendments 

1. Summary of Final Amendments and 

Major Changes Since Proposal 

We are making several additional 

amendments to subpart A, as follows. 

We are making technical corrections 

to 40 CFR 98.3(c)(4)(i) through (c)(4)(iii) 

and (c)(4)(vi) to clarify that facilities 

must report GHG emissions from all 

applicable source categories, which 

includes general stationary fuel 

combustion, miscellaneous carbonates 

and any other source category covered 

by Part 98. This is consistent with the 

language in the 2009 final rule which 

required facilities to report emissions 

from all applicable source categories in 

subparts C through JJ. In a recent final 

rule (July 12, 2010, 75 FR 39736) we 

updated 40 CFR 98.2 to remove the lists 

of source categories covered by the rule 

and replace the list with Tables, 

specifically Table A–3 and Table A–4 of 

this chapter. This change was merely a 

reorganization and did not change 

applicability under the rule. The 

reformatting from lists to tables would 

enable EPA to add source categories in 

the future, and therefore add new 

subparts to the rule, without having to 

update all language referring to 

‘‘subparts C through JJ.’’ In finalizing that 

rule, we made the appropriate changes 

to 40 CFR 98.2 indicating facilities must 

report GHG emissions from stationary 

fuel combustion sources, miscellaneous 

use of carbonates and all applicable 

source categories in Table A–3 and 

Table A–4. However, only the references 

to Table A–3 and Table A–4 were 

carried over to 40 CFR 98.3(c), which 

might suggest that facilities did not have 

to report emissions from general 

stationary combustion, because 

combustion is not in Table A–3 or Table 

A–4. We are therefore amending 40 CFR 

98.3(c) to clarify that facilities must also 

report emissions from general stationary 

combustion and miscellaneous use of 

carbonates. 

We are amending 40 CFR 98.3(c)(5)(i) 

to clarify that for the purposes of 

meeting the requirements of this 

paragraph, suppliers of industrial 

fluorinated GHGs only need to calculate 

and report GHG emissions in mtCO2e 

for those fluorinated GHGs that are 

listed in Table A–1. Suppliers of 

industrial fluorinated GHGs do not need 

to calculate and report GHG emissions 

in metric tons CO2 equivalents (mtCO2e) 

for fluorinated GHGs not listed in Table 

A–1. However, it is important to note 

that suppliers are still required to report 

these gases under 40 CFR 98.3(c)(5)(ii) 

(in metric tons of GHG). 

We are amending 40 CFR 98.3(d)(3) to 

correct the year in which reporters that 

submit an abbreviated report for 2010 

must submit a full report, from 2011 to 

2012. The full report submitted in 2012 

will be for the 2011 reporting year. 

We are amending 40 CFR 98.3(f) to 

correct the cross-reference from 

‘‘§ 98.3(c)(8)’’ to ‘‘§ 98.3(c)(9).’’ We are 

amending 40 CFR 98.3(g)(5)(iii) to 

correct a spelling error. 

We are amending the elements 

required with a certificate of 

representation under 40 CFR 98.4(i)(2) 

to include organization name (company 

affiliation-employer). We are also 

adding the same element to the 

delegation by designated representative 

and alternate designated representative 

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

the amendments do not require the 

designated representative, alternate 

designated representative, or agent to be 

an employee of the reporting entity. If 

a designated representative further 

delegates their authority to an agent the 

agent gains access to all data for that 

facility or supplier. To underline the 

importance of granting access to the 

correct person, EPA requires the 

designated representative (or alternate) 

to confirm each agent delegation. 

Adding organization name to the 

certificate of representation and notice 

of delegation adds a level of assurance 

to the confirmation process. 

Finally, we are amending 40 CFR 98.6 

(Definitions) and 40 CFR 98.7 (What 

standardized methods are incorporated 

by reference into this part?). We are 

adding or changing several definitions 

to subpart A, which are needed to 

clarify terms used in other subparts of 

Part 98. 

We are amending the definitions of 

several terms in 40 CFR 98.6: 

• Bulk natural gas liquid 

• Distillate fuel oil 

• Fossil fuel 

• Fuel gas 

• Municipal solid waste or MSW 

• Natural gas 

• Natural gas liquids, and 

• Standard conditions 

Bulk natural gas liquid. We are 

amending the definitions of ‘‘bulk 

natural gas liquid or NGL’’ and ‘‘natural 

gas liquids (NGL)’’ by removing the 

phrase ‘‘lease separators and field 

facilities’’ for enhanced clarity. We have 

retained the words ‘‘or other methods’’ 

in both definitions because the list of 

separation processes in the definitions 

(absorption, condensation, adsorption) 

is not exhaustive, and other separation/ 

extraction processes may be employed 

at some facilities. We do not wish to 

exclude the reporting of emissions 

associated with products separated/ 

extracted by means not explicitly stated 

in the rule. 

Distillate fuel oil. We are expanding 

the definition of ‘‘Distillate fuel oil’’ to 

include kerosene-type jet fuel. 

Fossil fuel. We are amending the 

definition of fossil fuel, as proposed, to 

read, ‘‘Fossil fuel means natural gas, 

petroleum, coal, or any form of solid, 

liquid, or gaseous fuel derived from 

such material for purpose of creating 

useful heat.’’ This amendment finalizes 

the same definition of fossil fuel that 

was originally proposed in April 2009 

(74 FR 16621), but was subsequently 

amended in the final Part 98 (74 FR 

56387). The change is not intended to 

have any impact on coverage of 

greenhouse gases under the GHG 

Reporting Program. 

Fuel gas. We are amending the 

definition of fuel gas to clarify that it 

includes only gas generated at refineries 

or petrochemical processes subject to 

subpart X and to remove the phrase ‘‘or 

similar industrial process unit.’’ For a 

fuel explanation of this final change, 

please see the Comments and Response 

discussion under Section II.G of this 

preamble. 

Municipal solid waste. We are 

amending the definition of municipal 

solid waste to be similar to, but not 

exactly the same as, the definition of 

‘‘municipal solid waste’’ in subpart Ea of 

the NSPS regulations (40 CFR 60.51a). 

The amended definition explains what 

is meant by ‘‘household waste,’’ 

‘‘commercial/retail waste,’’ and 

‘‘institutional waste.’’ Household, 

commercial/retail, and institutional 

wastes include yard waste, refusederived fuel, and motor vehicle 

maintenance materials. Insofar as there 

is separate collection, processing and 

disposal of industrial source waste 

streams consisting of used oil, wood 

pallets, construction, renovation, and 

demolition wastes (which includes, but 

is not limited to, railroad ties and 

telephone poles), paper, clean wood, 

plastics, industrial process or 

manufacturing wastes, medical waste, 

motor vehicle parts or vehicle fluff, or 

used tires that do not contain hazardous 

waste identified or listed under 42 

U.S.C. 6921, such wastes are not 

municipal solid waste. However, such 

wastes qualify as municipal solid waste 

where they are collected with other 

municipal solid waste or are otherwise 

combined with other municipal solid 

waste for processing and/or disposal. 

Natural gas. We are finalizing the 

definition of natural gas to remove any 

specifications regarding Btu value or 

methane content. The final definition 


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reads, ‘‘Natural gas means a naturally 

occurring mixture of hydrocarbon and 

non-hydrocarbon gases found in 

geologic formations beneath the earth’s 

surface, of which the principal 

constituent is methane. Natural gas may 

be field quality or pipeline quality.’’ For 

a full explanation of this final change, 

please see the Comments and Response 

discussion under this section of the 

preamble. 

Standard conditions. For consistency 

across the rule, and to reflect typical 

operating procedures at various types of 

industries covered by 40 CFR part 98, 

we are amending the definition of 

standard conditions to mean either 60 or 

68 degrees Fahrenheit and 14.7 pounds 

per square inch absolute. 

We are adding definitions of the 

following terms to 40 CFR 98.6 to 

address the large number of questions 

received requesting clarification on the 

meaning of these terms: 

• Agricultural by-products, 

• Primary fuel, 

• Solid by-products, 

• Used oil, and 

• Wood residuals. 

We received no comments on the 

definitions of ‘‘Agricultural byproducts,’’ ‘‘Primary fuel,’’ and ‘‘Solid byproducts.’’ Therefore, these definitions 

have been finalized, as proposed. For 

the purposes of Part 98, ‘‘Agricultural 

by-products’’ includes the parts of crops 

that are not ordinarily used for food 

(e.g., corn straw, peanut shells, pomace, 

etc.). ‘‘Primary fuel’’ is defined as the 

fuel that contributes the greatest 

percentage of the annual heat input to 

a combustion unit. ‘‘Solid by-products’’ 

includes plant matter such as vegetable 

waste, animal materials/wastes, and 

other solid biomass, except for wood, 

wood waste and sulphite lyes (black 

liquor). 

We proposed to add the term ‘‘waste 

oil’’ to Table C–1 but we received 

comment use of the term ‘‘waste oil’’ 

could result in used oil being classified 

as hazardous waste. We have therefore 

changed the term to ‘‘used oil.’’ Used oil 

has been added to Table C–1 as a new 

fuel type, and is defined as a petroleumderived or synthetically-derived oil 

whose physical properties have changed 

as a result of handling or use, such that 

the oil cannot be used for its original 

purpose. Used oil consists primarily of 

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

transmission oil, hydraulic fluids, brake 

fluid, etc.) and industrial oils (e.g., 

industrial engine oils, metalworking 

oils, process oils, industrial grease, etc). 

For a full explanation of this final 

change, please see the Comments and 

Response discussion under this section 

of the preamble. 

The definition of ‘‘wood residuals’’ 

has been finalized similar to the 

proposal, but EPA has also specifically 

included trim, sander dust, and sawdust 

from wood products manufacturing 

(including resinated wood product 

residuals) in the final definition. 

We are amending 40 CFR 98.7 

(Incorporation by reference) to 

accommodate changes in the standard 

methods that are allowed by other 

subparts of Part 98. The rationale for 

any additions or deletions of methods in 

a particular subpart is discussed in the 

relevant subpart. 

Major changes since proposal are 

identified in the following list. The 

rationale for these and any other 

significant changes can be found in this 

preamble or the document, ‘‘Response to 

Comments: Revision to Certain 

Provisions of the Mandatory Reporting 

of Greenhouse Gases Rule’’ (see EPA– 

HQ–OAR–2008–0508). 

• Not adopting the proposed 

amendments to 40 CFR 98.3(c)(1) to 

report a facility or supplier ID number. 

• Clarifying the definition of 

municipal solid waste. Clarifying that 

separate collection, processing and 

disposal of industrial source waste 

streams consisting of used oil, wood 

pallets, construction, renovation, and 

demolition wastes, clean wood, 

industrial process or manufacturing 

wastes, medical waste, motor vehicle 

parts or vehicle fluff, or used tires that 

do not contain hazardous waste 

identified or listed under 42 U.S.C. 

6921, are not municipal solid waste. 

However, such wastes qualify as 

municipal solid waste where they are 

collected with other municipal solid 

waste or are otherwise combined with 

other municipal solid waste for 

processing and/or disposal. 

• Finalizing the definition of natural 

gas to remove any specifications 

regarding Btu value or methane content. 

• Amending the definition of 

standard conditions to provide two 

alternatives. 

• Replacing the term ‘‘waste oil’’ with 

‘‘used oil.’’ 

• Amending the definition of ‘‘wood 

residuals’’ to include trim, sander dust 

and sawdust from wood products 

manufacturing, including resinated 

wood product residuals. 

2. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. 

Several comments were received on this 

subpart. Responses to additional 

comments received can be found in the 

document, ‘‘Response to Comments: 

Revision to Certain Provisions of the 

Mandatory Reporting of Greenhouse 

Gases Rule’’ (see EPA–HQ–OAR–2008– 

0508). 

Comment: Several commenters 

objected to the proposed definition of 

municipal solid waste or MSW. One 

commenter in particular pointed to the 

regulatory history of the definition in 40 

CFR 60, subpart Ea, indicating that some 

of the materials excluded by the 

proposed definition under 40 CFR part 

98 are often included in MSW. 

According to the commenter, some of 

the exclusions in subpart Ea were added 

to the definition to provide an 

exemption to certain sources that 

combust materials such as used oil or 

wood pellets separately. By excluding 

materials often considered to be part of 

MSW, the commenter expressed 

concern that the proposed definition of 

MSW in 40 CFR part 98 might force 

some municipal waste combustors who 

considered themselves to be combusting 

MSW and would therefore otherwise be 

allowed to use Tier 2, to not meet the 

definition of MSW under 40 CFR part 98 

and therefore have to install CEMS and 

use the Tier 4 methodology to quantify 

CO2 emissions. 

Response: EPA proposed to amend 

the definition of MSW to provide greater 

clarity on what is included as MSW. 

Several questions were raised during 

implementation of the GHGRP because 

the definition of MSW in the final Part 

98 rule was too generic and did not 

define terms such as ‘‘house, 

commercial/retail, and institutional 

waste.’’ To clarify the definition, EPA 

sought to use another EPA definition of 

the term, and did not intend to push 

some municipal waste combustors into 

a higher tier. Based on supplementary 

information provided by the commenter 

(please refer to EPA–HQ–OAR–2008– 

0508), the final definition of MSW 

includes materials that should not have 

been excluded, and clarifies that when 

these materials are extracted from MSW 

and combusted separately, they are not 

classified as MSW. 

Comment: Two commenters on the 

definition of ‘‘Natural gas’’ pointed out 

that not all natural gas (particularly field 

gas) can consistently meet the proposed 

specifications. The commenters were 

concerned that EPA’s proposal to 

include specifications that natural gas 

must be composed of at least 70 percent 

methane by volume or have a high heat 

value between 910 and 1,150 Btu per 

standard cubic foot would be 

problematic for subpart W, when 

finalized, because these ranges could 

exclude field gas. 

Response: The definition of natural 

gas in the final rule caused significant 

confusion because it included not only 


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naturally occurring mixtures of 

hydrocarbons, but also fuels such as 

field gas, process gas and fuel gas. We 

proposed to change the definition of 

‘‘natural gas’’ to include specifications 

on the methane content and a range of 

Btu values that must be achieved before 

the gas can be referred to as ‘‘natural 

gas.’’ Clarifying the definition of natural 

gas is important, particularly given that 

it is a fuel in Table C–1 and if an owner 

or operator burns a fuel outside the 

range of the specifications, then they 

could be pushed into Tier 3 if any unit 

has a maximum rated heat input 

capacity greater than 250 million British 

thermal units per hour (mmBtu/hr). 

Based on the comments received we 

have decided to finalize the definition 

of natural gas without any specifications 

regarding minimum or maximum Btu 

values or a minimum methane content. 

Although the commenters were 

concerned specifically about the 

implications of the definition of natural 

gas for the oil and gas industry, where 

the fuels combusted can often fall 

outside the listed specifications thereby 

potentially forcing them into Tier 3, 

these concerns did not weigh heavily 

into our determination to remove the 

specifications. Rather, we considered 

that most facilities subject to subpart C 

only typically burn natural gas within 

the proposed specifications. For these 

facilities, it was not necessary to list 

specifications, because most would 

already fall into the specifications we 

had proposed. Further, we were 

concerned that by introducing 

specifications to the definition of 

natural gas we could inadvertently push 

a small number of owners or operators 

into Tier 3, if they have been 

combusting a fuel outside that range. 

It is true that facilities in the oil and 

gas industry are more likely to combust 

gas outside the listed specifications 

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

the oil and gas industry will be subject 

to the reporting requirements under 

subpart W beginning with the 2011 

reporting year. The concerns raised by 

the commenters with respect to 

calculating combustion-related 

emissions from natural gas were 

explicitly considered within the context 

of subpart W. 

Comment: One commenter brought to 

our attention that the term ‘‘used oil’’ is 

more appropriate than ‘‘waste oil.’’ 

According to the commenter, the term 

‘‘waste oil’’ could result in used oil being 

classified as hazardous waste rather 

than traditional fuel, and might bring 

the Resource Conservation and 

Recovery Act program into view. 

Response: Without indicating whether 

we agree with the commenter’s concern 

or not, we have decided to avoid 

potential complication or confusion and 

have replaced the term ‘‘waste oil’’ with 

‘‘used oil’’ in the final rule. 

Comment: We received two comments 

on the definition of ‘‘wood residuals.’’ 

Both commenters requested that the 

definition explicitly include trim, 

sander dust and sawdust from wood 

products manufacturing, including 

resinated wood product residuals 

because they were concerned that the 

proposed definition was too broad and 

it was not clear if these products were 

included. 

Response: We agree with the 

commenter. We did not intend to 

exclude these types of products from the 

definition of wood residuals and agree 

that these terms should be included in 

the definition in order to provide 

clarity. 

Comment: Several commenters 

expressed concern about EPA’s proposal 

to add a reporting requirement for 

facility ID. Two commenters suggested 

that EPA provide a separate public 

comment period for including a facility 

ID reporting requirement, and in that 

proposal, include a specific mechanism 

for assigning the ID numbers. 

Response: Although we maintain that 

assigning a unique ID number to each 

facility or supplier, for administrative 

purposes, is important to facilitate 

program implementation, we have 

decided it is not necessary to finalize 

this reporting requirement at this time, 

given the concerns raised by the 

commenters. We will consider this issue 

further for future rulemakings. Note that 

we are still finalizing the technical 

clarification in 40 CFR 98.3(c)(1) that it 

is the physical street address of the 

facility or supplier that must be 

reported. 

G. Subpart C—General Stationary Fuel 

Combustion 

1. Summary of Final Amendments and 

Major Changes Since Proposal 

Numerous issues have been raised by 

owners and operators in relation to the 

requirements in subpart C for general 

stationary fuel combustion. The issues 

being addressed by the final 

amendments include the following: 

• Definition of the source category. 

• GHGs to report. 

• Calculating GHG emissions. 

• Natural gas consumption expressed 

in therms. 

• Use of Equation C–2b. 

• Categories of gaseous fuels. 

• Use of mass-based gas flow meters. 

• Site-specific stack gas moisture 

content values. 

• Determining emissions from an 

exhaust stream diverted from a CEMS 

monitored stack. 

• Biomass combustion in Part 75 

units using the CO2 calculation 

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

• Use of Tier 3. 

• Tier 4 monitoring threshold for 

units that combust MSW. 

• Applicability of Tier 4 to common 

stack configurations. 

• Starting dates for the use of Tier 4. 

• Methane (CH4) and nitrous oxide 

(N2O) calculations. 

• CO2 emissions from sorbent. 

• Biogenic CO2 emissions from 

biomass combustion. 

• Fuel sampling for coal and fuel oil. 

• Tier 3 sampling frequency for 

gaseous fuels. 

• GHG emissions from blended fuel 

combustion. 

• Use of consensus standard methods. 

• CO2 monitor span values. 

• CEMS data validation. 

• Use of American Society of Testing 

and Materials (ASTM) Methods D7459– 

08 and D6866–08. 

• Electronic data reporting and 

recordkeeping. 

• Common stack reporting option. 

• Common fuel supply pipe reporting 

option. 

• Table C–1 default HHV and CO2

emission factors. 

• Table C–2 default CH4 and N2O 

emission factors. 

Definition of the source category. We 

are adding new paragraph 40 CFR 

98.30(d), clarifying that the GHG 

emissions from a pilot light need not be 

included in the emissions totals for the 

facility. A pilot light is a small auxiliary 

flame that simply ignites the burner of 

a combustion process in a boiler, 

turbine, or other fuel combustion 

device, and is not used to produce 

electricity or steam, or provide useful 

energy to an industrial process, or 

reduce waste by removing combustible 

matter. 

GHGs to report. We are amending 40 

CFR 98.32 to clarify that CO2, CH4, and 

N2O mass emissions from a stationary 

fuel combustion unit do not need to be 

reported under subpart C if such an 

exclusion is indicated elsewhere in 

subpart C. 

Calculating GHG emissions. We are 

amending the introductory text of 40 

CFR 98.33(a) to provide additional 

detail and clarify who may (or must) use 

the calculation methods in the 

subsequent paragraphs to calculate and 

report GHG emissions. Specifically, we 

are amending this text to point out that 

certain sources may use the methods in 

40 CFR part 75 to calculate CO2

emissions, if they are already using part 


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75 to report heat input data year-round 

under another CAA program. The 

introductory text of 40 CFR 98.33(a) is 

also being amended to clarify the 

reporting of CO2 emissions from 

biomass combustion when a unit 

combusts both biomass and fossil fuels. 

Natural gas consumption expressed in 

therms. We are amending 40 CFR 

98.33(a)(1) by adding two new equations 

to Tier 1. When natural gas 

consumption is expressed in therms, 

Equation C–1a enables sources to 

calculate CO2 mass emissions directly 

from the information on the billing 

records, without having to request or 

obtain additional data from the fuel 

suppliers. We are also allowing 

Equation C–1a to be used for units of 

any size when the fuel usage 

information on natural gas billing 

records is expressed in units of therms. 

A new paragraph, (b)(1)(v), has been 

added to 40 CFR 98.33 to reflect this. 

Section 98.36(e)(2)(i) is also amended to 

allow gaseous fuel consumption to be 

reported in units of therms. 

Equation C–1b has been added to Tier 

1 to accommodate situations in which 

the fuel usage information on gas billing 

records is expressed in mmBtu. We are 

also adding two new equations to 40 

CFR 98.33(c), i.e., Equations C–8a and 

C–8b, for calculating CH4 and N2O 

emissions when the fuel usage 

information on natural gas billing 

records is in units of therms or mmBtu. 

Use of Equation C–2b. We are 

amending 40 CFR 98.33(a)(2)(ii), to 

require calculation of a weighted HHV, 

using Equation C–2b, only for 

individual Tier 2 units with a maximum 

rated heat input capacity greater than or 

equal to 100 mmBtu/hr, and for groups 

of units that contain at least one unit of 

that size. For Tier 2 units smaller than 

100 mmBtu/hr and for aggregated 

groups of Tier 2 units under 40 CFR 

98.36(c)(1) in which all units in the 

group are smaller than 100 mmBtu/hr, 

we are allowing reporters to use either 

an annual arithmetic average HHV or an 

annual fuel-weighted average HHV in 

Equation C–2a. 

Categories of gaseous fuels. We have 

revised 40 CFR 98.34(a)(2)(iii) by 

replacing the term ‘‘fossil fuel-derived 

gaseous fuels’’ with a more inclusive 

term, i.e., ‘‘gaseous fuels other than 

natural gas.’’ Corresponding changes to 

Table C–1 were also made for 

consistency, placing blast furnace gas, 

coke oven gas, fuel gas, and propane in 

a new category, ‘‘Other fuels (gaseous).’’ 

Use of mass-based gas flow meters. 

The Tier 3 CO2 emissions calculation 

methodology in 40 CFR 98.33(a)(3) 

allows reporters to use flow meters that 

measure mass flow rates of liquid fuels 

to quantify fuel consumption, provided 

that they (the reporters) determine the 

density of the fuel and convert the 

measured mass of fuel to units of 

volume (i.e., gallons), for use in 

Equation C–4. In response to a number 

of requests, we are amending 40 CFR 

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

reporters to use flow meters that 

measure mass flow rates of gaseous fuels 

for Tier 3 applications, as well as for 

liquid fuels. A reporter wanting to use 

this option will have to measure the 

density of the gaseous fuel, either with 

a calibrated density meter or by using a 

consensus standard method or standard 

industry practice, in order to convert the 

measured mass of fuel to units of 

standard cubic feet, for use in Equation 

C–5. 

Site-specific stack gas moisture 

content values. We are amending 40 

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

site-specific moisture constants under 

the Tier 4 methodology. The sitespecific 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 

stack gas moisture content associated 

with different process operating 

conditions. Generally, for each sitespecific default moisture percentage, at 

least nine runs are required using EPA 

Method 4—Determination of Moisture 

Content In Stack Gases (40 CFR part 60, 

appendix A–3). Each site-specific 

default moisture value would be 

calculated by taking the arithmetic 

average of the Method 4 runs. Moisture 

data from the relative accuracy test 

audit (RATA) of a CEMS could be used 

for this purpose. The final rule does 

allow the site-specific moisture default 

values to be based on fewer than nine 

Method 4 runs in cases where moisture 

data from the RATA of a CEMS are used 

to derive the default value and the 

applicable regulation allows a single 

moisture run to represent two or more 

RATA runs. 

Each site-specific moisture default 

value must be updated at least annually 

and whenever the reporter determines 

the current value is non-representative 

due to changes in unit or process 

operation. The updated moisture value 

must be used in the subsequent CO2

emissions calculations. 

Determining emissions from an 

exhaust stream diverted from a CEMS 

monitored stack. We are finalizing 

amendments to 40 CFR 98.33(a)(4) by 

adding a new paragraph, (a)(4)(viii), to 

address the determination of CO2 mass 

emissions from a unit subject to the Tier 

4 calculation methodology when a 

portion of the flue gases generated by 

the unit exhaust through a stack that is 

not equipped with a CEMS to measure 

CO2 emissions (herein referred to as an 

‘‘unmonitored stack’’). The final 

amendments require annual emission 

testing of a diverted gas stream to be 

performed at a set point that best 

represents normal operation, using EPA 

Methods 2 and 3A and (if moisture 

correction is necessary) Method 4. A 

CO2 mass emission rate is calculated 

from the test results. If, over time, flow 

rate of the diverted stream varies little 

from the tested flow rate, then the 

annual CO2 mass emissions for the 

diverted stream (which must be added 

to the CO2 mass emissions measured at 

the main stack) are determined simply 

by multiplying the CO2 mass emission 

rate from the emission testing by the 

number of operating hours in which a 

portion of the flue gas was diverted from 

the main flue gas exhaust system. 

However, if the flow rate of the diverted 

stream varies significantly over the 

reporting year, the owner or operator 

must either perform additional stack 

testing or use the best available 

information (e.g., fan settings and 

damper positions) and engineering 

judgment to estimate the CO2 mass 

emission rate at a minimum of two 

additional set points, to represent the 

variation across the normal operating 

range. Then, the most appropriate CO2

mass emission rate must be applied to 

each hour in which a portion of flue gas 

is diverted from the main exhaust 

system. The procedures used to 

determine the annual CO2 mass 

emissions for the diverted stream must 

be documented in the GHG monitoring 

plan. 

Biomass combustion in Part 75 units 

using the CO2 calculation 

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

We are amending 40 CFR 

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

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

paragraph numbering error in subpart C, 

because this paragraph applies to all of 

40 CFR 98.33(a)(5) and not just to 40 

CFR 98.33(a)(5)(iii). 

We had proposed to amend 40 CFR 

98.3(c) in subpart A and 40 CFR 

98.33(a)(5) to clarify that the separate 

reporting of biogenic CO2 is optional for 

units that are not subject to the Acid 

Rain Program, but are using 40 CFR part 

75 methodologies to calculate CO2 mass 

emissions, as described in 40 CFR 

98.33(a)(5)(i) through (a)(5)(iii). After 

considering the comments received on 

this proposal and other information (see 

EPA–HQ–OAR–2008–0508), however, 

we are finalizing language which makes 

it clear that reporting of biogenic CO2

emissions from these units is optional 

for reporting year 2010, and mandatory 


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thereafter. Please see the discussion in 

Section II.C of this preamble regarding 

separate reporting of biogenic emissions 

for units subject to 40 CFR part 75. 

Use of Tier 3. We are amending 40 

CFR 98.33(b)(3)(iii) to clarify that the 

paragraph applies also to common pipe 

configurations where at least one unit 

served by the common pipe has a heat 

input capacity greater than 250 mmBtu/ 

hr. 

We are also adding a new paragraph, 

(b)(3)(iv), to 40 CFR 98.33, requiring 

Tier 3 to be used when specified in 

another subpart of Part 98, regardless of 

unit size. For example, subpart Y 

requires certain units that combust fuel 

gas to use Equation C–5 in subpart C 

(which is the Tier 3 equation for gaseous 

fuel combustion) to calculate CO2 mass 

emissions, without regard to unit size. 

Tier 4 monitoring threshold for units 

that combust MSW. We are amending 40 

CFR 98.33(b)(4)(ii)(A) to change the Tier 

4 monitoring threshold from 250 tons 

MSW per day to 600 tons MSW per day, 

based on analysis that this value is 

approximately equivalent to the 250 

mmBtu/hr Tier 4 heat input threshold 

for other large stationary combustion 

units. Units less than 600 tons MSW per 

day that do not meet the requirements 

in 40 CFR 98.33(b)(4)(iii) are allowed to 

use Tier 2 to calculate CO2 mass 

emissions (specifically, Equation C–2c). 

Applicability of Tier 4 to common 

stack configurations. We are amending 

40 CFR 98.33(b)(4) by adding provisions 

to clarify how the Tier 4 criteria apply 

to common stack configurations. 

Paragraph (b)(4)(i) is expanded to 

include monitored common stack 

configurations that consist of stationary 

combustion units, process units, or both 

types of units. A new paragraph, 

(b)(4)(iv) is also added describing the 

following three distinct common stack 

configurations to which Tier 4 might 

apply. 

The first, most basic configuration is 

one in which the combined effluent gas 

streams from two or more stationary fuel 

combustion units are vented through a 

monitored common stack (or duct). In 

this case, Tier 4 applies if the following 

conditions are met: 

• There is at least one large unit in 

the configuration that has a maximum 

rated heat input capacity greater than 

250 mmBtu/hr or an input capacity 

greater than 600 tons/day of MSW (as 

applicable). 

• At least one large combustion unit 

in the configuration meets the 

conditions of 40 CFR 98.33(b)(4)(ii)(A) 

through (b)(4)(ii)(C). 

• The CEMS installed at the common 

stack (or duct) meets all of the 

requirements of 40 CFR 98.33 

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

Tier 4 also applies when all of the 

combustion units in the configuration 

are small (not greater than 250 mmBtu/ 

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

one of the units meets the conditions of 

40 CFR 98.33(b)(4)(iii). 

The second configuration is one in 

which the combined effluent gas 

streams from a stationary combustion 

unit and a process or manufacturing 

unit are vented through a common stack 

or duct. Many subparts of Part 98 

describe this situation (see subparts F, 

G, K, Q, Z, BB, EE, and GG). In this case, 

the use of Tier 4 is required if the 

stationary combustion unit and the 

monitors installed at the common stack 

or duct meet the applicability criteria of 

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

If multiple stationary combustion units 

and a process unit (or units) are vented 

through a common stack or duct, Tier 4 

is required if at least one of the 

combustion units and the monitors 

installed at the common stack or duct 

meet the conditions of 40 CFR 

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

The third configuration is one in 

which the combined effluent streams 

from two or more process or 

manufacturing units are vented through 

a common stack or duct. In this case, if 

any of these units is required to use Tier 

4 under an applicable subpart of Part 98, 

the owner or operator can either 

monitor the CO2 mass emissions at the 

Tier 4 unit(s) before the effluent streams 

are combined together, or monitor the 

combined CO2 mass emissions from all 

units at the common stack or duct. 

However, if it is not feasible to monitor 

the individual units, the combined CO2

mass emissions will have to be 

monitored at the common stack or duct, 

using Tier 4. 

Starting dates for the use of Tier 4. In 

the October 30, 2009 final rule, 40 CFR 

98.33(b)(5) of subpart C states that units 

that are required to use the Tier 4 

methodology must begin using it on 

January 1, 2010 if all required CEMS are 

in place. Otherwise, use of Tier 4 begins 

on January 1, 2011, and Tier 2 or Tier 

3 may be used to report CO2 mass 

emissions in 2010. We are amending 40 

CFR 98.33(b)(5) to clarify that sources 

can begin monitoring CO2 emissions 

data prior to January 1, 2011 from CEMS 

that successfully complete certification 

testing in 2010. Note that changes in 

methodology during a reporting year are 

allowed by Part 98, and must be 

documented in the annual GHG 

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

This revision will allow sources to 

discontinue using Tier 2 or 3 and begin 

reporting their 2010 emissions under 

Tier 4 as of the date on which all 

required certification tests are passed. 

Data recorded during the certification 

test period for a CEMS can also be used 

for Part 98 reporting, provided that: All 

required certification tests are passed in 

sequence, with no test failures; and no 

unscheduled maintenance or repair of 

the CEMS is required during the test 

period. 

We are also amending 40 CFR 

98.33(b)(5) by adding a new paragraph, 

(b)(5)(iii), to address situations where 

the owner or operator of an affected unit 

that has been using Tier 1, 2, or 3 to 

calculate CO2 mass emissions makes a 

change that triggers Tier 4 applicability 

by changing: The primary fuel, the 

manner of unit operation, or the 

installed continuous monitoring 

equipment. In such cases, the owner or 

operator will be required to begin using 

Tier 4 no later than 180 days from the 

date on which the change is 

implemented. This allows adequate 

time for the owner or operator to obtain 

and/or certify any of the required Tier 

4 continuous monitors. 

Methane and nitrous oxide 

calculations. Today’s amendments 

remove the term ‘‘normal operation’’ 

from 40 CFR 98.33(c)(4)(i) and (c)(4)(ii). 

Therefore, calculation of CH4 and N2O 

emissions is simply required for each 

Table C–2 fuel combusted in the unit 

during the reporting year. 

We are also further amending 40 CFR 

98.33(c)(4)(ii), to allow additional 

reporting flexibility for certain units that 

combust more than one type of fuel; 

specifically, for units that report heat 

input data to EPA year-round using part 

75 CEMS. Under the final amendments 

to 40 CFR 98.33(c)(4)(ii), 40 CFR part 75 

units that use the worst-case F-factor 

reporting option can attribute 100 

percent of the unit’s annual heat input 

to the fuel with the highest F-factor, as 

though it were the only fuel combusted 

during the report year. 

For Tier 4 units, the requirement to 

use the best available information to 

determine the annual heat input from 

each type of fuel is being retained in 40 

CFR 98.33(c)(4)(i), but we are also now 

allowing it under 40 CFR 

98.33(c)(4)(ii)(D) as an alternative for 

part 75 units, in cases where fuelspecific heat input values cannot be 

determined solely from the part 75 

electronic data reports. 

Carbon dioxide emissions from 

sorbent. We are amending 40 CFR 

98.33(d) to make it more generally 

applicable to different types of CO2- 

producing sorbents. The term ‘‘R’’ is 

redefined as the number of moles of CO2

released upon capture of one mole of 

acid gas. When the sorbent is CaCO3, the 


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value of R is 1.00. For other CO2- 

producing sorbents, a specific value of 

R is 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. 

The title and introductory text of 40 

CFR 98.33(e) are being amended to more 

precisely define the requirements for 

reporting biogenic CO2 emissions. In 

general, biogenic CO2 emissions 

reporting is required only for the 

combustion of the biomass fuels listed 

in Table C–1 and for municipal solid 

waste (which consists partly of biomass 

and partly of fossil fuel derivatives). 

We are also amending 40 CFR 98.33(e) 

to describe three cases in which 

reporters may not need to report 

biogenic CO2 emissions separate from 

total CO2 emissions, for units that 

combust biomass: 

1. If a biomass fuel is not listed in 

Table C–1 and is combusted in a unit 

that is not required to use Tier 4, a 

reporter is not required to separately 

report the biogenic CO2 emissions from 

combustion of that fuel unless: 

—The fuel is combusted in a large unit 

(greater than 250 mmBtu/hr heat 

input capacity). 

—The biomass fuel accounts for 10 

percent or more of the annual heat 

input to the unit. 

In that case, according to 40 CFR 

98.33(b)(3)(iii), Tier 3 must be used to 

determine the carbon content of the 

biomass fuel and to calculate the 

biogenic CO2 emissions. 

2. If a unit is subject to subpart C or 

D and uses the CO2 mass emissions 

calculation methodologies in 40 CFR 

part 75 to satisfy the Part 98 reporting 

requirements, the reporter has the 

option to report biogenic CO2 emissions 

for the 2010 reporting year, but is 

required to report them thereafter. 

3. For the combustion of tires, which 

are also partly biogenic (typically about 

20 percent biomass, for car and truck 

tires), the reporter has the option, but 

not the requirement, to separately report 

the biogenic CO2 emissions, by 

following the applicable provisions in 

40 CFR 98.33(e). 

No comments were received on the 

proposal to make biogenic CO2

emissions reporting optional for the 

combustion of tires, and the proposal 

has been finalized without modification. 

However, tire-derived fuel has a 

biomass component, and perhaps it 

should be treated in the same manner as 

MSW, which is also partly biogenic. A 

number of units that are subject to Part 

98 combust tires as the primary fuel or 

as a secondary fuel. Therefore, we are 

considering whether these units should 

be required to account for their biogenic 

CO2 emissions. However, before making 

this mandatory we intend to open it to 

notice and comment in a future 

rulemaking. 

We are amending 40 CFR 98.33(e)(1) 

by removing the restriction against 

using Tier 1 to calculate biogenic CO2

emissions on units that use CEMS to 

measure the total CO2 mass emissions. 

However, the use of Tier 1 is not 

allowed for calculating biogenic CO2

emissions for combustion of MSW, as 

originally specified in 40 CFR 

98.33(e)(1) of subpart C, and is also not 

allowed for the combustion of tires, if 

biogenic CO2 emissions are calculated 

for tires. 

We are amending the methodology in 

40 CFR 98.33(e)(2), which is specifically 

for units using a CEMS to measure CO2

mass emissions, by limiting it to cases 

where the CO2 emissions measured by 

the CEMS are solely from combustion, 

i.e., the stack gas contains no additional 

process CO2 or CO2 from sorbent; and 

prohibiting its use if the unit combusts 

MSW or tires. 

For sources that combust MSW, we 

are amending 40 CFR 98.33(e)(3) to 

require, except as provided below, the 

quarterly use of ASTM methods D7459– 

08 and D6866–08, as described in 40 

CFR 98.34(d), when any MSW is 

combusted either as the primary fuel or 

as the only fuel with a biogenic 

component. We are also amending 40 

CFR 98.33(e)(3) to allow the ASTM 

methods to be used, as described in 40 

CFR 98.34(e), for any unit in which 

biogenic (or partly biogenic) fuels, and 

non-biogenic fuels are combusted, in 

any proportions. 

In response to comments, we have 

added an alternative calculation 

methodology for biogenic CO2 emissions 

from the combustion of MSW and/or 

tires, which may be used when the total 

contribution of these fuels to the unit’s 

heat input is 10 percent or less. If a unit 

combusts both MSW and tires and the 

reporter exercises the option not to 

separately report biogenic CO2

emissions from the tires, the alternative 

calculation methodology may still be 

used for the MSW, provided that the 

contribution of MSW to the unit’s total 

heat input does not exceed 10 percent. 

The methodology may also be used for 

small, batch incinerators that burn no 

more than 1,000 tons of MSW per year. 

Units that qualify for and elect to use 

the alternative methodology will use 

Tier 1 to calculate the total annual CO2

emissions from the combustion of the 

MSW or tires, and multiply the result by 

an appropriate default factor that 

represents the biomass fraction of the 

fuel, to obtain an estimate of the annual 

biogenic CO2 emissions. Based on 

additional background research 

conducted, we have concluded that 

reasonable default factors are 0.20 for 

tires and 0.60 for MSW (please refer to 

the Background Technical Support 

Document—Revision of Certain 

Provisions). 

We are also amending 40 CFR 98.33(e) 

to delete and reserve 40 CFR 98.33(e)(4) 

and the related subparagraphs. 

Although 40 CFR 98.33(e)(4) allowed 

the ASTM methods to be used to 

determine biogenic CO2 emissions for 

various combinations of biogenic and 

fossil fuels, we are deleting and 

reserving that paragraph because the 

paragraph also included an unnecessary 

restriction, i.e., it only applied to units 

that use CEMS to measure total CO2

mass emissions. The amendments to 40 

CFR 98.33(e)(3) described above will 

achieve the same intended purpose as 

paragraph (e)(4), without imposing this 

restriction, so paragraph (e)(4) is no 

longer needed. 

We are amending 40 CFR 98.33(e)(5) 

so that it also applies to units that are 

using Tier 2 (Equation C–2a), as well as 

Tier 1 (Equation C–1), for calculating 

biogenic CO2 mass emissions. The 

approach in 40 CFR 98.33(e)(5) for 

estimating solid biomass fuel 

consumption is equally applicable to 

units using those two equations to 

calculate biogenic CO2 emissions. 

Equation C–2a applies when HHV data 

for a biomass fuel are available at the 

minimum frequency specified in 40 CFR 

98.34(a)(2). 

Finally, one commenter asked EPA to 

allow Part 75 units to calculate biogenic 

CO2 emissions using the same general 

approach that is used in 40 CFR 

98.33(c)(4)(ii) for the CH4 and N2O 

emissions calculations. This requires a 

heat input-based equation similar to 

Equation C–10 to be added to the rule. 

We find this request to be reasonable 

and have added a new paragraph, (e)(6), 

to 40 CFR 98.33(e). Paragraph (e)(6) 

provides the required equation, i.e., 

Equation C–15a. In cases where (HI)A, 

the fraction of unit heat input from 

combustion of the biomass fuel, cannot 

be determined from the information in 

Part 75 electronic data reports (e.g., for 

units that measure the total CO2

emissions with CEMS, if the ‘‘worstcase’’ F-factor option is used, or if 

biomass and fossil fuels with identical 

F-factors are combusted), facilities must 

use the ‘‘best available information’’ (as 

described in 40 CFR 98.33(c)(4)(ii)(C) 

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


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79110 Federal Register / Vol. 75, No. 242 / Friday, December 17, 2010 / Rules and Regulations 

Fuel sampling for coal and fuel oil. 

We are amending 40 CFR 98.34(a)(2), to 

clarify the frequency at which the HHV 

needs to be determined for different 

types of fuels. 

First, we are amending 40 CFR 

98.34(a)(2)(ii) to expand the list of fuels 

for which sampling of each fuel lot is 

sufficient to include other solid or 

liquid fuels that are delivered in lots. 

Second, we are amending the 

definition of the term ‘‘fuel lot’’ in 40 

CFR 98.34(a)(2)(ii), as it pertains to 

facilities that receive multiple deliveries 

of a particular type of fuel from the 

same supply source each month, either 

by truck, rail, or pipeline. The 

amendment clarifies that a fuel lot 

consists of all of the deliveries of that 

fuel for a given calendar month. Thus, 

for these facilities, the required HHV 

sampling has to be no more frequent 

than once per month. We did receive 

requests to clarify the meaning of the 

terms ‘‘type of fuel’’ and ‘‘supply source,’’ 

pertaining to the proposal to require 

only one monthly sample to represent 

multiple fuel deliveries. The final rule 

clarifies that for coal, the type of fuel 

refers to the coal rank (i.e., anthracite, 

bituminous, sub-bituminous, or lignite). 

For fuel oil, the type of fuel refers to the 

grade number or classification of the oil 

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

The term ‘‘supply source’’ is not so 

easily defined. For the reasons set forth 

in the Response to Comments (Section 

II.G.2 of this preamble), we have chosen 

not to include a definition of ‘‘supply 

source’’ in the final rule. 

Third, we are adding parallel 

language to 40 CFR 98.34(b)(3)(ii), the 

Tier 3 fuel sampling provisions for coal 

and fuel oil, for consistency with the 

revisions to 40 CFR 98.34(a)(2)(ii). 

Finally, we are amending 40 CFR 

98.34(a)(2)(ii) and 40 CFR 98.34(b)(3)(ii) 

to allow manual oil samples to be taken 

after each addition of oil to the storage 

tank. Daily manual sampling, flowproportional sampling, and continuous 

drip sampling are also allowed. The 

final rule requires at least one sample to 

be obtained from each storage tank that 

is currently in service, and whenever oil 

is added, for as long as the tank remains 

in service. If multiple additions (e.g., 

from multiple deliveries) are made on a 

given day, taking one sample after the 

final addition is sufficient. No sampling 

is required for addition of fuel to a tank 

that is out of service. Rather, a sample 

must be taken when the tank is brought 

into service and whenever oil is added 

to the tank, for as long as the tank 

remains in service. If the daily manual 

sampling option is implemented, 

sampling from a particular tank is 

required only on those days when oil 

from that tank is combusted in the 

unit(s). 

Tier 3 sampling frequency for gaseous 

fuels. 

We are amending 40 CFR 

98.34(b)(3)(ii)(E) to clarify that daily 

sampling of gaseous fuels other than 

natural gas and biogas for carbon 

content and molecular weight is only 

required where continuous, on-line 

equipment is in place; weekly sampling 

is required in all other cases. 

GHG emissions from blended fuel 

combustion. One of the most frequently 

asked questions by the regulated 

community since publication of the 

October 30, 2009 final Part 98 is, ‘‘How 

does one calculate CO2 mass emissions 

from the combustion of blended fuels?’’ 

Subpart C provided only limited 

guidance on this issue. We are now 

finalizing amendments to 40 CFR 

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

clarify reporting requirements for 

calculating emissions from blended 

fuels. The amendments make a clear 

distinction between cases where the 

mass or volume of each fuel in the blend 

is accurately measured prior to mixing 

(e.g., using individual flow meters for 

each component) and cases where the 

exact composition of the blend is not 

known. In the former case, the fact that 

the fuels are blended is of no 

consequence; because the exact quantity 

of each fuel in the blend is known, the 

CO2 emissions from combustion of each 

component must be calculated 

separately. In the latter case, the blend 

is considered to be a distinct ‘‘fuel type,’’ 

and the reporter must measure its mass 

or volume and essential properties (e.g., 

HHV, carbon content, etc.) at a 

prescribed frequency. 

When the mass or volume of each 

individual component of a blend is not 

precisely known prior to mixing, the 

appropriate method used to calculate 

the CO2 mass emissions from 

combustion of the blend is as follows. 

For smaller combustion units (heat 

input capacity not more than 250 

mmBtu/hr), Tier 2 (or possibly Tier 1) 

can be used when all components of the 

blend are listed in Table C–1 of subpart 

C. In order to perform these CO2

emissions calculations for the blend, a 

reasonable estimate of the percentage 

composition of the blend would be 

required, using the best available 

information (e.g., from the typical or 

expected range of values of each 

component). A heat-weighted CO2

emission factor must be calculated, 

using new Equation C–16. For Tier 1 

applications, a heat-weighted default 

HHV must be determined, using new 

Equation C–17. 

In cases where a fuel blend consists 

of a mixture of fuel(s) listed in Table C– 

1 and fuel(s) not listed in Table C–1, 

calculation of CO2 and other GHG 

emissions from combustion of the blend 

is required only for the Table C–1 

fuel(s), using the best available estimate 

of the mass or volume percentage(s) of 

the Table C–1 fuel(s) in the blend. In 

these cases, the use of Tier 1 is required, 

with modifications to certain terms in 

Equations C–17 and C–1, to account for 

the fact that the blend is not composed 

entirely of Table C–1 fuels. An example 

calculation is provided in 40 CFR 

98.34(a)(3)(iv). 

For larger combustion units (heat 

input capacity greater than 250 mmBtu/ 

hr) that do not qualify to use Tier 1 or 

2, the owner or operator must use Tier 

3 to calculate the CO2 mass emissions 

from combustion of a blended fuel. The 

mathematics for Tier 3 are simpler than 

for Tiers 1 and 2, since no default values 

are used in the calculations, and an 

estimate of the percentage composition 

of the blend is not required. To apply 

Tier 3, the only requirements are to 

accurately measure the annual 

consumption of the blended fuel and to 

determine its carbon content and (if 

necessary) molecular weight, at a 

prescribed frequency. By considering 

the blended fuel to be a distinct ‘‘fuel 

type,’’ in cases where that fuel is not 

listed in Table C–1, GHG emissions 

reporting is required in accordance with 

40 CFR 98.33(b)(3)(iii), if the blended 

fuel (as opposed to each individual 

component of the blend) provides at 

least 10 percent of the annual heat input 

to a unit or group of units, and if the use 

of Tier 4 is not required. 

To address the calculation of CH4 and 

N2O mass emissions from the 

combustion of blended fuels, we are 

adding a new paragraph, (c)(6), to 40 

CFR 98.33. Calculation of CH4 and N2O 

emissions is required only for 

components of a blend that are listed in 

Table C–2 of subpart C. 

If the mass or volume of each 

component of a blend is measured 

before the fuels are mixed and 

combusted, the existing CH4 and N2O 

mass emissions calculation procedures 

in 40 CFR 98.33(c)(1) through (5) must 

be followed for each component 

separately. The fact that the fuels are 

mixed prior to combustion is of no 

consequence in this case. 

If the mass or volume of each 

individual component is not measured 

prior to mixing, a reasonable estimate of 

the percentage composition of the blend 

is required, based on the best available 

information, and the procedures in 40 

CFR 98.33(c)(6)(ii) will be followed. 

First, the annual consumption of each 


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component fuel in the blend is 

calculated by multiplying the total 

quantity of the blend combusted during 

the reporting year by the estimated mass 

or volume percentage of that 

component. Next, the annual heat input 

from the combustion of each component 

is calculated by multiplying its annual 

consumption by the appropriate HHV 

(either the default HHV from Table C– 

1 or, if available, the measured annual 

average value). The annual CH4 and N2O 

mass emissions for each component 

must then be calculated using the 

applicable equation in 40 CFR 98.33(c), 

i.e., Equation C–8, C–9a, or C–10. 

Finally, the calculated CH4 and N2O 

emissions are summed across all 

components, and these sums are 

reported as the annual CH4 and N2O 

mass emissions for the blend. 

Use of consensus standard methods. 

We are amending 40 CFR 98.33(a)(3)(iv) 

and (a)(3)(v) to remove reference to 

specific standard methods and allow the 

use of standards from consensus-based 

organizations or industry standard 

practice. We are amending 40 CFR 98.34 

to remove the specific ASTM and GPA 

method list for fuel sampling and 

analysis in 40 CFR 98.34(a)(6), to 

remove the list of American Gas 

Association (AGA) and American 

Society of Mechanical Engineers 

(ASME) methods for fuel meter 

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

delete the list of ASTM methods to 

determine carbon content and molecular 

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

also redesignating 40 CFR 98.34(b)(5) as 

40 CFR 98.34(b)(4), and amending 

newly designated 40 CFR 98.34(b)(4). 

Finally, we are amending 40 CFR 

98.34(b)(1)(A) to remove the crossreference to the fuel flow meter test 

methods listed in 40 CFR 98.34(b)(4). 

These amendments allow the owner or 

operator to use manufacturers’ 

procedures, appropriate methods 

published by consensus-based standards 

organizations such as ASTM, ASME, 

American Petroleum Institute (API), 

AGA, ISO, etc.; or use industry-accepted 

practice. The methods used must be 

documented in the monitoring plan 

under 40 CFR 98.3(g)(5). 

CO2 monitor span values. The Tier 4 

calculation method in 40 CFR 

98.33(a)(4) requires a CO2 concentration 

monitor and a stack gas flow rate 

monitor to measure CO2 mass 

emissions. The CO2 monitor must be 

certified and quality-assured 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. However, 

when CO2 emissions from an industrial 

process (e.g., cement manufacturing) are 

combined with combustion CO2

emissions, the resultant CO2

concentration in the stack gas can be 

substantially higher than for the 

combustion emissions alone. In such 

cases, a span value of 30 percent CO2 (or 

higher) may be required. 

When the CO2 span exceeds 20 

percent CO2, the CGA concentrations 

specified in Part 60 only evaluate the 

lower portion of the measurement scale 

and are no longer representative. 

Therefore, we are amending 40 CFR 

98.34(c) by adding a new paragraph 

(c)(6), which allows the CGA of a CO2

monitor to be performed using 

calibration gas concentrations of 40 to 

60 percent of span and 80 to 100 percent 

of span, when the CO2 span value is set 

higher than 20 percent CO2. 

CEMS data validation. In subpart C, 

40 CFR 98.34(c) provides the monitoring 

and QA requirements for Tier 4. 

However, no criteria for hourly CEMS 

data validation were specified in the 

final rule. We are adding a new 

paragraph, (c)(7), to 40 CFR 98.34, 

which requires hourly CEMS data 

validation to be consistent with the 

sections of 40 CFR part 60 or part 75 

cited in the preceding paragraph of this 

preamble. Alternatively, the hourly data 

validation procedures in an applicable 

State CEM program can be followed. 

Use of ASTM Methods D7459–08 and 

D6866–08. Sections 98.34(d) and (e) of 

subpart C, respectively, outline 

procedures for quantifying biogenic CO2

emissions for units that combust MSW 

and other units that combust 

combinations of fossil fuels and 

biomass. Flue gas samples are taken 

quarterly using ASTM Method D7459– 

08 and analyzed using ASTM Method 

D6866–08. We are amending 40 CFR 

98.34(d) and (e), as discussed in the 

following paragraphs. 

The amendments to 40 CFR 98.34(d) 

require the ASTM methods to be used 

when MSW is combusted in a unit, 

either as the primary fuel, or as the only 

fuel with a biogenic component, unless 

the unit qualifies for the alternative Tier 

1 calculation methodology described 

above, under ‘‘Biogenic CO2 emissions 

from biomass combustion.’’ Quarterly 

sampling with ASTM Method D7459–08 

is required for a minimum of 24 

cumulative hours of sampling per 

quarter, except as provided below. 

We are amending 40 CFR 98.34(e) to 

remove the restriction limiting the use 

of ASTM Methods D7459–08 and 

D6866–08 to units with CEMS. Rather, 

any unit that combusts combinations of 

fossil and biogenic fuels (or partly 

biogenic fuels, such as tires), in any 

proportions, is allowed to determine 

biogenic CO2 emissions using the ASTM 

methods on a quarterly basis. At least 24 

cumulative hours of sampling per 

quarter are required, except as provided 

immediately below. 

We are adding an option to 40 CFR 

98.34(d) and (e), allowing sources to 

demonstrate that 8 hours of sampling 

per quarter is sufficient. The 

demonstration requires a minimum of 

two 8-hour tests and one 24-hour test, 

performed under normal, stable 

operating conditions. The 

demonstration tests must be distinct, 

i.e., no overlapping of the 8-hour and 

24-hour test periods is permitted. If the 

average biogenic fraction obtained from 

the 8-hour tests is within ±5 percent of 

the results from the 24-hour test, then, 

in subsequent quarters, the Method 

D7459–08 sampling time may be 

reduced to 8 hours. The results of the 

demonstration must be documented in 

the monitoring plan. 

We are also amending 40 CFR 

98.34(d) by adding an alternative to 

allow the owner or operator to collect an 

integrated sample by extracting a small 

amount of flue gas (1 to 5 cubic 

centimeters (cc)) during every unit 

operating hour in the quarter, in order 

to obtain a more representative sample 

for analysis. 

Procedures for estimating missing 

data. We are amending 40 CFR 98.35(a) 

to clarify that the missing data 

procedures in 40 CFR part 75 are only 

to be followed by units that are in the 

Acid Rain Program and those that 

monitor and report emissions and heat 

input data year round. Units that only 

monitor and report during the ozone 

season must follow the missing data 

procedures in 40 CFR 98.35(b). 

Electronic data reporting and 

recordkeeping. We are amending the 

data element lists in 40 CFR 98.36 by 

adding a number of essential data 

elements and eliminating or modifying 

others. The most significant revisions to 

the data element lists are summarized in 

the following paragraphs. We are also 

adding an alternative reporting option to 

40 CFR 98.36(c) to reduce the reporting 

burden for certain facilities. 

We are adding the reporting of 

methodology start and end dates in 

several places throughout 40 CFR 

98.36(b), (c), and (d). 

We are amending the data element 

lists in 40 CFR 98.36 to be consistent 


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79112 Federal Register / Vol. 75, No. 242 / Friday, December 17, 2010 / Rules and Regulations 

with respect to reporting of emissions 

by fuel type and reporting of biogenic 

CO2 emissions. Specifically, for clarity 

and consistency with the changes to 40 

CFR 98.3(c), we have modified the 

amendments to 40 CFR 98.36(d)(1)(ii), 

(d)(1)(ix), (d)(2)(ii)(I), and (d)(2)(iii)(I) 

from the proposal. These sections state 

that for units subject to 40 CFR part 75, 

reporting of biogenic CO2 emissions is 

optional only for the 2010 reporting 

year. Reporting of these emissions 

becomes mandatory starting with the 

2011 reporting year. 

We are removing 40 CFR 98.36(b)(10) 

to remove the requirement to report the 

customer meter number for units that 

combust natural gas. 

We are finalizing requirements in 40 

CFR 98.36(c)(1)(ii) that only the 

maximum rated heat input capacity of 

the largest unit in a group must be 

reported. We are also finalizing 

requirements for 98.36(c)(3) in a similar 

manner, for groups of units served by a 

common pipe. 

We are amending 40 CFR 98.36 to 

remove the requirement to report the 

combined annual GHG emissions from 

fossil fuel combustion in metric tons of 

CO2e (i.e., the sum of the CO2, CH4, and 

N2O emissions) by removing 40 CFR 

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

(c)(3)(viii). These data elements were 

duplicative of requirements in subpart 

A. 

We are amending 40 CFR 98.36(b), (c), 

and (d) to require reporting the fuelspecific annual heat input estimates, for 

the purpose of verifying the reported 

CH4 and N2O emissions. Also, we are 

amending 40 CFR 98.36(e)(2)(iv) to 

require reporting of the annual average 

HHV when measured HHV data are 

used to calculate CH4 and N2O 

emissions for a Tier 3 unit, in lieu of 

using a default HHV from Table C–1. 

We are amending 40 CFR 98.36(b) and 

(d) to make the data elements reported 

under Tiers 1 through 4 consistent for 

the reporting of biogenic CO2 emissions 

and CO2 from fossil fuel combustion. 

Also, as previously noted in Section II.C 

of this preamble, the amendments to 40 

CFR 98.36(d) state that reporting of 

biogenic CO2 emissions is optional only 

for the 2010 reporting year for units 

using the CO2 mass emissions 

calculation methods in 40 CFR part 75. 

For units that use the Tier 4 

methodology to calculate CO2 mass 

emissions, we are amending 40 CFR 

98.36(b)(7)(i) and (b)(7)(ii) (redesignated 

as 40 CFR 98.36(b)(9)(i) and (b)(9)(ii), 

respectively) and 40 CFR 98.36(c)(2)(vi) 

(redesignated as 40 CFR 98.36 

(c)(2)(viii)). The amendments to these 

sections require the annual ‘‘nonbiogenic’’ CO2 mass emissions to be 

reported instead of reporting the annual 

CO2 mass emissions from fossil fuel 

combustion. 

We are adding a new alternative 

reporting option, under 40 CFR 

98.36(c)(4). This new option applies to 

specific situations where a common 

liquid or gaseous fuel supply is shared 

between large combustion units such as 

boilers or combustion turbines 

(including Acid Rain Program units and 

other combustion units that use the 

methods in 40 CFR part 75 to calculate 

CO2 mass emissions), and small 

combustion sources such as space 

heaters, hot water heaters, etc. In such 

cases, a source can simplify reporting by 

attributing all of the GHG emissions 

from combustion of the shared fuel to 

the large combustion unit(s), provided 

that: 

• The total quantity of the shared fuel 

supply that is combusted during the 

report year is measured, either at the 

‘‘gate’’ to the facility or at a point inside 

the facility, using a fuel flow meter, a 

billing meter or tank drop 

measurements; and 

• On an annual basis, at least 95 

percent of the shared fuel supply (by 

mass or volume) is burned in the large 

combustion unit(s) and the remainder of 

the fuel is fed to the small combustion 

sources. 

Company records can be used to 

determine the percentage distribution of 

the shared fuel to the large and small 

units. Facilities using this reporting 

option are required to document in their 

monitoring plan which units share the 

common fuel supply and the method 

used to determine that the reporting 

option applies. For the small 

combustion sources, a description of the 

type(s) and approximate number of 

units involved is sufficient. 

Finally, we are amending 40 CFR 

98.36(e)(2)(iii) to simplify the 

recordkeeping requirements in cases 

where the results of fuel analyses for 

HHV are provided by the fuel supplier. 

Parallel language is added in a new 

paragraph, 40 CFR 98.36(e)(2)(v)(E), for 

the results of carbon content and 

molecular weight analyses received 

from the fuel supplier. In both cases, the 

owner or operator is required to keep 

records of only the dates on which the 

fuel sampling results are received, 

rather than keeping records of the dates 

on which the supplier’s fuel samples 

were taken (which may not be readily 

available). 

Common stack reporting option. 

Section 98.36(c)(2) of subpart C allows 

subpart C stationary fuel combustion 

units that share a common stack or duct 

to use the Tier 4 Calculation 

Methodology to monitor and report the 

combined CO2 mass emissions at the 

common stack or duct, in lieu of 

monitoring each unit individually. 

However, 40 CFR 98.36(c)(2) does not 

address circumstances where at least 

one of the units sharing the common 

stack is not a subpart C stationary fuel 

combustion unit, but is subject to 

another subpart of 40 CFR part 98. In 

view of this, we are amending 40 CFR 

98.36(c)(2) by extending the 

applicability of the common stack 

monitoring and reporting option to 

situations where off-gases from multiple 

process units or mixtures of combustion 

products and process off-gases are 

combined together and vented through 

a common stack or duct. 

The amendments to 40 CFR 

98.36(c)(2) apply not only to ordinary 

common stack or duct situations where 

the gas streams from multiple units are 

combined together, but also apply when 

combustion and/or process off-gas 

streams from a single unit (e.g., from a 

kiln, furnace, petrochemical process 

unit, or smelter) are routed to a stack. 

To accommodate this variation on the 

concept of a common stack, 40 CFR 

98.36(c)(2)(ii) is amended to require 

sources to report ‘‘1’’ as the ‘‘Number of 

units sharing the common stack or duct’’ 

where combustion and/or process 

emissions from a single unit are vented 

through the same stack or duct. 

Finally, since the concept of 

maximum rated heat input capacity may 

not be applicable to certain types of 

process or manufacturing units, we are 

amending 40 CFR 98.36(c)(2)(iii), to 

require that the ‘‘combined maximum 

rated heat input capacity of the units 

sharing the common stack or duct’’ only 

be reported when all of the units sharing 

the common stack or duct are stationary 

fuel combustion units. 

Common fuel supply pipe reporting 

option. Section 98.36(c)(3) of subpart C 

allows units that are served by a 

common fuel supply pipe to report the 

combined CO2 emissions from all of the 

units in lieu of reporting CO2 emissions 

separately from each unit. To use this 

reporting option, the total amount of 

fuel combusted in the units must be 

accurately measured with a flow meter 

calibrated according to the requirements 

in 40 CFR 98.34. Section 98.36(c)(3) also 

states that the applicable tier to use for 

this reporting option is based on the 

maximum rated heat input of the largest 

unit in the group. 

We are amending 40 CFR 98.36(c)(3) 

as follows. First, the erroneous citation 

of ‘‘§ 98.34(a)’’ is corrected to read 

‘‘§ 98.34(b).’’ Second, we are amending 

the requirement in 40 CFR 98.36(c)(3) to 

calibrate the fuel flow meter to the 

accuracy required by 40 CFR 98.34(b) 


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(which cross-references the accuracy 

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

this calibration requirement applies 

only when Tier 3 is the required tier for 

calculating CO2 mass emissions. This is 

consistent with the final amendments to 

40 CFR 98.3(i), where we clarify that the 

equipment used to generate company 

records under Tier 1 and 2 is not 

required to meet the calibration 

accuracy specifications of 40 CFR 

98.3(i). 

The applicable measurement tier for 

the common pipe option, according to 

subpart C, is based on the rated heat 

input capacity of the largest unit in the 

group. On the surface, this appears to 

mean that the use of Tiers 1 and 2 is 

restricted to common pipe 

configurations where the highest rated 

heat input capacity of any unit is 250 

mmBtu/hr or less, and that Tier 3 is 

required if any unit has a maximum 

rated heat input capacity greater than 

250 mmBtu/hr. In general, this is true. 

However, there is one exception in the 

current rule and we are amending the 

rule to add a second one. Section 

98.33(b)(2)(ii) of the current rule allows 

the use of Tier 2 instead of Tier 3 for 

the combustion of natural gas and/or 

distillate oil in a unit with a rated heat 

input capacity greater than 250 mmBtu/ 

hr. Today’s rule adds a new paragraph, 

(b)(1)(v), to 40 CFR 98.33, allowing Tier 

1 to be used when natural gas 

consumption is determined from billing 

records, and fuel usage on those records 

is expressed in units of therms or 

mmBtu. Therefore, we are also 

amending 40 CFR 98.36(c)(3) to reflect 

these two exceptions for common pipe 

configurations that include a unit with 

a maximum rated heat input capacity 

greater than 250 mmBtu/hr. 

Finally, we are amending the 

provision in 40 CFR 98.36(c)(3) 

regarding the partial diversion of a fuel 

stream such as natural gas that is 

measured ‘‘at the gate’’ to a facility (e.g., 

using a calibrated flow meter or a gas 

billing meter). Subpart C specifies that 

when part of a fuel stream is diverted to 

a chemical or industrial process where 

it is used but not combusted, and the 

remainder of the fuel is sent to a group 

of combustion units, you may subtract 

the diverted portion of the fuel stream 

from the total quantity of the fuel 

measured at the gate before applying the 

common pipe methodology to the 

combustion units. We are amending the 

rule to expand this provision to include 

cases where the diverted portion of the 

fuel stream is sent either to a flare or to 

another stationary combustion unit (or 

units) on site, including units that use 

40 CFR part 75 methodologies to 

calculate annual CO2 mass emissions 

(e.g., Acid Rain Program units). 

Provided that the GHG emissions from 

the flare and/or other combustion 

unit(s) are properly accounted for 

according to the applicable subpart(s) of 

Part 98, you are allowed to subtract the 

diverted portion of the fuel stream from 

the total quantity of the fuel measured 

at the gate, and then apply the common 

pipe reporting option to the group of 

combustion units served by the common 

pipe, using the Tier 1, Tier 2, or Tier 3 

calculation methodology (as applicable). 

Table C–1. Table C–1 of subpart C 

provides default HHV values and 

default CO2 emission factors for various 

types of fuel. We are finalizing several 

amendments to Table C–1; specifically, 

we have: 

• Replaced the categories ‘‘fossil fuelderived fuels (solid)’’ and ‘‘fossil fuelderived fuels (gaseous)’’ with more 

inclusive terms, i.e., ‘‘other fuels (solid)’’ 

and ‘‘other fuels (gaseous).’’ The ‘‘other 

fuels (solid)’’ category includes four 

fuels: plastics, municipal solid waste, 

tires, and petroleum coke. The ‘‘other 

fuels (gaseous)’’ category includes blast 

furnace gas, coke oven gas, propane gas, 

and fuel gas. 

• Removed the word ‘‘pipeline’’ from 

the description of natural gas. 

• Retained the following fuels: ‘‘wood 

residuals,’’ ‘‘agricultural by-products,’’ 

and ‘‘solid by-products’’, and added 

definitions of these terms to 40 CFR 98.6 

(see section II.F of this preamble for 

further discussion). 

• Added ‘‘Used oil’’ to the list of 

petroleum products, and added a 

definition to 40 CFR 98.6 (see section 

II.F of this preamble for further 

discussion). 

• Removed ‘‘still gas’’ from the list of 

petroleum products and added ‘‘fuel 

gas.’’ 

• Corrected a typographic error in the 

HHV for ethane; changing it to 0.069 

mmBtu/gal, rather than 0.096 mmBtu/ 

gal. 

• Revised footnote 1 regarding 

municipal waste combustor (MWC) 

units to make it clear that only MWC 

units that produce steam are prohibited 

from using the default HHV for MSW in 

Table C–1; MWC units that produce 

steam can still use the default CO2

emission factor for MSW. 

• Modified footnote 1 to Table C–1, to 

reflect the new biogenic CO2 emissions 

calculation options for certain units that 

combust MSW and/or tires. 

• Revised footnote 2 to clarify that if 

the conditions in 40 CFR 98.243(d)(2)(i) 

and (d)(2)(ii) and 40 CFR 98.252(a)(1) 

and (a)(2) do not apply, reporters subject 

to 40 CFR 98.243(d) of subpart X or 

subpart Y shall use either Tier 3 or Tier 

4. 

• Remove the qualifier of 100 percent 

for ethanol and biodiesel. 

• Added a default CO2 emission 

factor and a default high heat value for 

petroleum-derived ethanol. These are 

the same as the default values for 

biomass-derived ethanol. 

Table C–2. We are finalizing the 

proposed amendments to remove the 

first iteration of Table C–2 and make 

minor corrections to the second one. 

The amendments consist of correcting 

the exponents (powers-of-ten) of several 

emission factors. 

Standard conditions. A number of 

commenters requested that, for 

consistency with the rest of Part 98, we 

allow sources to use 60 °F as standard 

temperature instead of 68 °F, when 

Equation C–5 is used to calculate CO2

mass emissions from the combustion of 

gaseous fuel. We proposed to allow this 

alternative for subparts X and Y, 

because the refining and petrochemical 

industries use 60 °F as standard 

temperature. We have concluded that 

the commenters’ request to modify 

Equation C–5 accordingly is reasonable, 

and we are revising the definition of the 

term ‘‘MVC (molar volume conversion)’’ 

in the nomenclature of Equation C–5 

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

revised definition of MVC allows 

sources to use a MVC value of either 

849.5 standard cubic feet per kilogram 

mole (scf/kg mole) for a standard 

temperature of 68 °F, or 836.6 scf/kg 

mole for a standard temperature of 60 

°F. A corresponding change has been 

made to the definition of ‘‘Standard 

conditions’’ in 40 CFR 98.6. For 

verification purposes, a data element 

has been added at 40 CFR 

98.36(e)(2)(iv)(G), requiring sources 

using Equation C–5 to report which 

MVC value was used in the emissions 

calculations. 

Miscellaneous revisions. We are 

amending 40 CFR 98.34(c) by adding the 

citations from 40 CFR part 75 that 

pertain to the initial certification of Tier 

4 moisture monitoring systems. These 

amendments also correct an inadvertent 

omission in the verification section of 

subpart C, specifically, in 40 CFR 

98.36(e)(2)(v)(C). That section requires 

units using the Tier 3 methodology to 

keep records of the method(s) used for 

carbon content determination. However, 

no mention is made of keeping records 

of the method(s) used to determine the 

molecular weight, which is a 

requirement for gaseous fuels. To 

correct this inadvertent oversight, we 

have amended 40 CFR 98.36(e)(2)(v)(C) 

to require records to be kept of the 

method(s) used for both carbon content 

and (if applicable) molecular weight 

determination. Finally, we have 


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corrected typographical errors in the 

definition of ‘‘CC’’ in the nomenclature 

of Equation C–5. This equation applies 

to gaseous fuels, not liquid fuels, and 

the units of measure for CC must be kg 

C per kg of fuel, rather than kg C per 

gallon. 

Major changes since proposal are 

identified in the following list. The 

rationale for these and any other 

significant changes can be found in this 

preamble or the document, ‘‘Response to 

Comments: Revision to Certain 

Provisions of the Mandatory Reporting 

of Greenhouse Gases Rule’’ (see EPA– 

HQ–OAR–2008–0508). 

• A new equation has been added to 

Tier 1 to accommodate situations in 

which the fuel usage information on gas 

billing records is expressed in mmBtu. 

We have also added two new equations 

to 40 CFR 98.33(c) for calculating CH4

and N2O emissions when the fuel usage 

information on natural gas billing 

records is in units of therms or mmBtu. 

• For units using the Tier 2 

methodology that receive HHV data less 

frequently than monthly, or, for small 

units (< 100 mmBtu/hr) regardless of the 

HHV sampling frequency, we are 

allowing Equation C–2b to be used to 

calculate a fuel-weighted annual average 

HHV, instead of calculating the 

arithmetic average annual HHV. 

• For consistency with other 

subparts, we have revised the 

nomenclature of Equation C–5, to allow 

reporters to use a molar volume 

conversion (MVC) constant referenced 

to a standard temperature of either 60 °F 

or 68 °F. 

• For Tier 4 applications, we are 

allowing site-specific moisture default 

values to be based on fewer than nine 

Method 4 runs in cases where moisture 

data from the RATA of a CEMS are used 

to derive the default value and the 

applicable regulation allows a single 

moisture run to represent two or more 

RATA runs. 

• We have modified the approach for 

calculating CO2 mass emissions from an 

exhaust stream diverted from a CEMS 

monitored stack. 

• For consistency with Subpart A, we 

have added language in several places 

stating that for Part 75 units, separate 

reporting of biogenic CO2 emissions is 

optional in reporting year 2010 and 

mandatory thereafter. 

• We have added a new paragraph, 

(e)(6), to 40 CFR 98.33, allowing Part 75 

units to calculate biogenic CO2

emissions using the same general 

approach that is used in 40 CFR 

98.33(c)(4)(ii) for the CH4 and N2O 

emissions calculations. 

• We have added an alternative 

calculation methodology, for biogenic 

CO2 emissions from the combustion of 

MSW and tires that may be used when 

the total contribution of these fuels to 

the unit’s heat input is 10 percent or 

less. The methodology, which uses the 

Tier 1 equation together with default 

biogenic percentages, may also be used 

for small, batch incinerators that burn 

no more than 1,000 tons of MSW per 

year. 

• We have removed the term 

‘‘consecutive’’ between the words ‘‘24’’ 

and ‘‘hours’’, in reference to the 

minimum required sampling time for 

determining the percentage of biogenic 

CO2 in flue gas when ASTM Method 

D7459–08 is used, thereby allowing 

samples to be collected for 24 total 

hours in a quarter, rather than 24 

consecutive hours. We have also added 

a provision allowing sources to perform 

additional testing to demonstrate that 

sampling for 8 hours is sufficient. 

• We have added language to 40 CFR 

98.34(a)(2)(ii) and (b)(3)(ii)(B) 

explaining how to implement certain 

fuel oil sampling options, specifically, 

daily manual sampling and sampling 

after each addition of oil to the tank. 

• To minimize unnecessary burden 

related to collecting information on 

small units aggregated in a group and 

for the common pipe configuration, we 

are removing and reserving 40 CFR 

98.36 (c)(1)(ii), (c)(1)(iii), and (c)(3)(ii). 

We are no longer requiring sources to 

report the number of units in, or the 

cumulative heat input capacity of, an 

aggregated group of units or a group of 

units served by a common pipe. Only 

the maximum rated heat input capacity 

of the largest unit in the group must be 

reported. 

2. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. 

Several comments were received on this 

subpart. Responses to additional 

comments received can be found in the 

document, ‘‘Response to Comments: 

Revision to Certain Provisions of the 

Mandatory Reporting of Greenhouse 

Gases Rule’’ (see EPA–HQ–OAR–2008– 

0508). 

Natural gas consumption expressed in 

therms. 

Comment: Commenters were 

generally supportive of EPA’s proposal 

to provide equations for cases where 

natural gas consumption is expressed in 

therms in billing records. One 

commenter noted that the proposed rule 

failed to take into account that on some 

natural gas billing records, the fuel 

usage is expressed in units of mmBtu. 

The commenter also brought to our 

attention that the proposed rule did not 

provide corresponding equations for 

calculating CH4 and N2O emissions 

when the fuel usage information on gas 

billing records is expressed in therms. 

Response: We agree with these 

comments and have made the following 

adjustments to the final rule text. First, 

a new equation, Equation C–1b, has 

been added to Tier 1 to accommodate 

situations in which the fuel usage 

information on gas billing records is 

expressed in mmBtu. Second, we have 

added two new equations to 40 CFR 

98.33(c), i.e., Equations C–8a and C–8b, 

for calculating CH4 and N2O emissions 

when the fuel usage information on 

natural gas billing records is in units of 

therms or mmBtu. 

Site-specific stack gas moisture 

content values. 

Comment: Commenters were 

generally supportive of the proposed 

rule changes related to determining the 

site-specific moisture default values. 

Two commenters requested that we 

allow the site-specific moisture default 

values to be based on fewer than nine 

Method 4 runs, in cases where moisture 

data from the RATA of a CEMS are used 

to derive the default value and the 

applicable regulation allows a single 

moisture run to represent two or more 

RATA runs. 

Response: We believe that this is a 

reasonable request and have 

incorporated it into the final rule. 

Determining emissions from an 

exhaust stream diverted from a CEMS 

monitored stack. 

Comment: Commenters were 

supportive of the intent of the proposed 

amendments, but indicated that the 

proposed methodology for estimating 

the CO2 mass emissions from the 

diverted gas stream would not be 

implementable at every affected facility. 

Specifically, commenters took issue 

with EPA’s assumption that the CO2

concentration in the diverted stream 

will be the same as the concentration in 

the main stack. According to the 

commenters, this is not the case, 

because dilution air introduced via 

auxiliary fans and other equipment will 

lower the CO2 concentration of the side 

stream. 

Response: We agree with the 

commenters’ assessment and have 

modified the proposed approach for 

quantifying emissions in the diverted 

stream. The final rule requires annual 

emission testing of the diverted gas 

stream to be performed at a set point 

that best represents normal operation, 

using EPA Methods 2 and 3A and (if 

moisture correction is necessary) 

Method 4. A CO2 mass emission rate is 

calculated from the test results. If, over 

time, flow rate of the diverted stream 


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varies little from the tested flow rate, 

then the annual CO2 mass emissions for 

the diverted stream (which must be 

added to the CO2 mass emissions 

measured at the main stack) will be 

determined simply by multiplying the 

CO2 mass emission rate from the 

emission testing by the number of 

operating hours in which a portion of 

the flue gas was diverted from the main 

flue gas exhaust system. However, if the 

flow rate of the diverted stream varies 

significantly over the reporting year, the 

owner or operator must either perform 

additional stack testing or use the best 

available information (e.g., fan settings 

and damper positions) and engineering 

judgment to estimate the CO2 mass 

emission rate at a minimum of two 

additional set points, to represent the 

variation across the normal operating 

range. Then, the most appropriate CO2

mass emission rate must be applied to 

each hour in which a portion of flue gas 

is diverted from the main exhaust 

system. The procedures used to 

determine the annual CO2 mass 

emissions for the diverted stream must 

be documented in the monitoring plan. 

Fuel sampling for coal and fuel oil. 

Comment: Commenters were 

generally supportive of the proposed 

amendments to 40 CFR 98.34(a)(2)(ii) 

and 40 CFR 98.34(b)(3)(ii) regarding the 

definition of ‘‘fuel lot.’’ However, we did 

receive requests to clarify the meaning 

of the terms ‘‘type of fuel’’ and ‘‘supply 

source,’’ pertaining to the proposal to 

require only one monthly sample to 

represent multiple fuel deliveries. 

Response: The final rule clarifies that 

for coal, the type of fuel refers to the 

coal rank (i.e., anthracite, bituminous, 

sub-bituminous, or lignite). For fuel oil, 

the type of fuel refers to the grade 

number or classification of the oil (e.g., 

No. 2 oil, No. 6 oil, jet-A fuel, etc.). The 

term ‘‘supply source’’ is not so easily 

defined, however, and we have chosen 

not to include a definition to the final 

rule. Instead, you may use the following 

general guidelines. The term ‘‘supply 

source’’ can certainly refer to the coal 

mine, bulk terminal, or refinery from 

which the fuel is obtained. However, it 

also can apply to a fuel vendor who 

receives a particular type of fuel from 

different locations and distributes the 

fuel to his customers, provided the 

important properties of the fuel, such as 

its heating value, sulfur content, carbon 

content, etc., are guaranteed to be 

within specified ranges. 

Comment: With respect to the HHV 

sampling requirements for each fuel lot, 

commenters expressed concern that the 

option to sample fuel oil after each 

addition of fuel to the storage tank 

might not represent the fuel actually 

being combusted. For instance, fuel may 

be added to an empty or a partly full 

tank that is out of service. Also, for a 

tank that is currently in service, due to 

infrequent combustion of fuel oil, it may 

have been months, or even years, since 

oil was last added to the tank, and it 

may be months or years before oil is 

added again. 

Response: To address these concerns, 

the final rule requires at least one 

sample to be obtained from each storage 

tank that is currently in service, and an 

additional sample whenever fuel is 

added to the tank while it remains in 

service. If multiple additions are made 

to an in-service tank on a given day 

(e.g., from multiple deliveries) one 

sample taken after the final addition is 

sufficient. No sampling is required for 

addition of fuel to a tank that is out of 

service. Rather, a sample must be taken 

when the tank is brought into service 

and whenever oil is added to the tank, 

for as long as the tank remains in 

service. 

Tier 4 monitoring threshold for units 

that combust MSW. 

Comment: Commenters were 

generally supportive of the proposed 

amendment to increase the Tier 4 

monitoring threshold for combustion of 

municipal solid waste from 250 to 600 

tons per day. One concern was that the 

amendment might not be finalized 

before the end of 2010; therefore, they 

asked for the final rule to provide a six 

month extension of the January 1, 2011 

regulatory deadline for installing and 

certifying CEMS. Some commenters 

were concerned that this proposed 

change would affect the quantity of 

emissions reported under the program 

and were, therefore, concerned about 

finalizing this proposed amendment. 

Response: There is no need for the 

requested extension because units at or 

above the 600 ton per day threshold 

have been on notice since the 2009 final 

rule that they are required to use CEMS. 

The proposed revision to the Tier 4 

monitoring threshold should not have 

caused them to think otherwise. For 

units in-between the original threshold 

of 250 tons per day and the revised 

threshold of 600 tons per day, an 

extension is unnecessary because these 

units can use Tier 2 for the 2010 

reporting year. We disagree with 

concerns that the final amendments will 

impact the quantity of data reported to 

the program, because the final 

amendments still require the same units 

to report GHG emissions. The only 

difference is that they may be using the 

Tier 2 methodology instead of Tier 4. 

Biogenic CO2 emissions from biomass 

combustion. 

Comment: Regarding the proposed 

revisions to the optional biogenic CO2

emissions calculation methodology for 

units with CEMS described in 40 CFR 

98.33(e)(2), one commenter 

recommended that we make the 

methodology more flexible by 

modifying Equation C–13. The change 

to this equation proposed by the 

commenter would allow the volume of 

CO2 from combustion of the biomass 

fuel (rather than the fossil fuel) to be 

calculated directly and then used in 

Equation C–14 to calculate the biogenic 

percentage of the annual CO2 mass 

emissions. 

Response: EPA has not incorporated 

the commenter’s proposed changes. 

Although the proposed modification to 

the methodology could work for fuels 

such as wood residue and bark (which 

have F-factors listed in Table 1 in 

section 3.3.5 of 40 CFR part 75, 

appendix F), the commenter appears to 

be unaware that we proposed to remove 

from 40 CFR 98.33(e)(1) the restriction 

prohibiting units with CEMS from using 

the Tier 1 methodology to calculate 

biogenic CO2 emissions. As stated 

above, we are finalizing that amendment 

as proposed. Therefore, since both Tier 

1 and the commenter’s suggested 

methodology require sources to quantify 

the amount of biomass fuel combusted, 

and since the Tier 1 methodology is 

significantly simpler than the 

commenter’s proposal, there is no need 

to revise the calculation procedures in 

40 CFR 98.33(e)(2). 

Comment: Many units and industrial 

processes burn relatively small amounts 

of partly biogenic fuels such as tires and 

MSW, as supplementary fuels. Quarterly 

sampling and analysis of the flue gas 

using ASTM Methods D7459–08 and 

D6866–08 is the only available 

methodology in Part 98 for quantifying 

biogenic CO2 emissions from these 

fuels. Some commenters requested relief 

from reporting biogenic CO2 emissions 

from such fuels when they account for 

less than 10 percent of a unit’s heat 

input. Another commenter asked EPA to 

either make reporting of biogenic CO2

optional or reduce the amount of 

required testing with the ASTM 

methods to once every five years, for 

small batch incinerators that combust 

MSW. The commenter provided data for 

a typical batch incinerator, showing that 

in 2009, less than 400 metric tons of 

biogenic CO2 were emitted from the 

unit. 

Response: We do not intend to grant 

a reporting exemption for MSW 

combustion, and, for tires, although the 

reporting is optional at present, we 

intend to revisit this issue in the future. 

However, we are persuaded that the cost 


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of performing the ASTM methods 

(roughly $5,000 to $10,000 each quarter) 

is unreasonably high for sources that 

burn very small amounts of MSW and/ 

or tires and emit comparatively little 

biogenic CO2. Also, for sources that 

combust tires and wish to report 

biogenic CO2, the ASTM methods are 

their only option. In view of these 

considerations, we have added an 

alternative calculation methodology for 

biogenic CO2 emissions from the 

combustion of tires and/or MSW. The 

methodology is found at 40 CFR 

98.33(e)(3)(iv), and may be used when 

the total contribution of these fuels to 

the unit’s heat input is 10 percent or 

less. We are also allowing this 

methodology to be used for small batch 

incinerators that burn no more than 

1,000 tons of MSW per year. 

Supplementary information provided by 

the commenter who requested reduced 

testing of these incinerators indicates 

that the rated capacities of the units can 

be as high as 1,300 lb/hr of MSW, but 

that in practice, since the units operate 

in batch mode, a more realistic estimate 

of the actual, annualized capacity of the 

units is somewhere between 100 and 

200 lb/hr (see EPA–HQ–OAR–2008– 

0508). If one of these incinerators were 

to combust as much as 200 lb/hr of 

MSW on an annualized basis, this 

would equate to approximately 875 tons 

of MSW per year. The total annual CO2

emissions from the combustion of 875 

tons of MSW is estimated to be about 

800 metric tons, based on the default 

emission factors in Table C–1. 

Assuming a biogenic fraction of 0.60 for 

MSW, the biogenic portion of the total 

annual CO2 emissions would be 480 

metric tons, which is less than 2 percent 

of the 25,000 metric ton applicability 

threshold in 40 CFR 98.2 for Part 98 

facilities. Based on the above analysis, 

we have concluded that it is appropriate 

to allow Tier 1 to be used together with 

a default biogenic percentage of 0.60 to 

estimate the biogenic CO2 emissions 

from MSW combustion in small batch 

incinerators, in lieu of using ASTM 

Methods D7459–08 and D6866–08. To 

allow for some possible variation in the 

annualized capacity of these units, the 

final rule extends the use of the 

alternative calculation methodology to 

batch incinerators that combust no more 

than 1,000 tons of MSW per year (which 

corresponds to about 540 tons of 

biogenic CO2 per year). 

Comment: With regard to the use of 

ASTM Methods D7459–08 and D6866– 

08, two commenters from facilities that 

combust refuse-derived fuel (RDF) asked 

us to consider shortening the sampling 

time to 8 hours, in cases where the fuel 

is relatively homogeneous. Both 

commenters submitted data comparing 

the results of 8-hour samples against the 

results of 24-hour samples. For one 

source, the 8-hour sample results were 

within 3.3 percent of the 24-hour 

results, and for the other source the 

results were within 1.7 percent. 

Response: EPA agrees that under 

certain circumstances, it may be 

appropriate to shorten the sampling 

time. Therefore, we are adding an 

option to 40 CFR 98.34(d) and (e), 

allowing sources to demonstrate that 8 

hours of sampling per quarter is 

sufficient. The demonstration requires a 

minimum of two 8-hour tests and one 

24-hour test, performed under normal, 

stable operating conditions. The 

demonstration tests must be distinct, 

i.e., no overlapping of the 8-hour and 

24-hour test periods is permitted. If the 

average biogenic fraction obtained from 

the 8-hour tests is within ± 5 percent of 

the results from the 24-hour test, then, 

in subsequent quarters, the Method 

D7459–08 sampling time may be 

reduced to 8 hours. The results of the 

demonstration must be documented in 

the monitoring plan. Note that although 

the data provided by the commenters 

showed that the 8-hour and 24-hour 

sample results differed by no more that 

3.3 percent, we believe that ± 5 percent 

is a more reasonable acceptance 

criterion. This is because the 

methodology will likely be used for the 

combustion of tires as well as MSW. 

Tire-derived fuel (TDF) has a much 

lower biogenic fraction than MSW 

(typically about 0.20, compared to 0.60 

for MSW). An acceptance criterion 

lower than 5 percent for TDF 

combustion would require the 

difference between the 8-hour and 24- 

hour sample results to be less than 0.01, 

and would be overly stringent. 

Use of consensus standard methods. 

Comment: We received both 

supportive and adverse comments on 

the proposed amendments to remove 

reference to specific consensus 

standards. Commenters that objected to 

the proposal stated that elimination of 

the lists of acceptable methods and 

allowing the use of ‘‘industry standard 

practice’’ weakens the rule. According to 

these commenters, there is no way to 

evaluate the technical merits of an 

‘‘industry standard practice,’’ and the 

quality of the reported GHG emissions 

data could suffer as a result. 

Response: We do not agree with the 

objections raised by these commenters. 

Subpart C covers a large range of 

industries, perhaps including some that 

we are not even aware of yet that are 

significant emitters of GHG emissions 

and therefore covered by the rule. In 

these early years of the program, we 

want to ensure that the methods 

required by the rule are appropriate for 

all facilities subject to subpart C of the 

rule. Although we attempted to 

assemble a comprehensive list of 

methods and provide appropriate 

alternatives in the 2009 final rule, based 

on questions received we determined 

that it was likely that other valid 

methods from these organizations and 

practices were overlooked. For instance, 

under the 2009 final rule, even updates 

to the IBR methods to reflect the latest 

practices would not have been 

acceptable without a rulemaking. The 

commenters did not sufficiently justify 

why opening up to industry consensus 

standards would compromise data 

quality. In fact, the opposite could be 

said where more updated versions of 

previously incorporated standards are 

now allowable. 

Further, subpart C already includes a 

mechanism by which we can evaluate 

the methods being used by industry. 

Sections 98.36(e)(2)(iii) and 

98.36(e)(2)(v) require that records be 

kept of the methods that are used for 

flow meter calibration and for HHV and 

carbon content determinations, and 40 

CFR 98.36(e)(4) requires sources to 

provide this information to EPA within 

30 days of receiving a request for it. 

We note that we have not opened all 

subparts more broadly to industry 

consensus standards. Please see the 

responses to comments in Section II.K 

(Hydrogen Production) and Section II.M 

(Petrochemical Production) of this 

preamble for our response to similar 

comments under these subparts. 

Electronic data reporting and 

recordkeeping. 

Comment: Two commenters asked us 

to either remove or modify the proposed 

requirement to report the number of 

units in an aggregated group of units. 

One commenter suggested that reporting 

would be simplified if very small 

sources such as water heaters, space 

heaters, lab burners, etc., were lumped 

together and counted as one unit. The 

other commenter stated that it is 

burdensome to keep an accurate count 

of these small domestic units at large, 

complex industrial facilities. That same 

commenter also suggested that only 

units with heat input ratings of 10 

mmBtu or greater should be included in 

the count. A third commenter noted that 

it is also difficult to report the 

cumulative maximum heat input rating 

of a group of units, as required under 40 

CFR 98.36(c)(1)(iii), when numerous 

small domestic units, some of which 

may not have a heat input rating, are 

included in an aggregated group. 


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Response: We believe these comments 

have merit. After careful consideration, 

we have concluded that for verification 

purposes, we do not need to know 

either the exact number of units in an 

aggregated group or the combined 

maximum rated heat input of the group. 

The only critical data element is the 

maximum rated heat input capacity of 

the largest unit in the group. This 

information is needed to confirm that 

none of the units exceeds 250 mmBtu/ 

hr, which is the condition that must be 

met to use the unit aggregation option 

in 40 CFR 98.36(c)(1). Therefore, in the 

final rule, we are withdrawing the 

proposed requirement to report the 

number of units in an aggregated group 

of units, and are removing the 

requirement to report the combined 

maximum rated heat input of the group. 

We also are withdrawing the proposed 

requirement under 40 CFR 

98.36(c)(3)(ii) to report the number of 

units served by a common fuel pipe. 

The issue is the same for the common 

pipe configuration as for the aggregated 

group of units, i.e., hundreds of small, 

domestic units may be served by the 

common pipe. To effect these rule 

changes, 40 CFR 98.36(c)(1)(ii), 

(c)(1)(iii), and (c)(3)(ii) have been 

removed and reserved. 

Table C–1. 

Comment: Two commenters 

questioned the appropriateness of 

listing MSW with plastics and 

petroleum coke. Further, they noted that 

petroleum coke is listed twice in the 

table, first under petroleum products 

and then again under ‘‘other fuels 

(solid).’’ According to the commenters, 

petroleum coke is a petroleum 

derivative, and is more appropriately 

listed with the other ‘‘petroleum 

products.’’ 

Response: The category ‘‘other fuels 

(solid)’’ in Table C–1 is not intended to 

make any policy statement about the 

nature of the fuels included in the 

category. The fuels included in ‘‘other 

fuels (solid)’’ are miscellaneous fuels 

that do not fit into any other existing 

category for the purposes of this rule. 

Petroleum coke was included as a 

petroleum product in the 2009 final rule 

(74 FR 56409). However, the HHV units 

of measure for petroleum products 

listed in Table C–1 are in mmBtu per 

gallon and some reporters were 

confused about how to appropriately 

calculate CO2 emissions from petroleum 

coke, since it is actually a solid fuel, and 

is nominally measured in units of short 

tons. By listing petroleum coke as a 

solid fuel with a heating value in units 

of mmBtu/short ton, EPA intends to 

alleviate confusion about how emissions 

are to be calculated for petroleum coke. 

However, we also understand that some 

facilities report petroleum coke usage to 

the Energy Information Administration 

(EIA) in units of equivalent barrels of 

petroleum, and may prefer to report 

petroleum coke consumption in units of 

gallons under this rule. As such, EPA is 

not proposing to remove petroleum coke 

from the list of petroleum products in 

Table C–1. The two HHVs for petroleum 

coke differ only in units of measure. 

They will give equivalent results when 

CO2 mass emissions are calculated. 

Comment: Two commenters asserted 

that plastics are a small component of 

MSW and there is no reason why 

plastics should be listed as a separate 

fuel in Table C–1. These commenters 

stated that to the best of their 

knowledge, plastics are not combusted 

as a separate fuel stream, and they 

recommended that EPA delete plastics 

from Table C–1. 

Two other commenters, however, 

stated that plastics are, in fact, 

sometimes separated out from MSW as 

a separate stream. These commenters 

provided a suggested definition of 

‘‘plastics’’ and requested that we add it 

to 40 CFR 98.6. The commenters also 

asked us to modify the definition of 

MSW, to specifically exclude plastics 

that are recovered from MSW, processed 

separately, and disposed. 

Response: As mentioned in the 

preamble to the August 11, 2010 

proposed rule (75 FR 48764), facilities 

have questioned EPA as to why plastics 

and waste oil, two fuels that appeared 

in Table C–2 of the April 10, 2009 

proposed rule, were left out of the 

October 30, 2009 final rule. Responding 

to these concerns, on August 11, 2010 

we proposed to add both fuels to Table 

C–1. Today’s rule retains these entries, 

except that waste oil has been 

redesignated as ‘‘used oil.’’ In view of the 

input received from the commenters 

who brought to our attention that 

plastics (including such things as 

‘‘* * * bottles, containers, bags, CD 

cases, sheeting, packaging, broken 

consumer goods, etc. * * *’’) are 

sometimes recovered from MSW and 

processed separately, we decided not to 

incorporate the recommendation of the 

other commenters who asked us to 

delete plastics from the table. 

We see no need to add a definition of 

plastics to 40 CFR 98.6, since plastic 

materials are readily identifiable. 

However, to address the commenters’ 

chief concern, we have modified the 

definition of MSW to clearly state that 

insofar as plastics (along with certain 

other materials) are separated out from 

MSW, processed and disposed of, they 

are not considered to be ‘‘municipal 

solid waste.’’ 

Comment: Two commenters argued 

against the inclusion of default factors 

for ‘‘fuel gas’’ in Table C–1. They argued 

that this would have a negative impact 

on chemical plant fuel gas streams that 

were previously exempt from Tier 3 

requirements when the streams provide 

less than 10 percent of the annual heat 

input to a unit rated greater than 250 

mmBtu/hr) because Table C–1 

previously had no factors for fuel gas. 

According to the commenters, the 

proposed inclusion of default factors for 

‘‘fuel gas’’ in Table C–1 requires 

monitoring and reporting of GHG 

emissions from these gas streams. Both 

commenters suggested that Table C–1 

should include default factors for 

‘‘refinery fuel gas’’ rather than ‘‘fuel gas.’’ 

One commenter also suggested revising 

the definition of ‘‘fuel’’ and Footnote 2 

associated with the default values for 

fuel gas in Table C–1 to clarify that fuel 

gas is specific to refineries and 

petrochemical plants, but excludes 

process off-gases from chemical 

production plants. 

Response: Default values for fuel gas 

in Table C–1 are necessary to allow 

refineries and petrochemical plants to 

use Tier 1 or Tier 2 methods for certain 

small fuel gas streams that were 

proposed to be excluded from the 

requirement to use Tier 3 for fuel gas in 

subparts X and Y. In providing these 

factors, we did not intend to require 

chemical plants to monitor and report 

GHG emissions generated by the 

combustion of ‘‘fuel gas’’ that were 

excluded from reporting requirements 

in the October 30, 2009, final Part 98. 

Therefore, we agree that some 

additional clarification of terms is 

needed to prevent the fuel gas factor 

from requiring measurement and 

reporting of GHG from the chemical 

plant vent gases. 

While changing the term used in 

Table C–1 to ‘‘refinery fuel gas’’ may 

have helped to clarify the intent, we do 

not believe, given the definition of ‘‘fuel 

gas’’ in the final rule, that this would 

adequately address the issue. ‘‘Fuel gas’’ 

as defined in the October 30, 2009, final 

Part 98 means ‘‘gas generated at a 

petroleum refinery, petrochemical plant, 

or similar industrial process unit, and 

that is combusted separately or in any 

combination with any type of gas.’’ The 

inclusion of the phrase ‘‘or similar 

industrial process unit’’ within the 

definition of fuel gas expanded the 

meaning of fuel gas beyond refineries 

and petrochemical plants. Without 

specifically defining the term ‘‘refinery 

fuel gas’’ we expect that the rule 

language would have remained 

ambiguous, especially since refinery 


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fuel gas was still intended to apply to 

some petrochemical processes. 

To clarify our original intent of the 

proposed inclusion of default factors for 

fuel gas in Table C–1, we are revising 

the definition of ‘‘fuel gas’’ to delete 

reference to other similar industrial 

process units. In Part 98, the term ‘‘fuel 

gas’’ is intended to apply to petroleum 

refineries and petrochemical plants, so 

this revision does not affect other Part 

98 requirements; it simply clarifies that 

‘‘fuel gas’’ and the fuel gas factors are 

specific to petroleum refineries and 

petrochemical plants. 

The commenter suggested revising the 

definition of fuel to mean ‘‘solid, liquid 

or gaseous combustible material, but 

excludes process waste off gases from 

chemical production plants that are not 

petroleum refineries or petrochemical 

plants.’’ We have determined that this 

change is not necessary because we 

have addressed the commenter’s 

concerns through the change in the 

definition of fuel gas. We are amending 

Footnote 2 of Table C–1, as requested, 

to clarify further that only reporters 

subject to 40 CFR 98.243(d) of subpart 

X or subpart Y are required to use Tier 

3 or Tier 4 methodologies when the 

specific conditions outlined in the 

footnote do not exist. 

H. Subpart D—Electricity Generation 

1. Summary of Final Amendments and 

Major Changes Since Proposal 

We are amending 40 CFR 98.40(a) by 

adding the word ‘‘mass’’ between the 

words ‘‘CO2’’ and ‘‘emissions’’ to make it 

clear that subpart D applies only to 

units in two categories: ARP units and 

non-ARP electricity generating units 

(EGUs) that are required to report CO2

mass emissions data to EPA year-round. 

Optional reporting of biogenic CO2. 

For consistency with the amendments to 

subpart C, we have revised 40 CFR 

98.43 to clarify that for subpart D units, 

reporting of biogenic CO2 emissions is 

optional only for the 2010 reporting 

year, and mandatory thereafter. We are 

also adding a new paragraph 40 CFR 

98.43(b) indicating that biogenic CO2

emissions must be calculated and 

reported by following the applicable 

methods specified in 40 CFR 98.33(e). 

Fossil CO2 emissions are calculated by 

subtracting the biogenic CO2 mass 

emissions calculated according to 40 

CFR 98.33(e) from the cumulative 

annual CO2 mass emissions from 

paragraph (a)(1) of this section. 

Data reporting requirements. Section 

98.46 of subpart D specified that the 

owner or operator of a subpart D unit 

must comply with the data reporting 

requirements of 40 CFR 98.36(b) and, if 

applicable, 40 CFR 98.36(c)(2) or (c)(3). 

These section citations were incorrect. 

Subpart D units all use the CO2 mass 

emissions calculation methodologies in 

40 CFR part 75. Therefore, the 

applicable data reporting section for 

these units is 40 CFR 98.36(d), not 40 

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

CFR 98.36(c)(3). We are amending 40 

CFR 98.46 to correct this error. 

Recordkeeping. We are amending 40 

CFR 98.47 to state that the records kept 

under 40 CFR 75.57(h) for missing data 

events satisfy the recordkeeping 

requirements of 40 CFR 98.3(g)(4) for 

those same events. We have concluded 

that, as a practical matter, the missing 

data records required to be kept under 

40 CFR 75.57(h) are substantially 

equivalent to the records required under 

40 CFR 98.3(g)(4). 

Major changes since proposal are 

identified in the following list. The 

rationale for these and any other 

significant changes can be found in this 

preamble or the document, ‘‘Response to 

Comments: Revision to Certain 

Provisions of the Mandatory Reporting 

of Greenhouse Gases Rule’’ (see EPA– 

HQ–OAR–2008–0508). 

• Making separate reporting of 

biogenic emissions optional for part 75 

units in the 2010 reporting year and 

mandatory every year thereafter. See 

sections II.C and II.G of this preamble. 

• Adding a provision to subpart D to 

clarify how to calculate and report 

biogenic CO2 emissions, referencing the 

applicable methods in 40 CFR 98.33(e) 

and the reporting requirements in 40 

CFR 98.3(c)(4) and (c)(12). 

2. Summary of Comments and 

Responses 

No significant comments were 

received on the specific technical 

amendments to subpart D. Comments 

related to the proposed separate 

reporting of biogenic emissions for units 

subject to 40 CFR part 75 can be found 

in Sections II.C and II.G of this 

preamble. 

I. Subpart F—Aluminum Production 

1. Summary of Final Amendments and 

Major Changes Since Proposal 

Throughout subpart F we are making 

corrections as needed for typographical 

errors and alphanumeric sequencing. 

We are amending 40 CFR 98.63 to 

clarify that each perfluorocarbon (PFC) 

compound (perfluoromethane, CF4, also 

called tetrafluoromethane, and 

perfluoroethane, C2F6, also called 

hexafluoroethane) must be quantified 

and reported and to clarify in 40 CFR 

98.63(c) that reporters must use CEMS 

if the process CO2 emissions from anode 

consumption during electrolysis or 

anode baking of prebake cells are vented 

through the same stack as a combustion 

unit required to use CEMS. This 

requirement existed in the final rule, 

however, the cross-reference was 

omitted from the introductory language 

of 40 CFR 98.63(c). 

We are amending 40 CFR 98.64 to 

clarify the type of parameters that must 

be measured in accordance with the 

recommendations of the EPA/IAI 

Protocol for Measurement of 

Tetrafluoromethane (CF4) and 

Hexafluoroethane (C2F6) Emissions from 

Primary Aluminum Production (2008), 

and the frequency of monitoring for 

those parameters that are not measured 

annually, but are instead measured on a 

more or less frequent basis. We are also 

inserting dates into this paragraph. In 

inserting these dates, we have decided 

to use dates in reference to the effective 

date of the 2009 final rule, as opposed 

to the publication date as was written in 

the final rule. It was determined to be 

more appropriate to use the effective 

date of the rule as the basis for the 

timing of the requirements. Therefore, 

we are amending the paragraph to read 

‘‘December 31, 2010’’ in place of ‘‘one 

year after publication of the rule’’ and 

are inserting ‘‘December 31, 2012’’ in 

place of ‘‘three years after publication of 

the rule.’’ 

We are amending Table F–2 to clarify 

that default CO2 emissions from pitch 

volatiles combustion are relevant only 

for center work pre-bake (CWPB) and 

side work pre-bake (SWPB) 

technologies. 

We are also amending Table F–1 to 

spell out the acronyms for the 

technologies covered by that table; i.e., 

CWPB, SWPB, vertical stud S<derberg 

(VSS), and horizontal stud S<derberg 

(HSS). 

The comments received supported the 

proposed amendments, so the 

amendments to subpart F are finalized 

as proposed. 

2. Summary of Comments and 

Responses 

One comment letter was received on 

this subpart, and it supported the 

proposed amendments. The summary 

and response to this comment letter can 

be found in the document, ‘‘Response to 

Comments: Revision to Certain 

Provisions of the Mandatory Reporting 

of Greenhouse Gases Rule’’ (see EPA– 

HQ–OAR–2008–0508). 

J. Subpart G—Ammonia Manufacturing 

1. Summary of Final Amendments and 

Major Changes Since Proposal 

We are amending subpart G to remove 

reporting of the waste recycle stream or 


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purge, and to make subpart G conform 

to the amendments to the calibration 

requirements in subpart A. With respect 

to the waste recycle stream, we are 

eliminating the calculation, monitoring 

and reporting of the emissions 

associated with the waste recycle stream 

or purge currently required by Equation 

G–6 from 40 CFR 98.73, 98.74, 98.75, 

and 98.76. Carbon dioxide emissions 

from waste recycle stream or purge gas 

used as fuel will still be accounted for 

accurately using Equation G–5 in 

subpart G. Because total process 

emissions, calculated using Equation G– 

5, will also account for emissions 

associated with use of the purge gas as 

a fuel, we are amending 40 CFR 98.72(b) 

so that subpart C does not apply to CO2

emissions resulting from the use of 

purge gas as a fuel. 

We are clarifying in 40 CFR 98.72(a) 

and in the definition of CO2 in Equation 

G–5 that CO2 process emissions 

reported under this subpart may include 

CO2 that is later consumed on site for 

urea production and therefore is not 

released to the ambient air from the 

ammonia manufacturing process unit. 

We have included this clarification 

because although the equations 

accurately reflect total CO2 that is 

generated from the ammonia 

manufacturing process, not all of that 

CO2 is released on site. Rather, some of 

the CO2 may be used for urea 

production and not be actually released 

to the atmosphere until use of the urea 

at an off-site location. 

We are amending 40 CFR 98.74(d) to 

limit the flow meter calibration 

accuracy requirements of 40 CFR 

98.3(i)(2) and (i)(3) to only meters that 

are used to measure liquid and gaseous 

feedstock volumes. In accordance with 

40 CFR 98.3(i)(1), each measurement 

device that is not used to measure liquid 

and gaseous feedstock volumes, but is 

used to provide data for the GHG 

emissions calculations, will have to be 

calibrated to an accuracy within the 

appropriate error range for the specific 

measurement technology, based on an 

applicable operating standard, such as 

the manufacturer’s specifications. 

We are amending the definition of 

CO2 emissions in Equation G–5 to 

indicate that the CO2 emissions 

estimates under subpart G may include 

CO2 that is later consumed on site for 

urea production and therefore not 

released to the atmosphere from the 

ammonia manufacturing process unit. 

This change does not affect the total CO2

emissions that are quantified and 

reported to EPA under the calculation 

equations in 40 CFR 98.73. Likewise, we 

are amending 40 CFR 98.76(b) to require 

reporting of the CO2 from the ammonia 

manufacturing process unit that is then 

used to produce urea and the method 

used to determine that quantity of CO2

consumed. 

In addition, we are amending subpart 

G to correct several typographical errors 

and an incorrect cross-reference to 

another subpart in 40 CFR part 98. We 

are correcting the terms and definitions 

for annual CO2 emissions arising from 

gaseous, liquid, and solid fuel feedstock 

consumption in Equations G–1, G–2, 

and G–3, respectively, in 40 CFR 98.73. 

We are correcting 40 CFR 98.76(a) by 

changing the cross-reference from 

‘‘§ 98.37(e)(2)(vi)’’ to ‘‘§ 98.37.’’ 

We are amending the data reporting 

requirements in 40 CFR 98.76(b)(6) and 

(15) for consistency with the calculation 

procedures in 40 CFR 98.73(b)(6). We 

are amending 40 CFR 98.76(b)(6) to 

change ‘‘petroleum coke’’ to ‘‘feedstock’’ 

because petroleum coke is the incorrect 

term, and amending 40 CFR 98.76(b)(15) 

to specify that the carbon content 

analysis method being reported is for 

each month. We are also removing 40 

CFR 98.76(b)(17) for the reporting of 

urea produced, if known, as well as 

reporting requirements in 40 CFR 

98.76(c) for total pounds of synthetic 

fertilizer produced and total nitrogen 

contained in that fertilizer. 

No major changes have been made to 

the amendatory language since 

proposal. 

2. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. 

Several comments were received on this 

subpart. Responses to additional 

significant comments received can be 

found in the document, ‘‘Response to 

Comments: Revision to Certain 

Provisions of the Mandatory Reporting 

of Greenhouse Gases Rule’’ (see EPA– 

HQ–OAR–2008–0508). 

Comment: One commenter was 

supportive of all proposed amendments 

to subpart G. However, we received 

adverse comments on the proposed 

amendment to remove requirements to 

report the total quantity of synthetic 

fertilizer produced and the nitrogen 

content of fertilizer. The commenter 

asserted that EPA does not offer a reason 

for the deletion of fertilizer reporting 

requirements, and noted that synthetic 

fertilizer application drives a large 

fraction of N2O emissions from 

agricultural soils. They asserted that the 

reporting requirements should be 

retained for several reasons, including 

that collecting information for N2O 

emissions, even if it is from less than 

one-half of the total fertilizer produced, 

is valuable. Further, the commenter 

contended that justifying removal of the 

reporting requirement because of the 

availability of other data through the 

Association of American Plant Food 

Control Officials is not appropriate 

because those other data may not be 

available reliably into the future and do 

not map emissions back to specific 

facilities. They argued that reporting of 

synthetic fertilizer production is a good 

first step in estimating N2O emissions 

from agricultural soils. 

Another commenter countered many 

of the points raised above, asserting that 

data on domestic synthetic fertilizer 

production is not a good indicator of 

N2O emissions from farming because the 

rule did not capture all fertilizer 

production and not all fertilizer is 

applied to fields. 

Response: EPA has finalized, as 

proposed, the amendment to remove 

reporting requirements of the total 

amount of synthetic fertilizer produced 

and nitrogen contained in that fertilizer. 

EPA has concluded that the burden 

placed on fertilizer production facilities 

to report on total pounds of synthetic 

fertilizer and total nitrogen contained in 

that fertilizer would not be 

commensurate with the value of the 

data we would receive in terms of 

improving our ability to estimate N2O 

emissions from soils. Specifically, 

facility specific data from producers on 

the nitrogen content of synthetic 

fertilizer is of minimal value in 

estimating soil N2O emissions by itself. 

As explained in the proposal preamble 

(75 FR 48767), there are a variety of 

inputs that would be valuable to 

consider to estimate N2O emissions 

from agricultural soils, including 

fertilizer application rates, timing of 

application, and the use of slow release 

fertilizers and nitrification/release 

inhibitors, none of which would be 

provided through the provision 

removed from the rule. Given that the 

information required from the final rule 

would not provide sufficient 

information to estimate N2O emissions 

from fertilizer application to soils, we 

are removing the reporting requirement 

at this time. While there is concern over 

the potential future loss of the 

Association of American Plant Food 

Control Officials data, EPA has 

determined that it is preferable to 

remove the incomplete reporting 

requirement at this time and, if 

appropriate in the future, reconsider in 

a comprehensive manner reporting of 

information on fertilizer production, 

import and use practices. 


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K. Subpart P—Hydrogen Production 

1. Summary of Final Amendments and 

Major Changes Since Proposal 

We are amending the definition of the 

terms for the average carbon content 

(CCn) and molecular weight (MWn) in 

Equation P–1 of 40 CFR 98.163 to clarify 

that, where measurements are taken 

more frequently than monthly, CCn and 

MWn should be calculated using the 

arithmetic average of measurement 

values within the month. 

We are amending 40 CFR 98.164(b)(1) 

so it is consistent with today’s 

amendments to 40 CFR 98.3(i). First, we 

are limiting the flow meter calibration 

accuracy requirements of 40 CFR 

98.3(i)(2) and (i)(3) to meters that are 

used to measure liquid and gaseous 

feedstock volumes. In accordance with 

40 CFR 98.3(i)(1), all other measurement 

devices that are used to provide data for 

the GHG emissions calculations have to 

be calibrated only to an accuracy within 

the appropriate error range for the 

specific measurement technology, based 

on an applicable operating standard, 

such as the manufacturer’s 

specifications. Second, we are removing 

the requirements for solids weighing 

equipment and oil tank drop 

measurements to be calibrated 

according to 40 CFR 98.3(i), because the 

provisions of 40 CFR 98.3(i) apply only 

to gas and liquid flow meters. For oil 

tank drop measurements, the QA 

requirements of 40 CFR 98.34(b)(2) 

apply. 

As a harmonizing amendment with 

the amendment allowing the use of a gas 

chromatograph (described in 40 CFR 

98.164(b)(5)), we are adding the phrase 

‘‘no less frequent’’ to 40 CFR 

98.164(b)(2). This change indicates that 

when determining the carbon content 

and the molecular weight of ‘‘other 

gaseous fuels and feedstocks’’ (e.g., 

biogas, refinery gas, or process gas), you 

must undertake sampling and analysis 

no less frequently than weekly. 

Replacing a ‘‘weekly’’ requirement with 

‘‘no less frequent than weekly’’ allows 

for the use of continuous, on-line 

equipment gas chromatographs. 

We are amending 40 CFR 98.164(b)(5) 

to allow the use of chromatographic 

analysis of the fuel, provided that the 

gas chromatograph is operated, 

maintained, and calibrated according to 

the manufacturer’s instructions. 

Major changes since proposal are 

identified in the following list. The 

rationale for these and any other 

significant changes can be found in this 

preamble or the document, ‘‘Response to 

Comments: Revision to Certain 

Provisions of the Mandatory Reporting 

of Greenhouse Gases Rule’’ (see EPA– 

HQ–OAR–2008–0508). 

• Modification of Equation P–1 to 

account for measurements taken more 

frequently than monthly to determine 

the molecular weight of the gaseous fuel 

and feedstock. 

• Inclusion of the option to use a gas 

chromatograph (both continuous and 

non-continuous) for determining the 

carbon content and molecular weight of 

gaseous fuels. 

2. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. 

Several comments were received on this 

subpart. Responses to additional 

significant comments received can be 

found in the document, ‘‘Response to 

Comments: Revision to Certain 

Provisions of the Mandatory Reporting 

of Greenhouse Gases Rule’’ (see EPA– 

HQ–OAR–2008–0508). 

Comment: One commenter noted that 

the fuels and feedstocks to a hydrogen 

plant subject to subpart P requirements 

are often the same fuels that are burned 

in combustion units subject to subpart 

C requirements. The commenter further 

noted that both subparts had different 

monitoring and QA/QC requirements 

which would pose a problem for a 

facility trying to determine which 

method to use. 

Response: No change has been made 

as a result of this comment. We did not 

receive sufficient information from the 

commenter as to why they would not be 

able to comply using the methods 

already prescribed in subpart P for 

determining carbon content and 

molecular weight. As noted by the 

commenter, facilities only subject to 

subpart C must use a method published 

by a consensus standards organization if 

such a method exists, or an industry 

consensus standard practice. Therefore, 

the methods in the 2009 final rule for 

subpart P could be used to meet the 

requirements in subpart C. We 

determined that it was appropriate to 

open the methods to industry consensus 

standards or industry standard practices 

for facilities subject to subpart C only, 

because the industries covered by 

subpart C could be wide ranging and the 

specific methods listed may not be 

appropriate for certain industry types. 

Because the commenter does not 

provide specific concerns as to why the 

methods listed in subpart P are not 

appropriate, we have decided not to 

remove the applicable methods listed in 

subpart P and replace them with the 

option to use consensus based standards 

or industry consensus standards. 

Comment: One commenter requested 

that EPA allow the use of gas 

chromatographs as an alternative 

method for determining the carbon 

content in gaseous fuels and feedstocks. 

Response: EPA acknowledges the 

commenter’s recommendation to 

include the option to use gas 

chromatographs for measuring the 

carbon content and molecular weight of 

fuels and feedstocks in subpart P. As a 

result, EPA has revised the monitoring 

and QA/QC requirements to allow the 

use of gas chromatographs, both 

continuous and non-continuous, to 

determine the carbon content and 

molecular weight of fuels and 

feedstocks provided that the gas 

chromatograph is operated, maintained, 

and calibrated according to the 

manufacturer’s instructions. 

L. Subpart V—Nitric Acid Production 

1. Summary of Final Amendments and 

Major Changes Since Proposal 

We are amending 40 CFR 98.226 to 

remove the synthetic fertilizer and total 

nitrogen reporting requirement in 40 

CFR 98.226(o). The detailed rationale 

for this amendment is provided in 

Section II.J of this preamble. 

2. Summary of Comments and 

Responses 

Several comments were received on 

the proposal to remove the synthetic 

fertilizer and total nitrogen reporting 

requirement in 40 CFR 98.226(o). Please 

see section II.J (Ammonia Production) of 

this preamble for the comments and 

responses related to reporting of 

fertilizer production data. 

M. Subpart X—Petrochemical 

Production 

1. Summary of Final Amendments and 

Major Changes Since Proposal 

Numerous issues have been raised by 

owners and operators in relation to the 

requirements in subpart X for 

petrochemical production facilities. The 

issues being addressed by the 

amendments include the following: 

• Distillation and recycling of waste 

solvent. 

• Process vent emissions monitored 

by CEMS. 

• Process off-gas combustion in flares. 

• CH4 and N2O emissions from 

combustion of process off-gas. 

• Molar volume conversion (MVC) 

factors. 

• Methodology for small ethylene offgas streams. 

• Monitoring and QA/QC 

requirements. 

• Reporting requirements under the 

CEMS compliance option. 


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• Reporting requirements for the 

ethylene-specific option. 

• Reporting measurement device 

calibrations. 

• For the mass balance option, 

sampling frequency when receiving 

multiple deliveries from same supply 

source. 

Distillation and recycling of waste 

solvent. We are adding a new paragraph, 

as proposed, to 40 CFR 98.240(g) to 

specify that a process that distills or 

recycles waste solvent that contains a 

petrochemical is not part of the 

petrochemical production source 

category. 

Process vent emissions monitored by 

CEMS. We are adding a sentence, as 

proposed, to 40 CFR 98.242(a)(1) that 

specifies CO2 emissions from process 

vents routed to stacks that are not 

associated with stationary combustion 

units must be reported under subpart X 

when you comply with the CEMS 

option in 40 CFR 98.243(b). 

Process off-gas combustion in flares. 

We are amending 40 CFR 98.242(b), as 

proposed, by removing the reference to 

flares. 

CH4 and N2O emissions from 

combustion of process off-gas. We are 

amending 40 CFR 98.243(b), as 

proposed, to clarify that either the 

default HHV for fuel gas or a sitespecific calculated HHV may be used 

when using Tier 3 procedures to 

calculate CH4 and N2O emissions from 

combustion units that burn 

petrochemical process off-gas and are 

monitored with a CO2 CEMS. 

Sampling frequency for mass balance 

method. We are amending 40 CFR 

98.243(c)(3) to clarify that when 

multiple deliveries of a particular liquid 

or solid feedstock are received from the 

same supply source in a month, one 

representative sample is sufficient for 

the month. The amendment is being 

made in response to a comment 

received. As explained in section II.M.2 

of this preamble, we are amending 40 

CFR 98.243(c)(3) to make the language 

in subpart X consistent with a similar 

amendment for fuel sampling in 40 CFR 

98.34(b)(3)(ii)(B). The new language 

does not change the requirements in 40 

CFR 98.243(c). 

Molar volume conversion (MVC) 

factors. We are amending Equation X– 

1, as proposed, to provide two 

alternative values of MVC that 

correspond to the two most common 

standard conditions output by the flow 

monitors. Additionally, the reporting 

requirements related to this equation are 

being amended, as proposed, to include 

reporting of the standard temperature at 

which the gaseous feedstock and 

product volumes were determined 

(either 60 °F or 68 °F) and to afford 

verification of the reported emissions. 

Methodology for small ethylene offgas streams. We are finalizing 

amendments to 40 CFR 98.243(d), as 

proposed, to allow the use of Tier 1 or 

Tier 2 methods for small flows (in cases 

where a flow meter is not already 

installed). Specifically, Tier 1 or Tier 2 

methods may be used for ethylene 

process off-gas streams that meet either 

of the following conditions: 

• The annual average flow rate of fuel 

gas (that contains ethylene process offgas) in the fuel gas line to the 

combustion unit, prior to any split to 

individual burners or ports, does not 

exceed 345 standard cubic feet per 

minute (scfm) at 60 °F and 14.7 pounds 

per square inch absolute (psia) and a 

flow meter is not installed at any point 

in the line supplying fuel gas or at an 

upstream common pipe. 

• The combustion unit has a 

maximum rated heat input capacity of 

less than 30 mm Btu/hr, and a flow 

meter is not installed at any point in the 

line supplying fuel gas (that contains 

ethylene process off-gas) or an upstream 

common pipe. 

As in the proposal, this amendment 

also specifies how to calculate the 

annual average flow rate under the first 

condition. Specifically, the total flow 

obtained from company records is to be 

evenly distributed over 525,600 minutes 

per year. In response to comments we 

are making an editorial change to the 

introductory paragraph of 40 CFR 

98.243(d) to clarify that the common 

pipe reporting alternative may be used 

when applicable; the intent of the 

requirements in this section are not 

changed by this editorial change. We are 

also making a number of other editorial 

changes to 40 CFR 98.243(d), as 

proposed, to integrate the amended 

option with the existing requirements. 

Finally, we are amending 40 CFR 

98.246(d)(2) and 98.247(c), as proposed, 

to add reporting and recordkeeping 

requirements that are related to the 

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

Monitoring methods for determining 

carbon content and composition. We are 

finalizing the proposed addition of 

ASTM D2593–93 (Reapproved 2009), 

Standard Test Method for Butadiene 

Purity and Hydrocarbon Impurities by 

Gas Chromatography, to 40 CFR 

98.244(b)(4). We are further amending 

40 CFR 98.244(b)(4), as proposed, by 

adding a new paragraph that will allow 

the use of industry standard practice to 

determine the carbon content or 

composition of carbon black feedstock 

oils and carbon black products. 

We also added two more published 

methods to the list in 40 CFR 

98.244(b)(4) of the final rule: ASTM 

D7633, Standard Test Method for 

Carbon Black—Carbon Content, and 

EPA Method 9060A in EPA publication 

SW–846, Test Methods for Evaluating 

Solid Waste, Physical/Chemical 

Methods. We also added an option, 

already proposed in subparts C and Y, 

to use results of chromatographic 

analysis of feedstocks and products, 

provided that the gas chromatograph is 

operated, maintained, and calibrated 

according to the manufacturer’s 

instructions. Finally, we added an 

option to use results of a mass 

spectrometer analysis of a feedstock or 

product, provided that the mass 

spectrometer is operated, maintained, 

and calibrated according to the 

manufacturer’s instructions. 

We are also amending 40 CFR 

98.244(b)(4), as proposed, to provide 

facilities the option to determine carbon 

content or composition of feedstocks or 

products using modified versions of the 

analytical methods listed in 40 CFR 

98.244(b)(4) if the listed methods are not 

appropriate for reasons noted below. 

The proposed amendments in this 

section would have allowed the use of 

‘‘other analytical methods’’ if methods 

listed in 40 CFR 98.244(b)(4) are not 

appropriate for any of the same reasons. 

However, in response to comments, we 

revised this provision to allow the use 

of ‘‘other methods’’ rather than ‘‘other 

analytical methods’’ so that nonanalytical methods also can be used. 

The conditions under which the listed 

methods may be considered 

inappropriate are the same as at 

proposal. Specifically, a listed method 

may be considered inappropriate if the 

relevant compounds cannot be detected, 

the quality control requirements are not 

technically feasible, or use of the 

method will be unsafe. 

We are amending the reporting 

requirements in 40 CFR 98.246(a)(11), as 

proposed, so that if an alternative 

method is used, facilities must include 

in the annual report the name or title of 

the method used and, the first time it is 

used, a copy of the method and an 

explanation of why the use of the 

alternative method is necessary. Also as 

proposed, the amendments to 40 CFR 

98.244(b)(4) may be used for the 2010 

reporting year. 

QA/QC requirements. To maintain 

consistency with the amendments to 40 

CFR 98.3(i), we are amending, as 

proposed, the QA/QC provisions for 

weighing devices, flow meters, and tank 

level measurement devices in 40 CFR 

98.244 (b)(1), (b)(2), and (b)(3). 

Reporting requirements under the 

CEMS compliance option. As proposed, 

we are making a number of changes in 


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40 CFR 98.246(b)(1) through (b)(5) to 

clarify the reporting requirements under 

the CEMS compliance option. 

First, we are moving the requirement 

for reporting of the petrochemical 

process ID from 40 CFR 98.246(b)(3) to 

40 CFR 98.246(b)(1) to be consistent 

with the structure in other reporting 

sections, and we are renumbering the 

existing paragraphs (b)(1) and (b)(2). 

Second, we are adding a statement in 

the renumbered paragraph 40 CFR 

98.246(b)(2) to specify that the reporting 

requirements in 40 CFR 98.36(b)(9)(iii) 

(as numbered in today’s action) for CH4

and N2O do not apply under subpart X 

because applicable reporting 

requirements are specified in 40 CFR 

98.246(b)(5). 

Third, in the renumbered 40 CFR 

98.246(b)(3), we are deleting the 

requirement to report information 

required under 40 CFR 98.36(e)(2)(vii) 

because the referenced section specifies 

recordkeeping requirements, not 

reporting requirements. Note that one 

must still keep the applicable records 

because 40 CFR 98.247(a) references 40 

CFR 98.37, which in turn requires you 

to keep all of the applicable records in 

40 CFR 98.36(e). We are also amending 

the reference to 40 CFR 98.36(e)(2)(vii) 

to a more general reference of 40 CFR 

98.36. This makes the reporting 

requirements consistent with the 

methodology for calculating emissions 

in 40 CFR 98.243(b). 

Fourth, we are amending 40 CFR 

98.246(b)(4) to clarify our intent. The 

first sentence in 40 CFR 98.246(b)(4) 

requires reporting of the total CO2

emissions from each stack that is 

monitored with CO2 CEMS; this 

requirement will be unchanged. We are 

amending the second sentence in 40 

CFR 98.246(b)(4) to clarify that for each 

CEMS that monitors a combustion unit 

stack, you must estimate the fraction of 

the total CO2 emissions that is from 

combustion of the petrochemical 

process off-gas in the fuel gas. This 

estimate will give an indication of the 

total petrochemical process emissions, 

whereas the CEMS data alone will also 

include emissions from combustion of 

supplemental fuel (if any). 

Finally, as proposed, we are finalizing 

several amendments to 40 CFR 

98.246(b)(5). In general, as noted above, 

the requirements in this paragraph are 

consistent with the requirements in 40 

CFR 98.36(b)(9)(iii) (as numbered in this 

action). Most of the amendments to 40 

CFR 98.246(b)(5) restate requirements 

from 40 CFR 98.36(b)(9)(iii); for 

example, the amendments clarify that 

emissions are to be reported in metric 

tons of each gas and in metric tons of 

CO2e. However, because 40 CFR 

98.36(b)(9)(iii) allows you to consider 

petrochemical process off-gas as a part 

of ‘‘fuel gas’’ rather than as a separate 

fuel, under 40 CFR 98.246(b)(5) you 

must also estimate the fraction of total 

CH4 and N2O emissions in the exhaust 

from each stack that is from combustion 

of the petrochemical process off-gas. In 

addition, because 40 CFR 98.243(b) 

requires you to determine CH4 and N20 

emissions using Equation C–8 in 

subpart C (rather than Equation C–10), 

the amendments to 40 CFR 98.246(b)(5) 

require reporting of the HHV that you 

use in Equation C–8. We are also 

deleting the erroneous reference to 

Equation C–10 that was included in 40 

CFR 98.246(b)(5). 

Reporting requirements for the 

ethylene-specific option. As proposed, 

we are finalizing several amendments to 

clarify the reporting requirements in 40 

CFR 98.246(c) for the combustion-based 

methodology that is available to the 

ethylene-specific option. First, we are 

adding a requirement to report each 

ethylene process ID to allow 

identification of the applicable process 

units at facilities with more than one 

ethylene process unit. Second, we are 

making editorial changes to clarify that 

you must estimate the fraction of total 

combustion emissions that is due to 

combustion of ethylene process off-gas, 

consistent with the requirements 

described above for combustion units 

that are monitored with CEMS. Third, 

we are replacing the requirement to 

report the ‘‘annual quantity of each type 

of petrochemical produced from each 

process unit’’ with a requirement to 

report the ‘‘annual quantity of ethylene 

produced from each process unit.’’ 

Reporting measurement device 

calibrations. As proposed in 40 CFR 

98.246(a)(7) we are deleting the 

requirement for reporting of the dates 

and summarized results of calibrations 

of each measurement device under the 

mass balance option, and we are also 

adding 40 CFR 98.247(b)(4) to require 

retention of these records. 

Major changes since proposal are 

identified in the following list. The 

rationale for these and any other 

significant changes can be found in this 

preamble or the document, ‘‘Response to 

Comments: Revision to Certain 

Provisions of the Mandatory Reporting 

of Greenhouse Gases Rule’’ (see EPA– 

HQ–OAR–2008–0508). 

• Additional methods for determining 

carbon content or composition of 

feedstocks and products were added to 

40 CFR 98.244(b)(4). 

• For the optional combustion 

method for ethylene processes, the 

introductory paragraph in 40 CFR 

98.243(d) was edited to require 

calculation of GHG emissions from 

‘‘combustion units’’ rather than from 

‘‘each combustion unit.’’ This change 

makes it clear that the common pipe 

reporting alternative specified in 40 CFR 

98.36(c)(3) of subpart C may be used 

when applicable, and it makes 40 CFR 

98.243(d) consistent with the reporting 

requirements for the ethylene process 

option as specified in 40 CFR 98.246(c). 

• For the mass balance option, 40 

CFR 98.243(c)(3) was revised to specify 

that multiple deliveries of a particular 

liquid or solid feedstock in a month 

from the same supply source may be 

considered a single feedstock lot, 

requiring only one representative 

sample for carbon content analysis. This 

change makes the analysis requirements 

for feedstocks consistent with the 

amended requirements for fuels in 40 

CFR 98.34(b)(3)(ii)(B). 

2. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. 

Several comments were received on this 

subpart. Responses to additional 

significant comments received can be 

found in the document, ‘‘Response to 

Comments: Revision to Certain 

Provisions of the Mandatory Reporting 

of Greenhouse Gases Rule’’ (see EPA– 

HQ–OAR–2008–0508). 

Comment: Several commenters 

requested either the addition of specific 

carbon content or composition 

measurement methods in 40 CFR 

98.244(b)(4) or other changes that would 

increase measurement flexibility. One 

commenter requested that EPA Method 

9060 of SW–846 be added to the list of 

methods, and that the list of methods be 

modified to allow for the use of a 

company-specific method for measuring 

acetonitrile as an alternative to using 

EPA Method 8015 in SW–846. One 

commenter requested that ASTM 

D7633, Standard Test Method for 

Carbon Black—Carbon Content, be 

added to the list of methods because it 

has recently been accepted and 

approved by ASTM. This commenter 

also noted that ASTM is currently 

reviewing a method for carbon content 

in carbon black feedstock oils and 

requested addition of a statement 

indicating that once this method is 

approved and assigned an official 

number by ASTM that it is effective as 

of January 1, 2010. One commenter 

requested that EPA remove the reference 

to ‘‘analytical’’ in the phrase ‘‘other 

analytical methods’’ in proposed 40 CFR 

98.244(b)(4)(xiii) (renumbered as 

paragraph (xv)(A) in the final 

amendments) so that the carbon content 

of ethylene oxide and water solutions 


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could be measured using a 

densitometer. One commenter stated 

that 40 CFR 98.244(b)(4) should be 

expanded to allow the use of an on-line 

mass spectrometer to determine the 

carbon content and molecular weights. 

One commenter stated that 

requirements for gas chromatography 

should be consistent across all subparts 

and that EPA should extend the 

requirements for the use of gas 

chromatographs under subpart C to 

subpart X. Specifically, the commenter 

requested that the use of gas 

chromatographs be allowed, ‘‘provided 

that the gas chromatograph is operated, 

maintained, and calibrated according to 

the manufacturer’s instructions.’’ One 

commenter noted that the proposed 

amendments to subpart C added 

flexibility to the carbon content analysis 

requirements for fuels by eliminating 

the list of specific methods and instead 

allowing a broader array of methods 

(i.e., industry consensus standard 

practice, method published by a 

consensus-based standards organization, 

or results of gas chromatographic 

analysis). This commenter stated that 

the same flexibility should be allowed 

for feedstock and product analysis 

under subpart X. 

Response: In the preamble to the 

proposed amendments we indicated 

that we would consider adding carbon 

content methods for carbon black and 

carbon black feedstock oil if they were 

approved by ASTM before publication 

of the final amendments. Because it has 

been approved by ASTM, we have 

added Method D7633, Standard Test 

Method for Carbon Black—Carbon 

Content, to 40 CFR 98.244(b)(4). We 

have not added the requested statement 

regarding the method for determining 

carbon content in carbon black 

feedstock oil because we cannot cite a 

specific method without being able to 

incorporate it by reference, and 

incorporation by reference is possible 

only if a copy of the method is available. 

However, if this method is a current 

industry standard practice, its use since 

January 1, 2010, is allowed by 40 CFR 

98.244(b)(4)(xv) of the final 

amendments. 

We have also decided to make four of 

the other changes suggested by 

commenters. First, we have added EPA 

Method 9060A in SW–846 because a 

commenter indicated that it is much 

more effective at detecting organic 

compounds in a liquid waste stream 

than any of the listed methods. Because 

none of the currently listed methods 

effectively detect these compounds in 

the waste stream, an alternative method 

such as EPA Method 9060A in SW–846 

would already be allowed under 40 CFR 

98.244(b)(4)(xv)(A) of the final 

amendments. However, specifically 

listing the method will make 

demonstrating compliance more 

straightforward. 

Second, we have deleted the word 

‘‘analytical’’ from the phrase ‘‘other 

analytical methods’’ in 40 CFR 

98.244(b)(4)(xv)(A) of the final 

amendments so that non-analytical 

methods can be used. We agree with the 

commenter that this change is needed so 

that a densitometer can be used to 

determine the carbon content in an 

ethylene oxide and water solution. We 

also agree that a non-analytical 

alternative must be available in cases 

where the carbon content of the solution 

cannot safely be determined using any 

of the listed analytical methods or 

modifications of them. 

Third, we have added the option from 

subpart C to use results from a gas 

chromatograph, provided the 

instrument is operated, maintained, and 

calibrated according to the 

manufacturer’s instructions. This 

change means there is a common option 

in both subparts C and X, which we 

have determined is important because 

some materials may be a fuel in some 

applications and a petrochemical 

feedstock in others (e.g., ethylene 

feedstocks). With this change, a facility 

would not have to use two methods to 

determine the carbon content of the 

same material. 

Fourth, we have added an option to 

use a mass spectrometer to determine 

the carbon content of a feedstock or 

product. Although a mass spectrometer 

would more commonly be used as one 

type of detector to determine the 

concentration of individual compounds 

separated in a gas chromatograph, using 

a mass spectrometer alone to determine 

the overall carbon content is also 

acceptable. 

Finally, we have decided not to delete 

the list of specified methods and replace 

them with a general statement allowing 

the use of any industry consensus 

standard practice or method published 

by a consensus-based standards 

organization. We have received 

considerable input from the industry on 

methods that are actually being used. 

We conclude that the existing flexibility 

in the final amendments is sufficient, 

and that there is no need to allow the 

use of other unspecified methods. We 

recognize that this is not consistent with 

the methodologies allowed for 

determining carbon content in subpart 

C; however, we have concluded that this 

is justified given the wide variety of 

industries subject to subpart C versus 

the more narrowly-focused sources 

subject to subpart X. 

We are not specifically allowing the 

use of a company-specific method for 

the determination of carbon content in 

acetonitrile because we are not 

convinced that it is necessary. The 

commenter indicated that they can use 

EPA Method 8015 of SW–846, and they 

have not indicated any problems with 

using this method. It is also possible 

that their company-specific method 

would qualify as a modification to a 

listed method that would be allowed if 

any of the criteria in 40 CFR 

98.244(b)(4)(xv)(A) of the final 

amendments are met. Therefore, we 

have not made the requested change. 

Comment: One commenter requested 

a modification to 40 CFR 98.243(c)(3) 

for carbon black production processes 

that specifies all deliveries of a fuel or 

feedstock oil in a month from the same 

supply source are considered to be a 

fuel lot, and carbon content must be 

determined for only one representative 

sample from the lot. 

Response: Although we did not 

propose amendments to the sampling 

and analysis requirements in 40 CFR 

98.243(c)(3), we did propose a change 

similar to that suggested by the 

commenter in 40 CFR 98.34(b)(3)(ii)(B) 

of subpart C for fuels. Subpart X 

currently requires you to determine the 

carbon content for at least one sample 

of each feedstock and product per 

month. In addition, if you make more 

than one valid carbon content 

measurement during the month (from 

separate samples), then you must 

average the results arithmetically. (Note 

that this language does not require 

sampling and analysis for each delivery 

of a feedstock. Furthermore, each 

delivery of the same material, even from 

different suppliers, is not considered to 

be a separate feedstock.) However, we 

agree with the commenter that if 

multiple deliveries of the same 

feedstock are received from the same 

supply source, one representative 

sample is sufficient for the month. 

Therefore, we have amended 40 CFR 

98.243(c)(3) in the interest of improving 

the operating flexibility of the rule. We 

have also broadened the statement so 

that it applies for any liquid or solid 

feedstock. Please see the amended rule 

language to 40 CFR 98.243(c)(3). 

Comment: One commenter stated that 

the proposed term ‘‘each combustion 

unit’’ in the introductory paragraph of 

40 CFR 98.243(d) appears to preclude 

the use of the common pipe reporting 

alternative in 40 CFR 98.36(c)(3). 

According to the commenter, the 

common pipe option is appropriate for 

ethylene processes, and precluding it 

will not improve the quality of GHG 

emission estimates. Therefore, the 


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79124 Federal Register / Vol. 75, No. 242 / Friday, December 17, 2010 / Rules and Regulations 

commenter requests that ‘‘each 

combustion unit’’ be changed to 

‘‘combustion units.’’ 

Response: We have made the 

suggested change in the final 

amendments because we agree with the 

commenter’s assessment of the 

proposed language. We did not intend 

to preclude the use of the common pipe 

option, as evidenced by the fact that 40 

CFR 98.243(d)(2)(i) and (ii) both specify 

that the determination of when Tier 1 

and Tier 2 procedures may be used is 

to be based on whether there is an 

existing flow meter either in the line to 

the combustion device or an upstream 

common pipe. Moreover, the reporting 

requirements in 40 CFR 98.246(c)(2) 

require reporting for each stationary 

combustion unit, or group of stationary 

sources with a common pipe. 

N. Subpart Y—Petroleum Refineries 

1. Summary of Final Amendments and 

Major Changes Since Proposal 

Numerous issues have been raised by 

owners and operators in relation to the 

requirements in subpart Y for petroleum 

refineries. The issues being addressed 

by the amendments include the 

following: 

• GHG emissions from flares. 

• GHG emissions to report from 

combustion of fuel gas. 

• GHG emissions to report from nonmerchant hydrogen production process 

units. 

• Calculating GHG emissions from 

fuel gas combustion. 

• Calculating combustion GHG 

emissions from flares and asphalt 

blowing operations controlled by 

thermal oxidizer or flare. 

• Molar volume conversion factors. 

• Combined stacks monitored by 

CEMS. 

• Nitrogen concentration monitoring 

to determine exhaust gas flow rate. 

• Calculating CO2 emissions from 

catalytic reforming units. 

• Calculating GHG emissions from 

sulfur recovery plants. 

• Calculating CO2 emissions from 

coke calcining units. 

• Calculating CO2 emissions from 

process vents. 

• Monitoring and QA/QC 

requirements. 

• Reporting requirements. 

GHG emissions from flares. We are 

finalizing corrections to 40 CFR 

98.252(a) (GHGs to report) as proposed 

to clarify the required emissions 

methods for flares. We are proposing to 

amend the second sentence in 40 CFR 

98.252(a) to correctly require reporters 

to ‘‘Calculate and report the emissions 

from stationary combustion units under 

subpart C * * *’’ and we are proposing 

to add an additional sentence at the end 

of this section to clarify that reporters 

must ‘‘Calculate and report the 

emissions from flares under this 

subpart.’’ 

GHG emissions to report from 

combustion of fuel gas. We are 

finalizing amendments to 40 CFR 

98.252(a) as proposed to clarify that 

reporting of CH4 and N2O emissions is 

required for the stationary combustion 

units fired with fuel gas. As described 

in Section II.G of this preamble, we are 

also amending the definition of fuel gas. 

GHG emissions to report from nonmerchant hydrogen production process 

units. As proposed, we are amending 40 

CFR 98.252(i) to clarify that reporting of 

only CO2 emissions is required for nonmerchant hydrogen production process 

units. 

Calculating GHG emissions from fuel 

gas combustion. We are finalizing 

amendments to 40 CFR 98.252(a), as 

proposed, so that petroleum refineries 

subject to subpart Y can use the Tier 1 

or 2 methodologies in subpart C for 

combustion of fuel gas when either of 

the following conditions exists: 

• The annual average fuel gas flow rate 

in the fuel gas line to the combustion 

unit, prior to any split to individual 

burners or ports, does not exceed 345 

scfm at 60 °F and 14.7 psia, and either 

of the following conditions exists: 

—A flow meter is not installed at any 

point in the line supplying fuel gas 

or an upstream common pipe; or 

—The fuel gas line contains only 

vapors from loading or unloading, 

waste or wastewater handling, and 

remediation activities that are 

combusted in a thermal oxidizer or 

thermal incinerator. 

• The combustion unit has a maximum 

rated heat input capacity of less than 

30 mmBtu/hr, and either of the 

following conditions exists: 

—A flow meter is not installed at any 

point in the line supplying fuel gas 

or an upstream common pipe; or 

—The fuel gas line contains only 

vapors from loading or unloading, 

waste or wastewater handling, and 

remediation activities that are 

combusted in a thermal oxidizer or 

thermal incinerator. 

Calculating combustion GHG 

emissions from flares and asphalt 

blowing operations controlled by 

thermal oxidizer or flare. As proposed, 

we are finalizing amendments to 40 CFR 

98.253 to renumber existing Equations 

Y–1 and Y–16 as Equations Y–1a and 

Y–16a, and adding the more detailed 

Equations Y–1b and Y–16b that provide 

more detailed alternative methods for 

calculating emissions. We are also 

finalizing corresponding amendments in 

40 CFR 98.256 as proposed to require 

reporting of which equation was used 

and, if the new equations are used, 

reporting of the additional equation 

parameters. 

Molar volume conversion factors. We 

are finalizing amendments to Equations 

Y–1, Y–3, Y–6, Y–12, Y–18, Y–19, Y–20, 

and Y–23 in subpart Y as proposed to 

provide two alternative values of MVC 

depending on the standard conditions 

output by the flow monitors. For 

reasons outlined in the ‘‘Response to 

Comments: Revision to Certain 

Provisions of the Mandatory Reporting 

of Greenhouse Gases Rule’’ (see EPA– 

HQ–OAR–2008–0508), we are also 

finalizing a similar amendment to 

Equation Y–2, as a logical outgrowth of 

the proposal and comments received to 

provide two alternative values of MVC 

in this equation (if mass flow monitors 

are used) depending on the standard 

conditions at which the higher heating 

value is determined. Additionally, the 

reporting requirements related to each 

of these equations are being amended to 

include reporting of the value of MVC 

used to support the calculations and to 

allow verification of the reported 

emissions. 

Combined stacks monitored by CEMS. 

As proposed, we are amending the 

language in 40 CFR 98.253(c)(1)(ii) and 

also the reporting requirements in 40 

CFR 98.256(f)(6) to generalize the 

language to include other CO2 emission 

sources, not just a CO boiler. 

Nitrogen concentration monitoring to 

determine exhaust gas flow rate. As 

proposed, we are amending 40 CFR 

98.253(c)(2)(ii) to renumber Equation Y– 

7 as Equation Y–7a and to add an 

Equation Y–7b to provide an alternative 

N2 concentration monitoring approach 

for determining the exhaust gas flow 

rate. We are also finalizing reporting 

requirements in 40 CFR 98.256(f)(9) to 

report the input parameters for Equation 

Y–7b if it is used. 

Calculating CO2 emissions from 

catalytic reforming units. We are 

finalizing amendments to the definition 

of the coke burn-off quantity, CBQ, and 

the term ‘‘n’’ in Equation Y–11 in 40 CFR 

98.253(e)(3) as proposed to clarify the 

application of Equation Y–11 to 

continuously regenerated catalytic 

reforming units. 

Calculating GHG emissions from 

sulfur recovery plants. We are amending 

40 CFR 98.253(f) as proposed to add 

‘‘and for sour gas sent off site for sulfur 

recovery’’ to clarify that this calculation 

methodology applies ‘‘For on-site sulfur 

recovery plants and for sour gas sent off 

site for sulfur recovery, * * *’’ and to 


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allow non-Claus sulfur recovery plants 

to alternatively follow the requirements 

in 40 CFR 98.253(j) for process vents. 

We also are finalizing amendments to 

the reporting requirements in 40 CFR 

98.256(h) as proposed to include the 

type of sulfur recovery plant, an 

indication of the method used to 

calculate CO2 emissions, and reporting 

requirements for non-Claus sulfur 

recovery plants that elect to follow the 

requirements in 40 CFR 98.253(j) for 

process vents. 

Calculating CO2 emissions from coke 

calcining units. We are amending the 

definition of Mdust (the mass of dust 

collected in the dust collection system) 

in Equation Y–13 in 40 CFR 98.253(g) as 

proposed to clarify that dust recycled 

back to the coke calciner is not included 

in the mass of dust collected in the dust 

collection system (Mdust). We also are 

finalizing amendments to 40 CFR 

98.256(i)(5), as proposed, to require 

facilities that use Equation Y–13 to 

indicate whether or not the collected 

dust is recycled to the coke calciner. 

Calculating CO2 emissions from 

process vents. We are finalizing 

amendments to the process vent 

requirements in 40 CFR 98.253(j) as 

proposed to account for the additional 

sources that may elect to use Equation 

Y–19, specifically non-Claus sulfur 

recovery units (as previously described) 

and uncontrolled blowdown vents 

(inadvertently not referenced). We are 

also amending the reporting 

requirements for process vents in 40 

CFR 98.256(l) as proposed to clarify that 

the requirements apply to each process 

vent, and 40 CFR 98.256(l)(5) to require 

an indication of the measurement or 

estimation method for the volumetric 

flow rate and the mole fraction of the 

GHG in the vent. 

Finally, we are finalizing amendments 

to 40 CFR 98.253(n) as proposed to 

delete the words ‘‘equilibrium’’ and 

‘‘product-specific’’ to clarify that the true 

vapor phase of the loading operation 

system should be used when 

determining whether the vapor-phase 

concentration of methane is 0.5 volume 

percent or more. 

Monitoring and QA/QC requirements. 

We are finalizing amendments to the 

monitoring and QA/QC requirements in 

subpart Y, 40 CFR 98.254 as proposed, 

except as provided below. We proposed 

amendments to require all gas flow 

meters on process vents subject to 

reporting under 40 CFR 98.253(j) to 

comply with the monitoring 

requirements in 40 CFR 98.254(f). 

However, for the reasons set forth in the 

Response to Comments (Section N.2. of 

this preamble), we are finalizing 

amendments for gas flow meters on 

process vents subject to reporting under 

40 CFR 98.253(j) to comply with the 

monitoring requirements in 40 CFR 

98.254(c). 

A summary of the amendments to the 

monitoring and QA/QC requirements 

that we are finalizing as proposed is 

below. Paragraph (a) of 40 CFR 98.254 

is amended to include also the phrase 

‘‘sources that use a CEMS to measure 

CO2 emissions according to subpart C of 

this part * * *’’ to separate further these 

sources from those that are covered by 

40 CFR 98.254(b). We also are rewording the phrase ‘‘follow the 

monitoring and QA/QC requirements in 

§ 98.34’’ with ‘‘meet the applicable 

monitoring and QA/QC requirements in 

§ 98.34’’ to clarify that the monitors 

must meet the requirements for the 

specific tier for which monitoring was 

required (Tier 3 sources will comply 

with the Tier 3 requirements; Tier 4 

sources will comply with the Tier 4 

requirements; etc.). 

Because the QA/QC requirements for 

CO2 CEMS that were formerly included 

in 40 CFR 98.254(l) will be included in 

the amended paragraph 40 CFR 

98.254(a), we are removing 40 CFR 

98.254(l). 

Paragraph (b) of 40 CFR 98.254 is 

amended to clarify that these 

requirements apply to gas flow meters, 

gas composition monitors, and heating 

value monitors other than those subject 

to 40 CFR 98.254(a). We are correcting 

the reference to ‘‘paragraphs (c) through 

(e)’’ to correctly reference ‘‘paragraphs 

(c) through (g)’’ as gas monitoring system 

requirements are specified in 40 CFR 

98.254(c) through (g). We are also 

clarifying that the calibration 

requirements in 40 CFR 98.3(i) only 

apply to gas flow meters and allowing 

recalibration of gas flow meters 

biennially (every two years), at the 

minimum frequency specified by the 

manufacturer, or at the interval 

specified by the industry consensus 

standard practice used. Paragraph (b) of 

40 CFR 98.254 is also amended to 

clarify that gas composition and heating 

value monitors must be recalibrated 

either annually, at the minimum 

frequency specified by the 

manufacturer, or at the interval 

specified by the industry consensus 

standard practice used. 

Paragraph (c) of 40 CFR 98.254 is 

amended to clarify that the flare or sour 

gas flow meters must be calibrated (in 

addition to operated and maintained) 

using either a method published by a 

consensus-based standards organization 

(e.g., ASTM, API, etc.) or the procedures 

specified by the flow meter 

manufacturer. The ±5 percent accuracy 

specification is being removed from 40 

CFR 98.254(c). We are also amending 40 

CFR 98.254(c) by removing the list of 

methods as this is redundant to the 

existing phrase, ‘‘a method published by 

a consensus-based standards 

organization.’’ 

Paragraphs (d) and (e) of 40 CFR 

98.254 are amended to allow the use of 

any chromatographic analysis to 

determine flare gas composition and 

high heat value, as an alternative to the 

methods listed in 40 CFR 98.254(d) and 

(e), provided that the gas chromatograph 

is operated, maintained, and calibrated 

according to the manufacturer’s 

instructions. The methods used for 

operation, maintenance, and calibration 

of the gas chromatograph must be 

documented in the written monitoring 

plan for the unit under 40 CFR 

98.3(g)(5). Paragraph (d) in 40 CFR 

98.254 is also amended to apply to all 

gas composition monitors, other than 

those included in 40 CFR 98.254(g), and 

not just flare gas composition monitors. 

We are also amending 40 CFR 

98.254(d) to specify that the methods in 

this paragraph are also to be used for 

determining average molecular weight 

of the gas, which is needed in Equations 

Y–1a and Y–3. We are also adding an 

additional method (ASTM D2503–92) to 

this section for determining average 

molecular weight. 

We are making a number of 

amendments to 40 CFR 98.254(f). The 

term ‘‘exhaust gas flow meter’’ is 

replaced with the term ‘‘gas flow meter,’’ 

as proposed. 

We are retaining 40 CFR 98.254(f)(3) 

and portions of 40 CFR 98.254(f)(1) but 

only as general, supplementary 

guidelines for flow monitor installation 

and operation. Thus, we are amending 

40 CFR 98.254 to require that reporters 

must do all of the following: 

• Install, operate, calibrate, and 

maintain each stack gas flow meter 

according to the requirements in 40 CFR 

63.1572(c); 

• Locate the flow monitor at a site 

that provides representative flow rates 

(avoiding locations where there is 

swirling flow or abnormal velocity 

distributions); and 

• Use a monitoring system capable of 

correcting for the temperature, pressure, 

and moisture content to output flow in 

dry standard cubic feet (standard 

conditions as defined in 40 CFR 98.6). 

We are making a technical correction 

to 40 CFR 98.254(g) to correct the crossreference from 40 CFR 63.1572(a) to 40 

CFR 63.1572(c). 

We are amending 40 CFR 98.254(h) to 

require calibration of mass measurement 

equipment according to the procedures 

specified by National Institute of 

Standards and Technology (NIST) 


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79126 Federal Register / Vol. 75, No. 242 / Friday, December 17, 2010 / Rules and Regulations 

Handbook 44 or the procedures 

specified by the manufacturer, and 

removing reference to the calibration 

requirements in 40 CFR 98.3(i). 

Reporting requirements. This section 

covers reporting requirements that have 

not been described in previous sections 

of this preamble. 

We are amending the reporting 

requirements in 40 CFR 98.256(e)(6) and 

(8) for Equations Y–1 (renumbered to Y– 

1a) and Y–2, respectively, to require 

reporting of whether daily or weekly 

measurement periods are used, for 

verification purposes. 

In 40 CFR 98.256(f)(6), 40 CFR 

98.256(h)(6), and 40 CFR 98.256(i)(6), 

we are amending the references to 40 

CFR 98.36(e)(2)(vi) to reference 40 CFR 

98.36 more generally. This will make 

the references consistent with the 

associated requirements in 40 CFR 

98.253. 

We are amending 40 CFR 98.256(f) to 

require reporting of the unit-specific 

emission factor for CH4 and N2O, if 

used, in the newly designated 40 CFR 

98.256(f)(11) and (12), respectively. 

We are amending 40 CFR 98.256(i)(8) 

to make it consistent with the 

information collected in 40 CFR 

98.245(i)(7). 

We are also amending 40 CFR 

98.256(j)(2) to clarify that the reporting 

requirements for asphalt blowing apply 

at the unit level. 

We are also amending 40 CFR 

98.256(o) to re-organize the reporting 

requirements to separate and clarify the 

reporting requirement for storage tanks 

used for processing unstabilized crude 

oil from those reporting requirements 

for other types of storage tanks. 

Major changes since proposal are 

identified in the following list. The 

rationale for these and any other 

significant changes can be found in this 

preamble or the document, ‘‘Response to 

Comments: Revision to Certain 

Provisions of the Mandatory Reporting 

of Greenhouse Gases Rule’’ (see EPA– 

HQ–OAR–2008–0508). 

• Amending Equation Y–2 in subpart 

Y to provide two alternative values of 

MVC in this equation (if mass flow 

monitors are used) depending on the 

standard conditions at which the higher 

heating value is determined. 

• Amending requirements for gas 

flow meters on process vents subject to 

reporting under 40 CFR 98.253(j) to 

comply with the monitoring 

requirements in 40 CFR 98.254(c) rather 

than 40 CFR 98.254(f). 

2. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. 

Several comments were received on this 

subpart. Responses to additional 

comments received can be found in the 

document, ‘‘Response to Comments: 

Revision to Certain Provisions of the 

Mandatory Reporting of Greenhouse 

Gases Rule’’ (see EPA–HQ–OAR–2008– 

0508). 

Comment: One commenter stated that 

they have identified gas streams that 

would otherwise fit the requirements for 

the use of the Tier 1 or Tier 2 

methodologies, as proposed in 40 CFR 

98.252(a)(1) and (2), if it were not for the 

fact that they are equipped with flow 

meters. According to the commenter, 

these streams are not what industry 

would define as ‘‘refinery fuel gas’’ but 

would fall under the realm of ‘‘fuel gas’’ 

as originally defined in 40 CFR 98.6 in 

the October 30, 2009, final Part 98, and 

in the amended definition. These can 

include streams that are process off-gas 

or vent gases with properties much 

different from traditional ‘‘refinery fuel 

gas’’ streams and are not part of the 

refinery’s fuel gas system. According to 

the commenter, these off-gas streams 

may not be sampled currently. The 

commenter asserted that many of these 

streams are difficult to sample (for 

example, because of low pressure) or 

may present hazardous sampling 

conditions. According to the 

commenter, the added rigor associated 

with Tier 3 requirements is not justified 

for the increased safety risk, considering 

the very small contribution of emissions 

(on the order of 0.1 percent of a 

refinery’s total greenhouse gas 

emissions as estimated by the 

commenter). 

Response: The proposed amendments 

provided limited exclusions to the Tier 

3 requirement for very small fuel gas 

lines or combustion units that are not 

equipped with a flow meter. As noted 

in the preamble of the August 11, 2010, 

proposed amendments, the exclusion 

was specifically targeted to prevent the 

need to install flow meters for these 

small fuel gas lines. EPA noted that ‘‘[i]f 

flow meters are in place at the process 

heater or at a common pipe location, we 

consider that the Tier 3 monitoring 

requirements are reasonable and 

justified.’’ (See 75 FR 48772.) The 

commenter indicated that these gas 

streams could have a significantly 

different composition than typical 

refinery fuel gas, which suggests the 

default fuel gas factor would have 

considerable uncertainty for these gas 

streams, further indicating that Tier 3 

sampling is necessary. While we 

recognize that there are inherent safety 

issues with sampling any fuel gas 

streams, the commenter has not 

provided any supporting information for 

the assertion that sampling these 

‘‘process off-gas or vent gases’’ is more 

hazardous than other fuel gas streams at 

the refinery. Therefore, we are not 

expanding the proposed exclusion to 

the Tier 3 methodology for fuel gas lines 

that have a flow meter already installed 

in the line or upstream common pipe. 

We also note that today’s final 

amendments are not imposing new 

requirements to sample these fuel gas 

streams; the October 30, 2009, final Part 

98 already required these fuel gas 

streams to be sampled for carbon 

content no less than once per calendar 

week. 

Comment: One commenter objected to 

the proposed revision of 40 CFR 

98.254(f) to also require exhaust gas 

flow meters associated with process 

vents (i.e., subject to 40 CFR 98.253(j) 

requirements) to be installed, operated, 

calibrated and maintained according the 

Petroleum Refineries NESHAP (40 CFR 

part 63, subpart UUU) requirements in 

40 CFR 63.1572(c). According to the 

commenter, the Petroleum Refineries 

NESHAP requirements in 40 CFR 

63.1572(c) contain provisions that are 

more stringent than the monitoring and 

QA/QC requirements throughout Part 

98. For example, 40 CFR 63.1572(c) 

requires each monitoring system to have 

valid hourly average data from at least 

75 percent of the hours during which 

the process operated and to complete a 

minimum of one cycle of operation for 

each successive 15-minute period with 

a minimum of four successive cycles of 

operation to have a valid hour of data 

(or at least two if a calibration check is 

performed during that hour or if the 

continuous parameter monitoring 

system is out-of-control). The 

commenter stated that, since the flow 

monitoring requirements for the 

Petroleum Refineries NESHAP in 40 

CFR 63.1572(c) were established to 

demonstrate compliance with emission 

limits, they should not be used as a 

template for requirements of flow 

metering for GHG reporting. The 

commenter recommended that the 

process vent exhaust flow meter 

requirements should be consistent with 

the requirements in 40 CFR 98.254(c) for 

flare and sour gas flow meters. 

Response: We proposed to include the 

requirements for flow meters used to 

comply with the 40 CFR 98.253(j) for 

process vents within the monitoring 

provisions of 40 CFR 98.254(f) because 

these meters are exhaust gas flow meters 

rather than fuel gas flow meters. 

However, we agree with the commenter 

that the inclusion of flow meters used 

to comply with the 40 CFR 98.253(j) 

within the monitoring provisions of 40 

CFR 98.254(f) added new requirements 


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Federal Register / Vol. 75, No. 242 / Friday, December 17, 2010 / Rules and Regulations 79127 

to these flow meters. While we believe 

that the flow meter requirements in 40 

CFR 63.1572(c) of the Petroleum 

Refineries NESHAP are reasonable 

requirements for exhaust gas flow 

meters in general (40 CFR 63.1572(c) are 

requirements for parameter monitoring 

systems, not continuous emission 

monitoring systems), we agree with the 

commenter that it is inappropriate to 

add these requirements to process vent 

flow meters at this juncture. 

Furthermore, the provisions in 40 CFR 

98.253(j) allow use of process 

knowledge or engineering calculations 

as an alternative to direct flow 

measurement. As such, it is incongruous 

to subject facilities that have flow 

meters on these process vents to 

additional requirements when facilities 

that do not have flow meters on these 

process vents may use process 

knowledge or engineering calculations. 

Therefore, we are finalizing 

requirements for flow meters used to 

comply with 40 CFR 98.253(j) for 

process vents to meet the monitoring 

provisions of 40 CFR 98.254(c) rather 

than 40 CFR 98.254(f) as was required 

per the October 30, 2009 final Part 98. 

O. Subpart AA—Pulp and Paper 

Manufacturing 

1. Summary of Final Amendments and 

Major Changes Since Proposal 

We are amending 40 CFR 98.273(a)(1), 

(b)(1) and (c)(1) to clarify that owners 

and operators may choose to use a tier 

other than Tier 1 from 40 CFR 98.33 to 

calculate fossil-fuel based CO2

emissions. 

We have removed the CO2 emission 

factors from Table AA–2 and revised 40 

CFR 98.273(c)(1) to direct owners and 

operators to use the CO2 emission 

factors from Table C–1 of subpart C to 

calculate CO2 emissions from lime kilns. 

With respect to calculating CH4 and 

N2O emissions from fossil fuel 

combustion at lime kilns, and consistent 

with the amendments to allow use of 

higher tiers than Tier 1 for units subject 

to subpart AA, we are amending 40 CFR 

98.273(a)(2), (b)(2), and (c)(2) to allow 

reporters to also use site-specific high 

heating values, as opposed to default 

values, when calculating CH4 and N2O 

emissions. We are making harmonizing 

amendments to the definition of EF 

under Equation AA–1 to clarify that 

default or site-specific emission factors 

may be used. Similarly, we are 

amending 40 CFR 98.276(e) to reflect 

the option to use default or site-specific 

values. 

We are clarifying through this final 

rule that emissions from the combustion 

of wastewater treatment sludge are 

calculated using the emission factors 

included in Table C–1. We have 

determined that this sludge falls within 

the definition of ‘‘Wood and Wood 

Residuals’’ included in Table C–1. 

Therefore, per 40 CFR 98.33(b)(1)(iii), 

emissions from the combustion of this 

type of sludge may be determined using 

Tier 1 in subpart C. In order to further 

clarify this, we are adding the definition 

of ‘‘Wood and Wood Residuals’’ to 40 

CFR 98.6 and including wastewater 

process sludge from paper mills in this 

definition, as further described in 

Section II.F of this preamble. 

We are adding solid petroleum coke 

to both Table C–1 and Table AA–2. We 

have concluded that it is not necessary 

to have emission factors for petroleum 

coke specific to kraft calciners in Table 

AA–2 because we do not believe that 

any kraft calciners are combusting this 

fuel, nor were any comments received 

suggesting this was not the case. 

There were no comments received 

specifically on subpart AA, therefore the 

amendments are being finalized as 

proposed. 

P. Subpart NN—Suppliers of Natural 

Gas and Natural Gas Liquids 

1. Summary of Final Amendments and 

Major Changes Since Proposal 

Threshold for natural gas local 

distribution companies. We are 

amending 40 CFR Table A–5 of subpart 

A of 40 CFR part 98 to establish an 

applicability threshold so that only local 

distribution companies (LDCs) that 

deliver 460,000 thousand standard 

cubic feet (mscf) or more of natural gas 

per year are subject to the reporting rule. 

No major changes have been made since 

proposal. 

2. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. 

Several comments were received on this 

subpart. Responses to additional 

significant comments received can be 

found in the document, ‘‘Response to 

Comments: Revision to Certain 

Provisions of the Mandatory Reporting 

of Greenhouse Gases Rule’’ (see EPA– 

HQ–OAR–2008–0508). 

Comment: Two commenters requested 

that EPA apply the 460,000 thousand 

standard cubic feet (mscf) applicability 

threshold throughout 40 CFR part 98 

wherever a threshold is expressed in 

mtCO2e. Specifically, they contended 

that 40 CFR 98.2(i)(1) and (2) should be 

changed to allow LDCs to stop reporting 

if they deliver less than 460 million 

cubic feet (mmcf) for 5 consecutive 

years or less than 276 mmcf for 3 

consecutive years (25,000 mtCO2e is 

approximately equivalent to the CO2

emissions from the combustion of 460 

mmcf of natural gas and 15,000 mtCO2e 

is approximately equivalent to 276 

mmcf of natural gas). The commenters 

urged EPA to clarify that the threshold 

for natural gas distributors (460,000 

mscf) is equivalent to the threshold of 

25,000 mtCO2e wherever that metric ton 

threshold appears in the rule. 

Response: EPA has finalized an 

applicability threshold for LDCs of 

460,000 mscf or more of natural gas 

delivered per year. As noted by the 

commenters, we decided that it would 

be easier for LDCs to determine whether 

or not they were above a reporting 

threshold expressed in mscf than if that 

threshold were expressed in metric tons 

of carbon dioxide equivalent for the first 

year of this reporting program. 

However, we have not changed the 

conditions for ceasing reporting. In the 

2009 final rule, 40 CFR 98.2(i) states, 

‘‘Except as provided in this paragraph, 

once a facility or supplier is subject to 

the requirements of this part, the owner 

or operator must continue for each year 

thereafter to comply with all 

requirements of this part, including the 

requirement to submit annual GHG 

reports, even if the facility or supplier 

does not meet the applicability 

requirements in paragraph (a) of this 

section in a future year.’’ As noted by 

the commenter, facilities and suppliers 

can cease reporting when reported 

emissions are below 25,000 mtCO2e for 

five consecutive years or below 15,000 

mtCO2e for three consecutive years, as 

specified in 40 CFR 98.2(i)(1) and (i)(2), 

respectively. It is clear in the final rule 

that other than these two exceptions, a 

facility or supplier must continue to 

report even if the facility or supplier no 

longer meets the threshold for reporting 

EPA has concluded that applying a 

consistent threshold, expressed in 

mtCO2e, in 98.2(i)(1) and 98.2(i)(2) for 

all reporters levels the playing field for 

all reporters and is most logical. EPA 

does not intend to provide equivalent 

thresholds under 40 CFR 98.2(i) for 

various categories because it becomes 

too cumbersome. LDCs are required to 

report, under 40 CFR 98.406(b)(8), the 

total annual CO2 mass emissions that 

would result from complete combustion 

of the natural gas delivered to end-users. 

By performing this required calculation, 

LDCs have the necessary data to 

determine whether they may cease 

reporting. 


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6 In Part 98, EPA required the monitoring of all 

streams being destroyed because it was our 

understanding, based on conversations with 

fluorinated GHG producers, that the mass flow of 

destroyed fluorinated GHG streams was routinely 

monitored. To arrive at the quantities being 

removed from the supply, EPA required facilities to 

estimate the share of the total quantity of 

fluorinated GHGs destroyed that consisted of 

fluorinated GHGs that were not included in the 

calculation of the mass produced. This share could 

then be subtracted from the total to arrive at the 

amounts destroyed that were removed from the 

supply. In other words, monitoring and reporting of 

the destruction of fluorinated GHGs that were not 

included in the mass produced was required in 

order to estimate the destruction of fluorinated 

GHGs that had been produced. 

7These 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. 

Q. Subpart OO—Suppliers of Industrial 

Greenhouse Gases 

1. Summary of Final Amendments and 

Major Changes Since Proposal 

We are making several changes to 

subpart OO to respond to concerns 

raised by producers of fluorinated GHGs 

regarding the scope of the monitoring 

and reporting requirements, and clarify 

the scope and due dates for certain 

reporting and recordkeeping 

requirements. 

Producers of fluorinated GHGs 

requested that EPA clarify that subpart 

OO does not apply to fluorinated GHGs 

that are either emitted or destroyed at 

the facility before the fluorinated GHG 

product is packaged for sale or for 

shipment to another facility for 

destruction; are produced and 

transformed at the same facility; or 

occur as low-concentration constituents 

(e.g., impurities) in fluorinated GHG 

products. The producers also requested 

that EPA amend the rule to account for 

the fact that some fluorinated GHGs do 

not have global warming potential 

values (GWPs) listed in Table A–1 of 

subpart A. For fluorinated GHGs 

without GWPs in Table A–1, facilities 

cannot calculate CO2-equivalent 

production as required by subpart A, 

and importers and exporters cannot take 

advantage of the reporting exemptions 

for small shipments under 40 CFR 

98.416(c) and (d), which are expressed 

in CO2-equivalents. 

In response to the concern regarding 

fluorinated GHGs that are emitted or 

destroyed before the product is 

packaged for sale, we are amending the 

definition of ‘‘produce a fluorinated 

GHG’’ at 40 CFR 98.410(b) to explicitly 

exclude the ‘‘creation of fluorinated 

GHGs that are released or destroyed at 

the production facility before the 

production measurement at § 98.414(a).’’ 

We are also removing the requirements 

at 40 CFR 98.414(j) and 98.416(a)(4) to 

monitor and report the destruction of 

fluorinated GHGs ‘‘that are not included 

in the calculation of the mass produced 

in § 98.413(a) because they are removed 

from the production process as byproducts or wastes.’’ Finally, we are 

modifying the requirements at 40 CFR 

98.414(h), 98.416(a)(3), and 

98.416(a)(11) to limit them to the mass 

of each fluorinated GHG that is fed into 

the destruction device (or ‘‘destroyed’’ in 

the case of 40 CFR 98.416(a)(3)) and that 

was previously produced as defined at 

40 CFR 98.410(b). 

These amendments will clarify that 

the scope of subpart OO is that which 

EPA has always intended, and they will 

modify the destruction monitoring and 

reporting requirements to be fully 

consistent with that scope. As noted in 

the preamble to the final Part 98 (74 FR 

56259), and in the response to 

comments document, the intent of 

subpart OO is to track the quantities of 

fluorinated GHGs entering and leaving 

the U.S. supply of fluorinated GHGs. 

Specifically, subpart OO is intended to 

address production of fluorinated GHGs, 

not emissions or destruction of 

fluorinated GHGs that occur during the 

production process. 

As noted in the proposed Part 98 (74 

FR 16580), the production measurement 

at 40 CFR 98.414(a) could occur 

wherever it traditionally occurs, e.g., at 

the inlet to the day tank or at the 

shipping dock, as long as the subpart 

OO monitoring requirements were met 

(e.g., one-percent precision and 

accuracy for the mass produced and for 

container heels, if applicable). 

Emissions upstream of the production 

measurement will be subject to the 

recently promulgated subpart L, which 

was signed by EPA Administrator Lisa 

Jackson on November 8, 2010 and are 

not part of the subpart OO source 

category. 

We are also amending 40 CFR 

98.416(a)(3) and (a)(11) to limit the 

monitoring and reporting of destroyed 

fluorinated GHGs to those destroyed 

fluorinated GHGs that were previously 

‘‘produced’’ under today’s revised 

definition.6 Such fluorinated GHGs 

include but are not limited to quantities 

that are shipped to the facility by 

another facility for destruction, and 

quantities that are returned to the 

facility for reclamation but are found to 

be irretrievably contaminated. While 

monitoring of some destroyed streams 

appears to pose significant technical 

challenges,7 monitoring of quantities of 

fluorinated GHGs that were previously 

produced does not. These quantities can 

be weighed and analyzed by the facility 

upon receipt or upon the facility’s 

conclusion that they cannot be brought 

back to the specifications for new or 

reusable product. 

In response to the concern regarding 

fluorinated GHGs that are produced and 

transformed at the same facility, we are 

amending the definition of ‘‘produce a 

fluorinated GHG’’ to exclude ‘‘the 

creation of intermediates that are 

created and transformed in a single 

process with no storage of the 

intermediates.’’ We are also amending 

the definition of ‘‘produce a fluorinated 

GHG’’ in 40 CFR 98.410(b) to explicitly 

include ‘‘the manufacture of a 

fluorinated GHG as an isolated 

intermediate for use in a process that 

will result in its transformation either at 

or outside of the production facility.’’ 

We are also adding a definition of 

‘‘isolated intermediate’’ to 40 CFR 

98.418. Finally, we are adding 

provisions to 40 CFR 98.414, 98.416, 

and 98.417 to clarify that isolated 

intermediates that are produced and 

transformed at the same facility are 

exempt from subpart OO monitoring, 

reporting, and recordkeeping 

requirements respectively. 

As noted by the producers, 

fluorinated GHGs that are produced and 

transformed at the same facility never 

enter the U.S. supply of industrial 

greenhouse gases; thus, they do not 

need to be reported under subpart OO. 

This is true both of isolated 

intermediates and of intermediates that 

are created and transformed in a single 

process with no storage of the 

intermediate. However, while we are 

excluding the latter from the definition 

of ‘‘produce a fluorinated GHG,’’ we are 

including the former in that definition. 

This is because the manufacture of 

isolated intermediates, which can lead 

to emissions of those intermediates, will 

be of interest under the recently 

promulgated subpart L and it is 

desirable to use the same definition of 

‘‘produce a fluorinated GHG’’ for subpart 

L as for subpart OO for consistency and 

clarity. Thus, instead of excluding the 

manufacture of isolated intermediates 

that are transformed at the same facility 

from the definition of ‘‘produce a 

fluorinated GHG,’’ we are adding 

provisions to exclude it from the 

subpart OO monitoring, reporting, and 

recordkeeping requirements. We are 

also adding a definition of ‘‘isolated 


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intermediate’’ that is the same as that for 

the recently promulgated subpart L. 

In response to the concern regarding 

fluorinated GHGs that occur as lowconcentration constituents of 

fluorinated GHG products, we are 

defining and excluding lowconcentration constituents from the 

monitoring, reporting, and 

recordkeeping requirements for 

fluorinated GHG production, exports, 

and imports. For purposes of production 

and export, we are defining a lowconcentration constituent in 40 CFR 

98.418 as a fluorinated GHG constituent 

of a fluorinated GHG product that 

occurs in the product in concentrations 

below 0.1 percent by mass. This 

concentration is the same as that used 

in the definition of ‘‘trace concentration’’ 

used elsewhere in subpart OO. It is also 

consistent with industry purity 

standards for HFC refrigerants (AirConditioning, Heating, and Refrigeration 

Institute (AHRI) 700), for SF6 used as an 

insulator in electrical equipment 

(International Electrotechnical 

Commission (IEC) 60376), and for 

perfluorocarbons and other fluorinated 

GHGs used in electronics manufacturing 

(Semiconductor Equipment and 

Materials International (SEMI) C3 

series). To meet these standards, which 

set limits that range from less than 0.1 

percent to 0.5 percent for all fluorinated 

GHG impurities combined, fluorinated 

GHG producers are likely to have 

identified and quantified the 

concentrations of impurities at 

concentrations at or above 0.1 percent 

for the products subject to the 

standards. Finally, below concentrations 

of 0.1 percent, fluorinated GHG 

impurities are not likely to have a 

significant impact on the GWP of the 

product. For example, if a lowconcentration constituent occurs in 

concentrations of just less than 0.1 

percent and has a GWP that is ten times 

as large as the GWP of the main 

constituent of the product, it will 

increase the weighted GWP of the 

product by just less than one percent. 

To ensure that fluorinated GHG 

production facilities rely on data of 

known and acceptable quality when 

determining whether or not to report a 

minor fluorinated GHG constituent of a 

product, we are adding product 

sampling and analytical requirements at 

40 CFR 98.414(n), corresponding 

calibration requirements at 40 CFR 

98.414(o), and a corresponding 

reporting requirement at 40 CFR 

98.416(f). We are also clarifying in 40 

CFR 98.414(a) how to calculate 

production of each fluorinated GHG 

constituent of a product. 

For purposes of fluorinated GHG 

imports, we are defining a ‘‘lowconcentration constituent’’ in 40 CFR 

98.418 as a fluorinated GHG constituent 

of a fluorinated GHG product that 

occurs in the product in concentrations 

below 0.5 percent by mass. We are 

defining a higher concentration for 

fluorinated GHG imports than for 

fluorinated GHG production and exports 

because importers are less likely than 

producers to have detailed information 

on the identities and concentrations of 

minor fluorinated GHG constituents in 

their products. 

In response to the concerns regarding 

fluorinated GHGs that do not have 

GWPs listed in Table A–1, we are 

amending subpart A to exempt such 

compounds from the general subpart A 

requirement to report supply flows in 

terms of CO2 equivalents and revising 

the reporting exemptions for import and 

export of small shipments to be in terms 

of kilograms of fluorinated GHGs or 

N2O, rather than tons of CO2- 

equivalents. The amendment to subpart 

A is discussed in more detail in Section 

II.F of this preamble. The exemptions 

for import and export will be applied to 

shipments of less than 25 kilograms of 

fluorinated GHGs or N2O rather than to 

shipments of less than 250 metric tons 

of CO2e. This will enable small 

shipments of fluorinated GHGs to be 

exempt from reporting regardless of 

whether or not the fluorinated GHG has 

a GWP listed in Table A–1. 

Other corrections. We are also 

amending the reporting and 

recordkeeping provisions in subpart OO 

to clarify those requirements and to 

correct internal inconsistencies in the 

subpart. 

We are amending the reporting 

requirements in 40 CFR 98.416(a)(15) 

and (c)(10) to remove N2O from the list 

of GHGs that must be reported when 

they are transferred off site for 

destruction, because N2O transferred off 

site for destruction is not required to be 

monitored. 

We are amending 40 CFR 98.416(b) 

and (e) to clarify the due dates of the 

one-time reports required by those 

paragraphs. The due date for the onetime reports is March 31, 2011, or 

within 60 days of commencing 

fluorinated GHG destruction or 

production (as applicable). The due date 

in 40 CFR 98.416(e) in subpart OO was 

originally April 1, 2011, and there was 

no provision for fluorinated GHG 

destruction or production commenced 

after that date. 

We are amending the recordkeeping 

requirements in 40 CFR 98.417(a)(2) to 

correct and update an internal reference. 

The correct reference is to ‘‘§ 98.414(m) 

and (o),’’ instead of ‘‘§ 98.417(j) and (k).’’ 

We are amending 40 CFR 98.417(b) to 

remove the reference to the ‘‘annual 

destruction device outlet reports’’ in 40 

CFR 98.416(e) since no such reporting 

requirement exists. 

Finally, we are amending 40 CFR 

98.417(d)(2) to correct a typographical 

error; that paragraph should refer to ‘‘the 

invoice for the export,’’ rather than for 

the ‘‘import.’’ 

EPA is making one clarifying editorial 

change in the final rule amendments 

that was not in the proposed 

amendments. As discussed above and in 

the preamble to the proposed 

amendments, 40 CFR 98.414(h) requires 

facilities to measure the mass of each 

fluorinated GHG that is fed into the 

destruction device and that was 

previously produced. If the mass being 

fed into the destruction device includes 

more than trace concentrations of 

materials other than the fluorinated 

GHG being destroyed, facilities must 

estimate the concentrations of the 

fluorinated GHGs being destroyed. They 

must then multiply these concentrations 

by the mass measurement to obtain the 

mass of the fluorinated GHGs fed into 

the destruction device. In the proposed 

paragraph (h), the final sentence read, 

‘‘You must multiply this concentration 

(mass fraction) by the mass 

measurement to obtain the mass of the 

fluorinated GHG destroyed.’’ To be 

consistent with the beginning of the 

paragraph and to be mathematically 

correct, this sentence has been corrected 

in the final rule to read, ‘‘You must 

multiply this concentration (mass 

fraction) by the mass measurement to 

obtain the mass of the fluorinated GHG 

fed into the destruction device.’’ As 

specified in Equation OO–4 of 40 CFR 

98.413(d), the mass of the fluorinated 

GHG destroyed is obtained by 

multiplying the mass of the fluorinated 

GHG fed into the destruction device by 

the destruction efficiency of the 

destruction device. 

2. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. 

Several comments were received on this 

subpart. Responses to additional 

significant comments received can be 

found in the document, ‘‘Response to 

Comments: Revision to Certain 

Provisions of the Mandatory Reporting 

of Greenhouse Gases Rule’’ (see EPA– 

HQ–OAR–2008–0508). 

Comment: Two commenters 

expressed concerns that exempting lowconcentration constituents of products 

from monitoring and reporting would 

exempt a significant amount of 


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79130 Federal Register / Vol. 75, No. 242 / Friday, December 17, 2010 / Rules and Regulations 

emissions from reporting. These 

commenters requested additional 

information on the GWPs of these lowconcentration constituents and on the 

emissions affected by the exemption. 

Response: We analyzed the potential 

impact of low-concentration 

constituents on the total calculated 

flows of fluorinated GHGs into the U.S. 

economy, considering both the possible 

masses of the low-concentration 

constituents and their CO2-equivalents. 

We concluded that at a level of 0.1 

percent of production and 0.5 percent of 

imports, identification of such 

constituents would have a negligible 

impact on the total calculated flows of 

fluorinated GHGs into the U.S. supply. 

It is important to note that, under the 

exemption for low-concentration 

constituents, the masses and CO2e of 

low-concentration constituents are not 

equated to zero. Instead, the mass of the 

low-concentration constituent is 

assigned to the main constituent of the 

product, and the GWP is assumed to be 

that of the main constituent of the 

product. Only if the GWP or 

atmospheric lifetime of the lowconcentration constituent is 

significantly higher than that of the 

main constituent is there a potential 

concern associated with these 

assumptions. 

As noted in the preamble to the 

proposed rule, low-concentration 

constituents are generally by-products 

of the reaction used to produce the 

fluorinated GHG product. Although we 

do not have information on every 

product and by-product combination, 

we believe, based on the examples of 

which we are aware, that by-products 

rarely have GWPs that are more than ten 

times as large as that of the product. We 

analyzed the potential impact of a byproduct that had ten times the GWP of 

the product on the weighted GWP of the 

combination of the two. At a 

concentration of 0.1 percent, the byproduct would raise the weighted GWP 

(and CO2e) above that of the product by 

just under one percent. Given that the 

impacts of most low-concentration 

constituents are likely to fall below this 

level, we do not consider them 

significant. 

We also performed an analysis in 

which we conservatively assumed that 

every HFC, PFC, and SF6 product had a 

PFC by-product that was shipped along 

with it at a concentration of 0.1 percent. 

This was intended to address the 

possibility that low-concentration 

constituents had very long atmospheric 

lifetimes. Based on this worst-case 

assumption, the quantity of PFCs 

flowing into the U.S. fluorinated GHG 

supply was increased by less than 10 

percent. It is extremely unlikely that 

every HFC, PFC, and SF6 product has a 

PFC by-product; in fact, the highestvolume products, the HFCs, are unlikely 

to have PFC by-products. Therefore, in 

consideration of this analysis and the 

GWP analysis, we have concluded that 

the exemption for low-concentration 

constituents is very unlikely to lead to 

significant errors in our understanding 

of potential emissions of fluorinated 

GHGs from the U.S. supply. 

Comment: Two commenters 

expressed concerns regarding the 

proposal to exclude from subpart OO 

fluorinated GHGs that are emitted or 

destroyed before the fluorinated product 

is packaged for sale. They requested that 

EPA ensure that these emissions were 

fully captured under the reporting rule 

(e.g., subpart L) and requested that EPA 

document the magnitude of these 

emissions and the identities and GWPs 

of the compounds emitted. 

Response: As proposed, we are 

excluding from the definition of 

‘‘produce a fluorinated GHG’’ the 

creation of fluorinated GHGs that are 

released or destroyed at the production 

facility before the production 

measurement. As discussed in the 

preamble to the proposed amendments, 

such fluorinated GHGs never enter the 

U.S. supply of fluorinated GHGs, and 

the goal of subpart OO is to monitor 

fluorinated GHG flows into and out of 

this supply. However, the recently 

promulgated subpart L requires 

monitoring and reporting of emissions 

that occur before the production 

measurement. We have worked to 

ensure that no fluorinated GHG 

emissions from fluorinated GHG 

production are ‘‘missed’’ under the 

combined oversight of these two 

subparts. The magnitudes, identities, 

and GWPs of the emissions that will be 

reported under subpart L of 40 CFR part 

98 are discussed in the preamble to the 

proposed rule including subpart L (75 

FR 18652, April 12, 2010) and in the 

Technical Support Document for 

subpart L. 

R. Subpart PP—Suppliers of Carbon 

Dioxide 

1. Summary of Final Amendments and 

Major Changes Since Proposal 

We are removing the words ‘‘each’’ 

from 40 CFR 98.422(a) and (b). This 

change will align this section with the 

requirements of the rest of subpart PP, 

which allow for monitoring of an 

aggregated flow of CO2, versus 

monitoring at each production well or 

process unit, if the monitoring is done 

at a gathering point downstream of 

individual production wells or 

production process units. 

We are allowing suppliers to calculate 

the annual mass of CO2 supplied in 

containers by using weigh bills, scales, 

load cells, or loaded container volume 

readings as an alternative to flow 

meters. We are making multiple 

amendments to the regulatory text to 

accommodate this provision. First, we 

are redesignating 40 CFR 98.423(b) as 40 

CFR 98.423(c) and adding a new 40 CFR 

98.423(b) with calculation procedures 

for CO2 supplied in containers. Second, 

we are amending the first sentence of 40 

CFR 98.423(a) to allow use of the 

alternative procedures in 40 CFR 

98.423(b). Third, we are adding new 

QA/QC procedures for suppliers of CO2

in containers to 40 CFR 98.424(a)(2). 

Fourth, we are adding missing data 

procedures for suppliers of CO2 in 

containers to 40 CFR 98.425(d) and 

specifying that the missing data 

procedures in 40 CFR 98.425(a) are for 

suppliers using flow meters. Finally, we 

are making multiple amendments to 

regulatory text in 40 CFR 98.426 so that 

all data collected with weigh bills, 

scales, load cells, or loaded container 

volume readings must be reported just 

as for all data collected with flow 

meters. 

We are removing the requirement that 

CO2 measurement must be made prior to 

subsequent purification, processing, or 

compression at 40 CFR 98.423(a)(1), 

(a)(2), and (b) (which we are 

redesignating as 40 CFR 98.423(c)). 

Because the purpose of subpart PP is to 

collect accurate data on CO2 supplied to 

the economy, we have concluded that 

measurements made after purification, 

compression, or processing will 

continue to meet the level of data 

quality and accuracy needed with 

respect to subpart PP, while minimizing 

the burden on industry and providing 

greater flexibility in measuring CO2

streams. 

To ensure that all reporters account 

for the appropriate quantity of CO2 in 

situations where a CO2 stream is 

segregated such that only a portion is 

captured for commercial application or 

for injection and where a flow meter is 

used, we are making a number of 

amendments. First, we are adding 

language at 40 CFR 98.424(a) regarding 

flow meter location. Reporters who have 

a flow meter(s) on the main, captured 

CO2 stream(s) only must locate the flow 

meter(s) after the point(s) of segregation. 

Reporters who have a flow meter(s) on 

the main, captured CO2 stream and a 

subsequent flow meter(s) on the CO2

stream(s) diverted for on-site use and 

who choose to use the subsequent flow 

meter(s) to calculate CO2 supply (i.e. the 


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two meter method) must locate the main 

flow meter(s) prior to the point(s) of 

segregation and the subsequent flow 

meter(s) on the CO2 stream(s) for on-site 

use after the point(s) of segregation. We 

are also amending existing language in 

40 CFR 98.424(a) to reference this new 

requirement. Second, we are amending 

40 CFR 98.423(a)(3) to provide reporters 

using the two meter approach a new 

equation (Equation PP–3b) to calculate 

total CO2 supplied. As a harmonizing 

change, we are redesignating Equation 

PP–3 as Equation PP–3a. Third, we are 

amending 40 CFR 98.426(c) so that 

reporters using the new Equation PP–3b 

are required to report the equation 

inputs and output and the location of 

flow meters with respect to the point of 

segregation. 

Because the amendments will allow 

flow meters to be located after 

purification, compression, or 

processing, we are adding data reporting 

requirements in 40 CFR 98.426 to 

collect additional information on flow 

meter location. Specifically, we are 

adding that facilities will report 

information on the placement of each 

flow meter used in relation to the points 

of CO2 stream capture, dehydration, 

compression, and other processing. 

Knowing where in the production 

process the flow meter is located will 

enable EPA to effectively compare data 

across reporters and learn about the 

efficacy of various CO2 stream capture 

processes. 

We are specifying standard conditions 

under subpart PP as a temperature and 

an absolute pressure of 60 °F and 1 

atmosphere. It is our understanding that 

60° F and 1 atmosphere (which is 

equivalent to 14.7 psia) are more 

commonly used by the industries 

covered by subpart PP. 

We are making several amendments to 

allow the reporter to determine the mass 

of a CO2 stream by converting the 

volumetric flow of the CO2 stream from 

operating conditions to standard 

conditions and then applying the 

density value for CO2 at standard 

conditions and the measured 

concentration of CO2 in the flow as a 

volume percent. First, we are specifying 

that, at the revised standard conditions, 

the density of CO2 is 0.001868 metric 

tons per standard cubic meter. This is 

slightly different than the density value 

proposed (0.018704) as the result of 

additional research we have conducted. 

We are specifying that a reporter who 

applies the density value for CO2 at 

standard conditions must use this 

specified value. 

Second, we are revising the 

definitions of two of the input variables 

to Equation PP–2 in paragraph (a)(2). 

Since it was finalized (74 FR 56260, 

October 30, 2009), Equation PP–2 allows 

a reporter to calculate annual mass of 

CO2 with an input for CO2 concentration 

in weight percent and an input for 

density of the CO2 stream. So that 

reporters can avail themselves of the 

density value for CO2 being finalized in 

this action, however, Equation PP–2 can 

now also be used to calculate annual 

mass of CO2 with an input for CO2

concentration in volume percent and an 

input for density of CO2. We note that 

when we proposed this action, we did 

not propose to revise the definitions of 

the input variables because we 

erroneously overlooked the mismatch 

between the density value we were 

providing (CO2) and the density value 

required by Equation PP–2 (the CO2

stream). In order to provide all reporters 

with lower burden calculation 

procedures, as intended by proposing a 

density value for CO2, we are correcting 

this omission and harmonizing Equation 

PP–2 with the finalized density value. 

We note that the revision to the two 

input variables is being applied for both 

reporters using flow meters and 

reporters using containers. 

Third, we are amending 40 CFR 

98.426(b)(3) and (b)(4) to require that for 

volumetric flow meters, the reporter 

must report quarterly concentration 

either in volume or weight percent and 

a density value for either CO2 or the CO2

stream, depending on which of the two 

equation input descriptions provided 

the reporter uses. 

Fourth, we are amending language in 

40 CFR 98.424(a)(5), (a)(5)(i) and 

(a)(5)(ii) to allow reporters to choose 

either a method published by a 

consensus-based standards organization 

or an industry standard practice to 

determine the density of the CO2 stream. 

We are also replacing the word 

‘‘measure’’ with the word ‘‘determine.’’ 

Previously, subpart PP required a 

reporter to use an appropriate method 

published by a consensus-based 

standards organization to measure 

density for CO2 at standard conditions, 

if such a method existed. Only where no 

such method existed could an industry 

standard practice be used. However, we 

have been unable to identify any 

method published by a consensus-based 

standards organization for measuring 

the density of the CO2 stream. 

Therefore, we are providing reporters 

with more flexibility on this 

requirement so that they can use an 

industry standard practice to calculate 

the density of the CO2 stream rather 

than directly measure density with an 

instrument, if preferred. 

Finally, we are amending the 

reference to the U.S. Food and Drug 

Administration food-grade 

specifications for CO2 in 40 CFR 

98.424(b)(2) to correct a typographical 

error. The correct reference is 21 CFR 

184.1240, not 21 CFR 184.1250. 

Major changes since proposal are 

identified in the following list. The 

rationale for these and any other 

significant changes can be found in this 

preamble or the document, ‘‘Response to 

Comments: Revision to Certain 

Provisions of the Mandatory Reporting 

of Greenhouse Gases Rule’’ (see EPA– 

HQ–OAR–2008–0508). 

• We are adding a second aggregation 

equation (Equation PP–3b) with 

appropriate flow meter location 

requirements so that a reporter can 

select either the one-meter or two-meter 

approach for calculating total annual 

mass of CO2. 

• We are revising the definitions of 

two of the input variables to Equation 

PP–2 in paragraphs 40 CFR 98.423(a)(2) 

and (b)(2) so that the equation can be 

used to calculate annual mass of CO2

with an input for CO2 concentration in 

either volume percent and an input for 

density of CO2, or weight percent CO2

and the density of the whole stream. 

2. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. 

Several comments were received on this 

subpart. Responses to additional 

significant comments received can be 

found in the document, ‘‘Response to 

Comments: Revision to Certain 

Provisions of the Mandatory Reporting 

of Greenhouse Gases Rule’’ (see EPA– 

HQ–OAR–2008–0508). 

Comment: One commenter asserted 

that one of their facilities has already 

installed a CO2 meter prior to 

purification, processing, or 

compression—as was required by 40 

CFR 98.424 when Part 98 was finalized 

(74 FR 56260, October 30, 2009)—and 

because this facility has segregation, this 

results in a flow meter location prior to 

segregation. The commenter suggested 

that this facility and others like it 

should be allowed to keep their flow 

meters in place rather than be required 

to move them to a location after 

segregation, as was proposed in the 

amendments of August 11, 2010. The 

commenter suggested a two-meter 

approach, whereby a facility locates a 

main flow meter prior to segregation on 

the main, captured CO2 stream and a 

subsequent flow meter after segregation 

on the diverted CO2 stream and then 

calculates the CO2 for off-site 

commercial use as the difference 

between the two. The commenter stated 

that this two-meter approach should be 


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equally acceptable to the approach 

proposed. 

Response: EPA agrees that a reporter 

can calculate CO2 supplied for 

commercial transaction or injection 

with sufficient accuracy with the twometer approach suggested by the 

commenter, as long as the CO2 stream 

diverted for on site use is the only CO2

stream diversion after the location of the 

main flow meter. If any of the main CO2

stream remaining after on-site diversion 

is further diverted (to a vent for 

emission, for example) then the 

difference between the captured CO2

stream and the CO2 stream diverted for 

on-site use will not be an accurate 

reflection of the CO2 supplied for 

commercial transaction or injection. 

Therefore, EPA is finalizing two 

approaches for calculating CO2

supplied, including aggregation 

equations with flow meter location 

requirements, so that a reporter can 

select either the one-meter or two-meter 

approach. However, we are specifying 

in the monitoring and QA/QC 

requirements (40 CFR 98.424) that a 

reporter may only follow the two-meter 

approach if the CO2 stream(s) for on-site 

use is/are the only diversion(s) from the 

main, captured CO2 stream after the 

main flow meter(s) location. 

III. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review 

This action is not a ‘‘significant 

regulatory action’’ under the terms of 

Executive Order 12866 (58 FR 51735, 

October 4, 1993) and is therefore not 

subject to review under the executive 

order. 

B. Paperwork Reduction Act 

This action does not impose any new 

information collection burden. These 

amendments do not make substantive 

changes to the reporting requirements in 

any of the amended subparts. In many 

cases, the amendments to the reporting 

requirements reduce the reporting 

burden by making the reporting 

requirements conform more closely to 

current industry practices. While the 

final rule results in a net decrease in 

collection burden, there is a new 

reporting requirement for facilities with 

part 75 units. Previously, facilities with 

these units had the option of reporting 

biogenic CO2 emissions separately. This 

final rule requires separate reporting of 

biogenic CO2 emissions beginning in 

2011; however facilities may use 

simplified methods based on available 

information. The Office of Management 

and Budget (OMB) has previously 

approved the information collection 

requirements contained in the 

regulations promulgated on October 30, 

2009, under 40 CFR part 98 under the 

provisions of the Paperwork Reduction 

Act, 44 U.S.C. 3501 et seq. and has 

assigned OMB control number 2060– 

0629. Burden is defined at 5 CFR 

1320.3(b). An agency may not conduct 

or sponsor, and a person is not required 

to respond to, a collection of 

information unless it displays a 

currently valid OMB control number. 

The OMB control numbers for EPA’s 

regulations in 40 CFR are listed in 40 

CFR part 9. 

Further information on EPA’s 

assessment on the impact on burden can 

be found in the Revisions Cost Memo 

(EPA–HQ–OAR–2008–0508). 

C. Regulatory Flexibility Act (RFA) 

The RFA generally requires an agency 

to prepare a regulatory flexibility 

analysis of any rule subject to notice 

and comment rulemaking requirements 

under the Administrative Procedure Act 

or any other statute unless the agency 

certifies that the rule will not have a 

significant economic impact on a 

substantial number of small entities. 

Small entities include small businesses, 

small organizations, and small 

governmental jurisdictions. 

For purposes of assessing the impacts 

of these amendments on small entities, 

small entity is defined as: (1) A small 

business as defined by the Small 

Business Administration’s regulations at 

13 CFR 121.201; (2) a small 

governmental jurisdiction that is a 

government of a city, county, town, 

school district or special district with a 

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

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

owned and operated and is not 

dominant in its field. 

After considering the economic 

impacts of these rule amendments on 

small entities, I certify that this action 

will not have a significant economic 

impact on a substantial number of small 

entities. 

The rule amendments will not impose 

any new significant requirements on 

small entities that are not currently 

required by the rules promulgated on 

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

reporting annual GHG emissions). 

Broadly, in developing the 2009 final 

rule EPA took several steps to reduce 

the impact on small entities. For 

example, EPA determined appropriate 

thresholds that reduced the number of 

small businesses reporting. In addition, 

EPA did not require facilities to install 

CEMS if they did not already have them. 

Facilities without CEMS can calculate 

emissions using readily available data or 

data that are less expensive to collect 

such as process data or material 

consumption data. For some source 

categories, EPA developed tiered 

methods that are simpler and less 

burdensome. Also, EPA required annual 

instead of more frequent reporting. 

Finally, EPA continues to conduct 

significant outreach on the mandatory 

GHG reporting rule and maintains an 

‘‘open door’’ policy for stakeholders to 

help inform EPA’s understanding of key 

issues for the industries. 

D. Unfunded Mandates Reform Act 

(UMRA) 

This action contains no Federal 

mandates under the provisions of Title 

II of the Unfunded Mandates Reform 

Act of 1995 (UMRA), 2 U.S.C. 1531– 

1538 for State, local, or tribal 

governments or the private sector. The 

action imposes no enforceable duty on 

any State, local or tribal governments or 

the private sector. In addition, EPA 

determined that the rule amendments 

contain no regulatory requirements that 

might significantly or uniquely affect 

small governments because the 

amendments will not impose any new 

requirements that are not currently 

required by the rule promulgated on 

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

reporting annual GHG emissions), and 

the rule amendments will not unfairly 

apply to small governments. Therefore, 

this action is not subject to the 

requirements of section 203 of the 

UMRA. 

E. Executive Order 13132: Federalism 

This action does not have federalism 

implications. It will not have substantial 

direct effects on the States, on the 

relationship between the national 

government and the States, or on the 

distribution of power and 

responsibilities among the various 

levels of government, as specified in 

Executive Order 13132. However, for a 

more detailed discussion about how 

these rule amendments will relate to 

existing State programs, please see 

Section II of the preamble for the 

proposed GHG reporting rule (74 FR 

16457 to 16461, April 10, 2009). 

These amendments apply directly to 

facilities that supply fuel that when 

used emit greenhouse gases or facilities 

that directly emit greenhouses gases. 

They do not apply to governmental 

entities unless the government entity 

owns a facility that directly emits 

greenhouse gases above threshold levels 

(such as a landfill or stationary 

combustion source), so relatively few 

government facilities will be affected. 

This regulation also does not limit the 


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Federal Register / Vol. 75, No. 242 / Friday, December 17, 2010 / Rules and Regulations 79133 

power of States or localities to collect 

GHG data and/or regulate GHG 

emissions. Thus, Executive Order 13132 

does not apply to this action. 

Although section 6 of Executive Order 

13132 does not apply to this action, EPA 

did consult with State and local officials 

or representatives of State and local 

governments in developing the 2009 

final rule. A summary of EPA’s 

consultations with State and local 

governments is provided in Section 

VIII.E of the preamble to the 2009 final 

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

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

This action does not have tribal 

implications, as specified in Executive 

Order 13175 (65 FR 67249, November 9, 

2000). The rule amendments will not 

result in any changes to the 

requirements of Part 98. Thus, Executive 

Order 13175 does not apply to this 

action. 

Although Executive Order 13175 does 

not apply to this action, EPA sought 

opportunities to provide information to 

Tribal governments and representatives 

during the development of the rules 

promulgated on October 30, 2009. A 

summary of the EPA’s consultations 

with Tribal officials is provided 

Sections VIII.E and VIII.F of the 

preamble to the final GHG Reporting 

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

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

EPA interprets Executive Order 13045 

(62 FR 19885, April 23, 1997) as 

applying only to those regulatory 

actions that concern health or safety 

risks, such that the analysis required 

under section 5–501 of the Executive 

Order has the potential to influence the 

regulation. This action is not subject to 

Executive Order 13045 because it does 

not establish an environmental standard 

intended to mitigate health or safety 

risks. 

H. Executive Order 13211: Actions That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This action is not subject to Executive 

Order 13211 (66 FR 28355 (May 22, 

2001)), because it is not a significant 

regulatory action under Executive Order 

12866. 

I. National Technology Transfer and 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (NTTAA), Public Law 104– 

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

use voluntary consensus standards in its 

regulatory activities unless to do so 

would be inconsistent with applicable 

law or otherwise impractical. Voluntary 

consensus standards are technical 

standards (e.g., materials specifications, 

test methods, sampling procedures, and 

business practices) that are developed or 

adopted by voluntary consensus 

standards bodies. NTTAA directs EPA 

to provide Congress, through OMB, 

explanations when the Agency decides 

not to use available and applicable 

voluntary consensus standards. 

This rulemaking involves the use of 

two new voluntary consensus standards 

from ASTM International. Specifically, 

EPA will allow facilities in the 

petroleum refining and petrochemical 

production industries to use ASTM 

D2593–93(2009) Standard Test Method 

for Butadiene Purity and Hydrocarbon 

Impurities by Gas Chromatography, and 

ASTM D7633–10 Standard Test Method 

for Carbon Black—Carbon Content, in 

addition to the methods incorporated by 

reference in Part 98. These additional 

voluntary consensus standards will 

provide alternative method that owners 

or operators in these industries can use 

to monitor GHG emissions. 

This rulemaking also involves the use 

of several standard methods that are in 

EPA publications. These include the 

following: 

• Protocol for Measurement of 

Tetrafluoromethane (CF4) and 

Hexafluoroethane (C2F6) Emissions from 

Primary Aluminum Production (April 

2008); IBR approved for 40 CFR 

98.64(a). 

• AP 42, Section 5.2, Transportation 

and Marketing of Petroleum Liquids, 

July 2008 (AP 42, Section 5.2); http://

www.epa.gov/ttn/chief/ap42/ch05/final/

c05s02.pdf; in Chapter 5, Petroleum 

Industry, of AP 42, Compilation of Air 

Pollutant Emission Factors, 5th Edition, 

Volume I; IBR approved for 40 CFR 

98.253(n). 

• AP 42, Section 7.1, Organic Liquid 

Storage Tanks, November 2006 (AP 42, 

Section 7.1), http://www.epa.gov/ttn/

chief/ap42/ch07/final/c07s01.pdf; in 

Chapter 7, Liquid Storage Tanks, of AP 

42, Compilation of Air Pollutant 

Emission Factors, 5th Edition, Volume 

1; IBR approved for 40 CFR 98.243(m)(1) 

and 40 CFR 98.256(o)(2)(i). 

• Method 8015C, Nonhalogenated 

Organics By Gas Chromatography, 

Revision 3, February 2007 (Method 

8015C), http://www.epa.gov/osw/ 

hazard/testmethods/sw846/pdfs/ 

8015c.pdf; in EPA Publication No. SW– 

846, ‘‘Test Methods for Evaluating Solid 

Waste, Physical/Chemical Methods,’’ 

Third Edition; IBR approved for 40 CFR 

98.244(b)(4)(viii). 

• Method 8021B, Aromatic And 

Halogenated Volatiles By Gas 

Chromatography Using Photoionization 

And/Or Electrolytic Conductivity 

Detectors, Revision 2, December 1996 

(Method 8021B). http://www.epa.gov/ 

osw/hazard/testmethods/sw846/pdfs/ 

8021b.pdf; in EPA Publication No. SW– 

846, ‘‘Test Methods for Evaluating Solid 

Waste, Physical/Chemical Methods,’’ 

Third Edition; IBR approved for 40 CFR 

98.244(b)(4)(viii). 

• Method 8031, Acrylonitrile By Gas 

Chromatography, Revision 0, September 

1994 (Method 8031), http://www.epa.

gov/osw/hazard/testmethods/sw846/

pdfs/8031.pdf; in EPA Publication No. 

SW–846, ‘‘Test Methods for Evaluating 

Solid Waste, Physical/Chemical 

Methods,’’ Third Edition; IBR approved 

for 40 CFR 98.244(b)(4)(viii). 

• Method 9060A, Total Organic 

Carbon, Revision 1, November 2004 

(Method 9060A), http://www.epa.gov/

osw/hazard/testmethods/sw846/pdfs/

9060a.pdf; in EPA Publication No. SW– 

846, ‘‘Test Methods for Evaluating Solid 

Waste, Physical/Chemical Methods,’’ 

Third Edition; IBR approved for 40 CFR 

98.244(b)(4)(viii). 

These methods are being added by the 

final rule amendments as a result of 

working with affected industries to 

identify existing methods that can be 

used to provide the data needed to 

calculate GHG emissions, proposing the 

addition of the methods, and 

considering the public comments on the 

addition of the methods in the final rule 

making. 

No new test methods were developed 

for this action. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order 12898 (59 FR 7629, 

February 16, 1994) establishes federal 

executive policy on environmental 

justice. Its main provision directs 

Federal agencies, to the greatest extent 

practicable and permitted by law, to 

make environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority 

populations and low-income 

populations in the United States. 

EPA has determined that Part 98 does 

not have disproportionately high and 

adverse human health or environmental 

effects on minority or low-income 

populations because it does not affect 

the level of protection provided to 

human health or the environment 

because it is a rule addressing 


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79134 Federal Register / Vol. 75, No. 242 / Friday, December 17, 2010 / Rules and Regulations 

information collection and reporting 

procedures. 

K. Congressional Review Act 

The Congressional Review Act, 5 

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

Business Regulatory Enforcement 

Fairness Act of 1996 (SBREFA), 

generally provides that before a rule 

may take effect, the agency 

promulgating the rule must submit a 

rule report, which includes a copy of 

the rule, to each House of the Congress 

and to the Comptroller General of the 

United States. EPA will submit a report 

containing this rule and other required 

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

House of Representatives, and the 

Comptroller General of the U.S. prior to 

publication of the rule in the Federal 

Register. A major rule cannot take effect 

until 60 days after it is published in the 

Federal Register. This action is not a 

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

804(2). This rule will be effective on 

December 31, 2010. 

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: November 24, 2010. 

Lisa P. Jackson, 

Administrator. 

■ For the reasons stated in the preamble, 

title 40, chapter I, of the Code of Federal 

Regulations is amended as follows: 

PART 98—[AMENDED] 

■ 1. The authority citation for part 98 

continues to read as follows: 

Authority: 42 U.S.C. 7401–7671q. 

Subpart A—[Amended] 

■ 2. Section 98.3 is amended by: 

■ a. Revising paragraphs (c)(1), (c)(4) 

introductory text, (c)(4)(i), (c)(4)(ii), and 

(c)(4)(iii) introductory text. 

■ b. Adding paragraph (c)(4)(vi). 

■ c. Adding a new sentence to the end 

of paragraph (c)(5)(i). 

■ d. Adding paragraph (c)(12). 

■ e. Revising the third sentence of 

paragraph (d)(3) introductory text. 

■ f. Revising the first sentence of 

paragraph (f). 

■ g. Revising paragraphs (g)(4) and 

(g)(5)(iii). 

■ h. Revising paragraph (h). 

■ i. Revising paragraph (i). 

■ j. Adding paragraph (j). 

§ 98.3 What are the general monitoring, 

reporting, recordkeeping and verification 

requirements of this part? 

* * * * * 

(c) * * * 

(1) Facility name or supplier name (as 

appropriate), and physical street address 

of the facility or supplier, including the 

city, State, and zip code. 

* * * * * 

(4) For facilities, except as otherwise 

provided in paragraph (c)(12) of this 

section, report annual emissions of CO2,

CH4, N2O, and each fluorinated GHG (as 

defined in § 98.6) as follows. 

(i) Annual emissions (excluding 

biogenic CO2) aggregated for all GHG 

from all applicable source categories, 

expressed in metric tons of CO2e 

calculated using Equation A–1 of this 

subpart. 

(ii) Annual emissions of biogenic CO2

aggregated for all applicable source 

categories, expressed in metric tons. 

(iii) Annual emissions from each 

applicable source category, expressed in 

metric tons of each applicable GHG 

listed in paragraphs (c)(4)(iii)(A) 

through (c)(4)(iii)(E) of this section. 

* * * * * 

(vi) Applicable source categories 

means stationary fuel combustion 

sources (subpart C of this part), 

miscellaneous use of carbonates 

(subpart U of this part), and all of the 

source categories listed in Table A–3 

and Table A–4 of this subpart present at 

the facility. 

(5) * * * 

(i) * * * For fluorinated GHGs, 

calculate and report CO2e for only those 

fluorinated GHGs listed in Table A–1 of 

this subpart. 

* * * * * 

(12) For the 2010 reporting year only, 

facilities that have ‘‘part 75 units’’ (i.e. 

units that are subject to subpart D of this 

part or units that use the methods in 

part 75 of this chapter to quantify CO2

mass emissions in accordance with 

§ 98.33(a)(5)) must report annual GHG 

emissions either in full accordance with 

paragraphs (c)(4)(i) through (c)(4)(iii) of 

this section or in full accordance with 

paragraphs (c)(12)(i) through (c)(12)(iii) 

of this section. If the latter reporting 

option is chosen, you must report: 

(i) Annual emissions aggregated for all 

GHG from all applicable source 

categories, expressed in metric tons of 

CO2e calculated using Equation A–1 of 

this subpart. You must include biogenic 

CO2 emissions from part 75 units in 

these annual emissions, but exclude 

biogenic CO2 emissions from any nonpart 75 units and other source 

categories. 

(ii) Annual emissions of biogenic CO2,

expressed in metric tons (excluding 

biogenic CO2 emissions from part 75 

units), aggregated for all applicable 

source categories. 

(iii) Annual emissions from each 

applicable source category, expressed in 

metric tons of each applicable GHG 

listed in paragraphs (c)(12)(iii)(A) 

through (c)(12)(iii)(E) of this section. 

(A) Biogenic CO2 (excluding biogenic 

CO2 emissions from part 75 units). 

(B) CO2. You must include biogenic 

CO2 emissions from part 75 units in 

these totals and exclude biogenic CO2

emissions from other non-part 75 units 

and other source categories. 

(C) CH4. 

(D) N2O. 

(E) Each fluorinated GHG (including 

those not listed in Table A–1 of this 

subpart). 

(d) * * * 

(3) * * * An owner or operator that 

submits an abbreviated report must 

submit a full GHG report according to 

the requirements of paragraph (c) of this 

section beginning in calendar year 2012. 

* * * 

* * * * * 

(f) Verification. To verify the 

completeness and accuracy of reported 

GHG emissions, the Administrator may 

review the certification statements 

described in paragraphs (c)(9) and 

(d)(3)(vi) of this section and any other 

credible evidence, in conjunction with a 

comprehensive review of the GHG 

reports and periodic audits of selected 

reporting facilities. * * * 

(g) * * * 

(4) Missing data computations. For 

each missing data event, also retain a 

record of the cause of the event and the 

corrective actions taken to restore 

malfunctioning monitoring equipment. 

(5) * * * 

(iii) The owner or operator shall 

revise the GHG Monitoring Plan as 

needed to reflect changes in production 

processes, monitoring instrumentation, 

and quality assurance procedures; or to 

improve procedures for the maintenance 

and repair of monitoring systems to 

reduce the frequency of monitoring 

equipment downtime. 

* * * * * 

(h) Annual GHG report revisions. (1) 

The owner or operator shall submit a 

revised annual GHG report within 45 

days of discovering that an annual GHG 

report that the owner or operator 

previously 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 


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operator shall, within 45 days of receipt 

of the notification, either resubmit the 

report that, for each identified 

substantive error, corrects the identified 

substantive error (in accordance with 

the applicable requirements of this part) 

or provide information demonstrating 

that the previously submitted report 

does not contain the identified 

substantive error or that the identified 

error is not a substantive error. 

(3) A substantive error is an error that 

impacts the quantity of GHG emissions 

reported or otherwise prevents the 

reported data from being validated or 

verified. 

(4) Notwithstanding paragraphs (h)(1) 

and (h)(2) of this section, upon request 

by the owner or operator, the 

Administrator may provide reasonable 

extensions of the 45-day period for 

submission of the revised report or 

information under paragraphs (h)(1) and 

(h)(2) of this section. If the 

Administrator receives a request for 

extension of the 45-day period, by email to an address prescribed by the 

Administrator, at least two business 

days prior to the expiration of the 45- 

day period, and the Administrator does 

not respond to the request by the end of 

such period, the extension request is 

deemed to be automatically granted for 

30 more days. During the automatic 30- 

day extension, the Administrator will 

determine what extension, if any, 

beyond the automatic extension is 

reasonable and will provide any such 

additional extension. 

(5) The owner or operator shall retain 

documentation for 3 years to support 

any revision made to an annual GHG 

report. 

(i) Calibration accuracy requirements. 

The owner or operator of a facility or 

supplier that is subject to the 

requirements of this part must meet the 

applicable flow meter calibration and 

accuracy requirements of this paragraph 

(i). The accuracy specifications in this 

paragraph (i) do not apply where either 

the use of company records (as defined 

in § 98.6) or the use of ‘‘best available 

information’’ is specified in an 

applicable subpart of this part to 

quantify fuel usage and/or other 

parameters. Further, the provisions of 

this paragraph (i) do not apply to 

stationary fuel combustion units that 

use the methodologies in part 75 of this 

chapter to calculate CO2 mass 

emissions. 

(1) Except as otherwise provided in 

paragraphs (i)(4) through (i)(6) of this 

section, flow meters that measure liquid 

and gaseous fuel feed rates, process 

stream flow rates, or feedstock flow 

rates and provide data for the GHG 

emissions calculations shall be 

calibrated prior to April 1, 2010 using 

the procedures specified in this 

paragraph (i) when such calibration is 

specified in a relevant subpart of this 

part. Each of these flow meters shall 

meet the applicable accuracy 

specification in paragraph (i)(2) or (i)(3) 

of this section. All other measurement 

devices (e.g., weighing devices) that are 

required by a relevant subpart of this 

part, and that are used to provide data 

for the GHG emissions calculations, 

shall also be calibrated prior to April 1, 

2010; however, the accuracy 

specifications in paragraphs (i)(2) and 

(i)(3) of this section do not apply to 

these devices. Rather, each of these 

measurement devices shall be calibrated 

to meet the accuracy requirement 

specified for the device in the 

applicable subpart of this part, or, in the 

absence of such accuracy requirement, 

the device must be calibrated to an 

accuracy within the appropriate error 

range for the specific measurement 

technology, based on an applicable 

operating standard, including but not 

limited to manufacturer’s specifications 

and industry standards. The procedures 

and methods used to quality-assure the 

data from each measurement device 

shall be documented in the written 

monitoring plan, pursuant to paragraph 

(g)(5)(i)(C) of this section. 

(i) All flow meters and other 

measurement devices that are subject to 

the provisions of this paragraph (i) must 

be calibrated according to one of the 

following: You may use the 

manufacturer’s recommended 

procedures; an appropriate industry 

consensus standard method; or a 

method specified in a relevant subpart 

of this part. The calibration method(s) 

used shall be documented in the 

monitoring plan required under 

paragraph (g) of this section. 

(ii) For facilities and suppliers that 

become subject to this part after April 1, 

2010, all flow meters and other 

measurement devices (if any) that are 

required by the relevant subpart(s) of 

this part to provide data for the GHG 

emissions calculations shall be installed 

no later than the date on which data 

collection is required to begin using the 

measurement device, and the initial 

calibration(s) required by this paragraph 

(i) (if any) shall be performed no later 

than that date. 

(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. 

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 


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measurement point shall not exceed 2.0 

percent of full-scale. 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. 

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 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 a 

manufacturer’s specification or an 

industry consensus standard. 

(C) You must document the methods 

used for the demonstration described in 

paragraph (i)(3)(ii)(A) of this section in 

the written GHG Monitoring Plan under 

paragraph (g)(5)(i)(C) of this section. 

You must also include the data from the 

demonstration, the mathematical 

correlation(s) between the remote 

readings and actual flow meter 

conditions derived from the data, and 

any supporting engineering calculations 

in the GHG Monitoring Plan. You must 

maintain all of this information in a 

format suitable for auditing and 

inspection. 

(D) You must use the mathematical 

correlation(s) derived from the 

demonstration described in paragraph 

(i)(3)(ii)(A) of this section to convert the 

remote temperature or the total pressure 

readings, or both, to the actual 

temperature or total pressure at the flow 

meter, or both, on a daily basis. You 

shall then use the actual temperature 

and total pressure values to correct the 

measured flow rates to standard 

conditions. 

(E) You shall periodically check the 

correlation(s) between the remote and 

actual readings (at least once a year), 

and make any necessary adjustments to 

the mathematical relationship(s). 

(4) Fuel billing meters are exempted 

from the calibration requirements of this 

section and from the GHG Monitoring 

Plan and recordkeeping provisions of 

paragraphs (g)(5)(i)(C), (g)(6), and (g)(7) 

of this section, provided that the fuel 

supplier and any unit combusting the 

fuel do not have any common owners 

and are not owned by subsidiaries or 

affiliates of the same company. Meters 

used exclusively to measure the flow 

rates of fuels that are used for unit 

startup are also exempted from the 

calibration requirements of this section. 

(5) For a flow meter that has been 

previously calibrated in accordance 

with paragraph (i)(1) of this section, an 

additional calibration is not required by 

the date specified in paragraph (i)(1) of 

this section if, as of that date, the 

previous calibration is still active (i.e., 

the device is not yet due for 

recalibration because the time interval 

between successive calibrations has not 

elapsed). In this case, the deadline for 

the successive calibrations of the flow 

meter shall be set according to one of 

the following. You may use either the 

manufacturer’s recommended 

calibration schedule or you may use the 

industry consensus calibration 

schedule. 

(6) For units and processes that 

operate continuously with infrequent 

outages, it may not be possible to meet 

the April 1, 2010 deadline for the initial 

calibration of a flow meter or other 

measurement device without disrupting 

normal process operation. In such cases, 

the owner or operator may postpone the 

initial calibration until the next 

scheduled maintenance outage. The best 

available information from company 

records may be used in the interim. The 

subsequent required recalibrations of 

the flow meters may be similarly 

postponed. Such postponements shall 

be documented in the monitoring plan 

that is required under paragraph (g)(5) 

of this section. 

(7) If the results of an initial 

calibration or a recalibration fail to meet 

the required accuracy specification, data 

from the flow meter shall be considered 

invalid, beginning with the hour of the 

failed calibration and continuing until a 

successful calibration is completed. You 

shall follow the missing data provisions 

provided in the relevant missing data 

sections during the period of data 

invalidation. 

(j) Measurement device installation— 

(1) General. If an owner or operator 

required to report under subpart P, 

subpart X or subpart Y of this part has 

process equipment or units that operate 

continuously and it is not possible to 

install a required flow meter or other 

measurement device by April 1, 2010, 

(or by any later date in 2010 approved 

by the Administrator as part of an 

extension of best available monitoring 

methods per paragraph (d) of this 

section) without process equipment or 

unit shutdown, or through a hot tap, the 

owner or operator may request an 

extension from the Administrator to 

delay installing the measurement device 

until the next scheduled process 

equipment or unit shutdown. If 

approval for such an extension is 

granted by the Administrator, the owner 

or operator must use best available 

monitoring methods during the 

extension period. 

(2) Requests for extension of the use 

of best available monitoring methods for 

measurement device installation. The 

owner or operator must first provide the 


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Administrator an initial notification of 

the intent to submit an extension 

request for use of best available 

monitoring methods beyond December 

31, 2010 (or an earlier date approved by 

EPA) in cases where measurement 

device installation would require a 

process equipment or unit shutdown, or 

could only be done through a hot tap. 

The owner or operator must follow-up 

this initial notification with the 

complete extension request containing 

the information specified in paragraph 

(j)(4) of this section. 

(3) Timing of request. (i) The initial 

notice of intent must be submitted no 

later than January 1, 2011, or by the end 

of the approved use of best available 

monitoring methods extension in 2010, 

whichever is earlier. The completed 

extension request must be submitted to 

the Administrator no later than 

February 15, 2011. 

(ii) Any subsequent extensions to the 

original request must be submitted to 

the Administrator within 4 weeks of the 

owner or operator identifying the need 

to extend the request, but in any event 

no later than 4 weeks before the date for 

the planned process equipment or unit 

shutdown that was provided in the 

original request. 

(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. 

(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. 

(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. 

■ 3. Section 98.4 is amended by revising 

paragraphs (i)(2) and (m)(2)(i) to read as 

follows: 

§ 98.4 Authorization and responsibilities of 

the designated representative. 

* * * * * 

(i) * * * 

(2) The name, organization name 

(company affiliation-employer), 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 affiliation-employer) address, 

e-mail address (if any), telephone 

number, and facsimile transmission 

number (if any) of such designated 

representative or alternate designated 

representative. 

* * * * * 

■ 4. Section 98.6 is amended by: 

■ a. Adding in alphabetical order 

definitions for ‘‘Agricultural byproducts,’’ ‘‘Primary fuel,’’ ‘‘Solid byproducts,’’ ‘‘Used oil,’’ and ‘‘Wood 

residuals.’’ 

■ b. Revising the definitions for ‘‘Bulk 

natural gas liquid or NGL,’’ ‘‘Distillate 

Fuel Oil,’’ ‘‘Fossil fuel,’’ ‘‘Fuel gas,’’ 

‘‘Municipal solid waste or MSW,’’ 

‘‘Natural gas,’’ ‘‘Natural gas liquids 

(NGLs) and ‘‘Standard conditions or 

standard temperature and pressure 

(STP).’’ 

■ c. Removing the definition for ‘‘Fossil 

fuel-fired.’’ 

§ 98.6 Definitions. 

* * * * * 

Agricultural by-products means those 

parts of arable crops that are not used 

for the primary purpose of producing 

food. Agricultural by-products include, 

but are not limited to, oat, corn and 

wheat straws, bagasse, peanut shells, 

rice and coconut husks, soybean hulls, 

palm kernel cake, cottonseed and 

sunflower seed cake, and pomace. 

* * * * * 

Bulk natural gas liquid or NGL refers 

to mixtures of hydrocarbons that have 

been separated from natural gas as 

liquids through the process of 

absorption, condensation, adsorption, or 

other methods. Generally, such liquids 

consist of ethane, propane, butanes, and 

pentanes plus. Bulk NGL is sold to 

fractionators or to refineries and 

petrochemical plants where the 

fractionation takes place. 

* * * * * 

Distillate fuel oil means a 

classification for one of the petroleum 


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fractions produced in conventional 

distillation operations and from crackers 

and hydrotreating process units. The 

generic term distillate fuel oil includes 

kerosene, kerosene-type jet fuel, diesel 

fuels (Diesel Fuels No. 1, No. 2, and No. 

4), and fuel oils (Fuel Oils No. 1, No. 2, 

and No. 4). 

* * * * * 

Fossil fuel means natural gas, 

petroleum, coal, or any form of solid, 

liquid, or gaseous fuel derived from 

such material, for purpose of creating 

useful heat. 

* * * * * 

Fuel gas means gas generated at a 

petroleum refinery or petrochemical 

plant and that is combusted separately 

or in any combination with any type of 

gas. 

* * * * * 

Municipal solid waste or MSW means 

solid phase household, commercial/ 

retail, and/or institutional waste. 

Household waste includes material 

discarded by single and multiple 

residential dwellings, hotels, motels, 

and other similar permanent or 

temporary housing establishments or 

facilities. Commercial/retail waste 

includes material discarded by stores, 

offices, restaurants, warehouses, nonmanufacturing activities at industrial 

facilities, and other similar 

establishments or facilities. Institutional 

waste includes material discarded by 

schools, nonmedical waste discarded by 

hospitals, material discarded by nonmanufacturing activities at prisons and 

government facilities, and material 

discarded by other similar 

establishments or facilities. Household, 

commercial/retail, and institutional 

wastes include yard waste, refusederived fuel, and motor vehicle 

maintenance materials. Insofar as there 

is separate collection, processing and 

disposal of industrial source waste 

streams consisting of used oil, wood 

pallets, construction, renovation, and 

demolition wastes (which includes, but 

is not limited to, railroad ties and 

telephone poles), paper, clean wood, 

plastics, industrial process or 

manufacturing wastes, medical waste, 

motor vehicle parts or vehicle fluff, or 

used tires that do not contain hazardous 

waste identified or listed under 42 

U.S.C. § 6921, such wastes are not 

municipal solid waste. However, such 

wastes qualify as municipal solid waste 

where they are collected with other 

municipal solid waste or are otherwise 

combined with other municipal solid 

waste for processing and/or disposal. 

* * * * * 

Natural gas means a naturally 

occurring mixture of hydrocarbon and 

non-hydrocarbon gases found in 

geologic formations beneath the earth’s 

surface, of which the principal 

constituent is methane. Natural gas may 

be field quality or pipeline quality. 

Natural gas liquids (NGLs) means 

those hydrocarbons in natural gas that 

are separated from the gas as liquids 

through the process of absorption, 

condensation, adsorption, or other 

methods. Generally, such liquids consist 

of ethane, propane, butanes, and 

pentanes plus. Bulk NGLs refers to 

mixtures of NGLs that are sold or 

delivered as undifferentiated product 

from natural gas processing plants. 

* * * * * 

Primary fuel means the fuel that 

provides the greatest percentage of the 

annual heat input to a stationary fuel 

combustion unit. 

* * * * * 

Solid by-products means plant matter 

such as vegetable waste, animal 

materials/wastes, and other solid 

biomass, except for wood, wood waste, 

and sulphite lyes (black liquor). 

* * * * * 

Standard conditions or standard 

temperature and pressure (STP), for the 

purposes of this part, means either 60 or 

68 degrees Fahrenheit and 14.7 pounds 

per square inch absolute. 

* * * * * 

Used oil means a petroleum-derived 

or synthetically-derived oil whose 

physical properties have changed as a 

result of handling or use, such that the 

oil cannot be used for its original 

purpose. Used oil consists primarily of 

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

transmission oil, hydraulic fluids, brake 

fluid, etc.) and industrial oils (e.g., 

industrial engine oils, metalworking 

oils, process oils, industrial grease, etc). 

* * * * * 

Wood residuals means materials 

recovered from three principal sources: 

Municipal solid waste (MSW); 

construction and demolition debris; and 

primary timber processing. Wood 

residuals recovered from MSW include 

wooden furniture, cabinets, pallets and 

containers, scrap lumber (from sources 

other than construction and demolition 

activities), and urban tree and landscape 

residues. Wood residuals from 

construction and demolition debris 

originate from the construction, repair, 

remodeling and demolition of houses 

and non-residential structures. Wood 

residuals from primary timber 

processing include bark, sawmill slabs 

and edgings, sawdust, and peeler log 

cores. Other sources of wood residuals 

include, but are not limited to, railroad 

ties, telephone and utility poles, pier 

and dock timbers, wastewater process 

sludge from paper mills, trim, sander 

dust, and sawdust from wood products 

manufacturing (including resinated 

wood product residuals), and logging 

residues. 

* * * * * 

■ 5. Section 98.7 is amended by: 

■ a. Removing and reserving paragraph 

(b). 

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

(d)(10). 

■ c. Removing paragraph (d)(11). 

■ d. Revising paragraph (e)(4). 

■ e. Removing and reserving paragraph 

(e)(7). 

■ f. Revising paragraphs (e)(8), (e)(10), 

(e)(11), (e)(14) and (e)(15). 

■ g. Revising paragraphs (e)(19) and 

(e)(20). 

■ h. Revising paragraphs (e)(24) through 

(e)(27). 

■ i. Removing and reserving paragraph 

(e)(28). 

■ j. Revising paragraph (e)(30). 

■ k. Revising paragraph (e)(33). 

■ l. Revising paragraph (e)(36). 

■ m. Removing and reserving paragraph 

(e)(39). 

■ n. Adding paragraphs (e)(48) and 

(e)(49). 

■ o. Removing and reserving paragraph 

(f)(1). 

■ p. Revising paragraph (f)(2). 

■ q. Removing and reserving paragraph 

(g)(3). 

■ r. Revising paragraph (m)(3). 

■ s. Adding paragraphs (m)(8) through 

(m)(14). 

§ 98.7 What standardized methods are 

incorporated by reference into this part? 

* * * * * 

(d) * * * 

(1) ASME MFC–3M–2004 

Measurement of Fluid Flow in Pipes 

Using Orifice, Nozzle, and Venturi, 

incorporation by reference (IBR) 

approved for § 98.124(m)(1), § 98.324(e), 

§ 98.354(d), § 98.354(h), § 98.344(c) and 

§ 98.364(e). 

(2) ASME MFC–4M–1986 (Reaffirmed 

1997) Measurement of Gas Flow by 

Turbine Meters, IBR approved for 

§ 98.124(m)(2), § 98.324(e), § 98.344(c), 

§ 98.354(h), and § 98.364(e). 

(3) ASME MFC–5M–1985 (Reaffirmed 

1994) Measurement of Liquid Flow in 

Closed Conduits Using Transit-Time 

Ultrasonic Flow Meters, IBR approved 

for § 98.124(m)(3) and § 98.354(d). 

(4) ASME MFC–6M–1998 

Measurement of Fluid Flow in Pipes 

Using Vortex Flowmeters, IBR approved 

for § 98.124(m)(4), § 98.324(e), 

§ 98.344(c), § 98.354(h), and § 98.364(e). 

(5) ASME MFC–7M–1987 (Reaffirmed 

1992) Measurement of Gas Flow by 

Means of Critical Flow Venturi Nozzles, 

IBR approved for § 98.124(m)(5), 


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§ 98.324(e), § 98.344(c), § 98.354(h), and 

§ 98.364(e). 

(6) ASME MFC–9M–1988 (Reaffirmed 

2001) Measurement of Liquid Flow in 

Closed Conduits by Weighing Method, 

IBR approved for § 98.124(m)(6). 

(7) ASME MFC–11M–2006 

Measurement of Fluid Flow by Means of 

Coriolis Mass Flowmeters, IBR 

approved for § 98.124(m)(7), § 98.324(e), 

§ 98.344(c), and § 98.354(h). 

(8) ASME MFC–14M–2003 

Measurement of Fluid Flow Using Small 

Bore Precision Orifice Meters, IBR 

approved for § 98.124(m)(8), § 98.324(e), 

§ 98.344(c), § 98.354(h), and § 98.364(e). 

(9) ASME MFC–16–2007 

Measurement of Liquid Flow in Closed 

Conduits with Electromagnetic Flow 

Meters, IBR approved for § 98.354(d). 

(10) ASME MFC–18M–2001 

Measurement of Fluid Flow Using 

Variable Area Meters, IBR approved for 

§ 98.324(e), § 98.344(c), § 98.354(h), and 

§ 98.364(e). 

(e) * * * 

(4) ASTM D240–02 (Reapproved 

2007) Standard Test Method for Heat of 

Combustion of Liquid Hydrocarbon 

Fuels by Bomb Calorimeter, IBR 

approved for § 98.254(e). 

* * * * * 

(8) ASTM D1826–94 (Reapproved 

2003) Standard Test Method for 

Calorific (Heating) Value of Gases in 

Natural Gas Range by Continuous 

Recording Calorimeter, IBR approved 

for § 98.254(e). 

* * * * * 

(10) ASTM D1945–03 Standard Test 

Method for Analysis of Natural Gas by 

Gas Chromatography, IBR approved for 

§ 98.74(c), § 98.164(b), § 98.244(b), 

§ 98.254(d), § 98.324(d), § 98.354(g), and 

§ 98.344(b). 

(11) ASTM D1946–90 (Reapproved 

2006) Standard Practice for Analysis of 

Reformed Gas by Gas Chromatography, 

IBR approved for § 98.74(c), § 98.164(b), 

§ 98.254(d), § 98.324(d), § 98.344(b), 

§ 98.354(g), and § 98.364(c). 

* * * * * 

(14) ASTM D2502–04 Standard Test 

Method for Estimation of Mean Relative 

Molecular Mass of Petroleum Oils From 

Viscosity Measurements, IBR approved 

for § 98.74(c). 

(15) ASTM D2503–92 (Reapproved 

2007) Standard Test Method for Relative 

Molecular Mass (Molecular Weight) of 

Hydrocarbons by Thermoelectric 

Measurement of Vapor Pressure, IBR 

approved for § 98.74(c) and 

§ 98.254(d)(6). 

* * * * * 

(19) ASTM D3238–95 (Reapproved 

2005) Standard Test Method for 

Calculation of Carbon Distribution and 

Structural Group Analysis of Petroleum 

Oils by the n-d-M Method, IBR 

approved for § 98.74(c) and § 98.164(b). 

(20) ASTM D3588–98 (Reapproved 

2003) Standard Practice for Calculating 

Heat Value, Compressibility Factor, and 

Relative Density of Gaseous Fuels, IBR 

approved for § 98.254(e). 

* * * * * 

(24) ASTM D4809–06 Standard Test 

Method for Heat of Combustion of 

Liquid Hydrocarbon Fuels by Bomb 

Calorimeter (Precision Method), IBR 

approved for § 98.254(e). 

(25) ASTM D4891–89 (Reapproved 

2006) Standard Test Method for Heating 

Value of Gases in Natural Gas Range by 

Stoichiometric Combustion, IBR 

approved for § 98.254(e) and 

§ 98.324(d). 

(26) ASTM D5291–02 (Reapproved 

2007) Standard Test Methods for 

Instrumental Determination of Carbon, 

Hydrogen, and Nitrogen in Petroleum 

Products and Lubricants, IBR approved 

for § 98.74(c), § 98.164(b), § 98.244(b), 

and § 98.254(i). 

(27) ASTM D5373–08 Standard Test 

Methods for Instrumental Determination 

of Carbon, Hydrogen, and Nitrogen in 

Laboratory Samples of Coal, IBR 

approved for § 98.74(c), § 98.114(b), 

§ 98.164(b), § 98.174(b), § 98.184(b), 

§ 98.244(b), § 98.254(i), § 98.274(b), 

§ 98.284(c), § 98.284(d), § 98.314(c), 

§ 98.314(d), § 98.314(f), and § 98.334(b). 

* * * * * 

(30) ASTM D6348–03 Standard Test 

Method for Determination of Gaseous 

Compounds by Extractive Direct 

Interface Fourier Transform Infrared 

(FTIR) Spectroscopy, IBR approved for 

§ 98.54(b), § 98.124(e)(2), § 98.224(b), 

and § 98.414(n). 

* * * * * 

(33) ASTM D6866–08 Standard Test 

Methods for Determining the Biobased 

Content of Solid, Liquid, and Gaseous 

Samples Using Radiocarbon Analysis, 

IBR approved for § 98.34(d), § 98.34(e), 

and § 98.36(e). 

* * * * * 

(36) ASTM D7459–08 Standard 

Practice for Collection of Integrated 

Samples for the Speciation of Biomass 

(Biogenic) and Fossil-Derived Carbon 

Dioxide Emitted from Stationary 

Emissions Sources, IBR approved for 

§ 98.34(d), § 98.34(e), and § 98.36(e). 

* * * * * 

(48) ASTM D2593–93 (Reapproved 

2009) Standard Test Method for 

Butadiene Purity and Hydrocarbon 

Impurities by Gas Chromatography, 

approved July 1, 2009, IBR approved for 

§ 98.244(b)(4)(xi). 

(49) ASTM D7633–10 Standard Test 

Method for Carbon Black—Carbon 

Content, approved May 15, 2010, IBR 

approved for § 98.244(b)(4)(xii). 

* * * * * 

(f) * * * 

(1) [Reserved] 

(2) GPA 2261–00 Analysis for Natural 

Gas and Similar Gaseous Mixtures by 

Gas Chromatography, IBR approved for 

§ 98.164(b), § 98.254(d), § 98.344(b), and 

§ 98.354(g). 

* * * * * 

(m) * * * 

(3) Protocol for Measuring Destruction 

or Removal Efficiency (DRE) of 

Fluorinated Greenhouse Gas Abatement 

Equipment in Electronics 

Manufacturing, Version 1, EPA–430–R– 

10–003, March 2010 (EPA 430–R–10– 

003), http://www.epa.gov/

semiconductor-pfc/documents/dre_

protocol.pdf, IBR approved for 

§ 98.94(f)(4)(i), § 98.94(g)(3), 

§ 98.97(d)(4), § 98.98, § 98.124(e)(2), and 

§ 98.414(n)(1). 

* * * * * 

(8) Protocol for Measurement of 

Tetrafluoromethane (CF4) and 

Hexafluoroethane (C2F6) Emissions from 

Primary Aluminum Production (2008), 

http://www.epa.gov/highgwp/ 

aluminum-pfc/documents/ 

measureprotocol.pdf, IBR approved for 

§ 98.64(a). 

(9) AP 42, Section 5.2, Transportation 

and Marketing of Petroleum Liquids, 

July 2008, (AP 42, Section 5.2); http:// 

www.epa.gov/ttn/chief/ap42/ch05/final/ 

c05s02.pdf; in Chapter 5, Petroleum 

Industry, of AP 42, Compilation of Air 

Pollutant Emission Factors, 5th Edition, 

Volume I, IBR approved for § 98.253(n). 

(10) Method 9060A, Total Organic 

Carbon, Revision 1, November 2004 

(Method 9060A), http://www.epa.gov/ 

osw/hazard/testmethods/sw846/pdfs/ 

9060a.pdf; in EPA Publication No. SW– 

846, ‘‘Test Methods for Evaluating Solid 

Waste, Physical/Chemical Methods,’’ 

Third Edition, IBR approved for 

§ 98.244(b)(4)(viii). 

(11) Method 8031, Acrylonitrile By 

Gas Chromatography, Revision 0, 

September 1994 (Method 8031), http:// 

www.epa.gov/osw/hazard/testmethods/ 

sw846/pdfs/8031.pdf; in EPA 

Publication No. SW–846, ‘‘Test Methods 

for Evaluating Solid Waste, Physical/ 

Chemical Methods,’’ Third Edition, IBR 

approved for § 98.244(b)(4)(viii). 

(12) Method 8021B, Aromatic and 

Halogenated Volatiles By Gas 

Chromatography Using Photoionization 

and/or Electrolytic Conductivity 

Detectors, Revision 2, December 1996 

(Method 8021B). http://www.epa.gov/ 

osw/hazard/testmethods/sw846/pdfs/ 

8021b.pdf; in EPA Publication No. SW– 

846, ‘‘Test Methods for Evaluating Solid 


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Waste, Physical/Chemical Methods,’’ 

Third Edition, IBR approved for 

§ 98.244(b)(4)(viii). 

(13) Method 8015C, Nonhalogenated 

Organics By Gas Chromatography, 

Revision 3, February 2007 (Method 

8015C). http://www.epa.gov/osw/ 

hazard/testmethods/sw846/pdfs/ 

8015c.pdf; in EPA Publication No. SW– 

846, ‘‘Test Methods for Evaluating Solid 

Waste, Physical/Chemical Methods,’’ 

Third Edition, IBR approved for 

§ 98.244(b)(4)(viii). 

(14) AP 42, Section 7.1, Organic 

Liquid Storage Tanks, November 2006 

(AP 42, Section 7.1), http://www.epa.

gov/ttn/chief/ap42/ch07/final/

c07s01.pdf; in Chapter 7, Liquid Storage 

Tanks, of AP 42, Compilation of Air 

Pollutant Emission Factors, 5th Edition, 

Volume I, IBR approved for 

§ 98.253(m)(1) and § 98.256(o)(2)(i). 

■ 6. Table A–5 to subpart A of part 98 

is amended by revising the entry for 

paragraph (B) under the heading 

‘‘Natural gas and natural gas liquids 

suppliers (subpart NN)’’ to read as 

follows: 

TABLE A–5 TO SUBPART A OF PART

98—SUPPLIER CATEGORY LIST FOR

§ 98.2(A)(4) 

Supplier Categories a Applicable in 2010 

and Future Years 

* * * * * 

Natural gas and natural gas liquids suppliers 

(subpart NN) 

* * * * * 

(B) Local natural gas distribution companies 

that deliver 460,000 thousand standard 

cubic feet or more of natural gas per year. 

* * * * * 

aSuppliers are defined in each applicable 

subpart. 

Subpart C—[Amended] 

■ 7. Section 98.30 is amended by: 

■ a. Revising paragraph (b)(4). 

■ b. Revising paragraph (c) introductory 

text. 

■ c. Adding paragraph (d). 

§ 98.30 Definition of the source category. 

* * * * * 

(b) * * * 

(4) Flares, unless otherwise required 

by provisions of another subpart of this 

part to use methodologies in this 

subpart. 

* * * * * 

(c) For a unit that combusts hazardous 

waste (as defined in § 261.3 of this 

chapter), reporting of GHG emissions is 

not required unless either of the 

following conditions apply: 

* * * * * 

(d) You are not required to report 

GHG emissions from pilot lights. A pilot 

light is a small auxiliary flame that 

ignites the burner of a combustion 

device when the control valve opens. 

■ 8. Section 98.32 is revised to read as 

follows: 

§ 98.32 GHGs to report. 

You must report CO2, CH4, and N2O 

mass emissions from each stationary 

fuel combustion unit, except as 

otherwise indicated in this subpart. 

■ 9. Section 98.33 is amended by: 

■ a. Revising paragraph (a) introductory 

text and paragraph (a)(1). 

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

Equation C–2a of paragraph (a)(2)(i). 

■ c. Revising the first two sentences of 

paragraph (a)(2)(ii) introductory text. 

■ d. In paragraph (a)(2)(ii)(A), revising 

the first sentence and the definitions of 

‘‘(HHV)i,’’ ‘‘(Fuel)i,’’ and ‘‘n’’ in Equation 

C–2b. 

■ e. Revising paragraph (a)(2)(ii)(B). 

■ f. Revising the definitions of ‘‘CC’’, 

‘‘MW’’, and ‘‘MVC’’ in Equation C–5 of 

paragraph (a)(3)(iii). 

■ g. Revising paragraphs (a)(3)(iv), 

(a)(3)(v), (a)(4)(iii), and (a)(4)(iv). 

■ h. Adding paragraph (a)(4)(viii). 

■ i. Revising paragraphs (a)(5) 

introductory text, (a)(5)(i) introductory 

text, (a)(5)(i)(A), (a)(5)(i)(B), (a)(5)(ii) 

introductory text, (a)(5)(ii)(A), (a)(5)(iii) 

introductory text, (a)(5)(iii)(A), and 

(a)(5)(iii)(B). 

■ j. Redesignating paragraph 

(a)(5)(iii)(D) as paragraph (a)(5)(iv), and 

revising newly designated paragraph 

(a)(5)(iv). 

■ k. Revising paragraph (b)(1)(iv). 

■ l. Adding paragraphs (b)(1)(v), 

(b)(1)(vi) and (b)(1)(vii). 

■ m. Revising paragraphs (b)(2)(ii), 

(b)(3)(ii)(A), (b)(3)(iii) introductory text, 

and (b)(3)(iii)(B). 

■ n. Adding paragraph (b)(3)(iv). 

■ o. Adding a second sentence to 

paragraph (b)(4)(i). 

■ p. Revising paragraphs (b)(4)(ii)(A), 

(b)(4)(ii)(B), (b)(4)(ii)(E), (b)(4)(ii)(F), and 

(b)(4)(iii) introductory text. 

■ q. Adding paragraph (b)(4)(iv). 

■ r. Revising paragraph (b)(5) and the 

third sentence of paragraph (b)(6). 

■ s. Revising paragraph (c)(1) 

introductory text and the definition of 

‘‘HHV’’ in Equation C–8. 

■ t. Adding paragraphs (c)(1)(i) and 

(c)(1)(ii). 

■ u. Revising the second sentence of 

paragraph (c)(2). 

■ v. In paragraph (c)(4) introductory 

text, revising the only sentence and 

revising the definition of ‘‘(HI)A’’ in 

Equation C–10. 

■ w. Revising paragraphs (c)(4)(i) and 

(c)(4)(ii). 

■ x. Revising paragraph (c)(5). 

■ y. Adding paragraph (c)(6). 

■ z. In paragraph (d)(1), revising the first 

sentence, adding a second sentence, and 

revising the definition of ‘‘R’’ in 

Equation C–11. 

■ aa. Revising paragraphs (d)(2), 

paragraph (e) introductory text, 

paragraph (e)(1), and paragraph (e)(2) 

introductory text. 

■ bb. Revising the definition of ‘‘Fc’’ in 

Equation C–13 of paragraph (e)(2)(iii). 

■ cc. Revising paragraphs (e)(2)(iv), 

(e)(2)(vi)(C), and (e)(3). 

■ dd. Removing paragraph (e)(4). 

■ ee. Redesignating paragraph (e)(5) as 

(e)(4). 

■ ff. Revising the first sentence of newly 

designated paragraph (e)(4). 

■ gg. Adding paragraph (e)(5). 

§ 98.33 Calculating GHG emissions. 

* * * * * 

(a) CO2 emissions from fuel 

combustion. Calculate CO2 mass 

emissions by using one of the four 

calculation methodologies in paragraphs 

(a)(1) through (a)(4) of this section, 

subject to the applicable conditions, 

requirements, and restrictions set forth 

in paragraph (b) of this section. 

Alternatively, for units that meet the 

conditions of paragraph (a)(5) of this 

section, you may use CO2 mass 

emissions calculation methods from 

part 75 of this chapter, as described in 

paragraph (a)(5) of this section. For 

units that combust both biomass and 

fossil fuels, you must calculate and 

report CO2 emissions from the 

combustion of biomass separately using 

the methods in paragraph (e) of this 

section, except as otherwise provided in 

paragraphs (a)(5)(iv) and (e) of this 

section and in § 98.36(d). 

(1) Tier 1 Calculation Methodology. 

Calculate the annual CO2 mass 

emissions for each type of fuel by using 

Equation C–1, C–1a, or C–1b of this 

section (as applicable). 

(i) Use Equation C–1 except when 

natural gas billing records are used to 

quantify fuel usage and gas 

consumption is expressed in units of 

therms or million Btu. In that case, use 

Equation C–1a or C–1b, as applicable. 


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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 × 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. 

Where: 

CO2 = Annual CO2 mass emissions from 

natural gas combustion (metric tons). 

Gas = Annual natural gas usage, from billing 

records (therms). 

EF = Fuel-specific default CO2 emission 

factor for natural gas, from Table C–1 of 

this subpart (kg CO2/mmBtu). 

0.1 = Conversion factor from therms to 

mmBtu 

1 × 10¥3 = Conversion factor from kilograms 

to metric tons. 

(iii) If natural gas consumption is 

obtained from billing records and fuel 

usage is expressed in mmBtu, use 

Equation C–1b. 

Where: 

CO2 = Annual CO2 mass emissions from 

natural gas combustion (metric tons). 

Gas = Annual natural gas usage, from billing 

records (mmBtu). 

EF = Fuel-specific default CO2 emission 

factor for natural gas, from Table C–1 of 

this subpart (kg CO2/mmBtu). 

1 × 10¥3 = Conversion factor from kilograms 

to metric tons. 

(2) * * * 

(i) * * * 

HHV = Annual average high heat value of the 

fuel (mmBtu per mass or volume). The 

average HHV shall be calculated 

according to the requirements of 

paragraph (a)(2)(ii) of this section. 

* * * * * 

(ii) The minimum required sampling 

frequency for determining the annual 

average HHV (e.g., monthly, quarterly, 

semi-annually, or by lot) is specified in 

§ 98.34. The method for computing the 

annual average HHV is a function of 

unit size and how frequently you 

perform or receive from the fuel 

supplier the results of fuel sampling for 

HHV. * * * 

(A) If the results of fuel sampling are 

received monthly or more frequently, 

then for each unit with a maximum 

rated heat input capacity greater than or 

equal to 100 mmBtu/hr (or for a group 

of units that includes at least one unit 

of that size), the annual average HHV 

shall be calculated using Equation C–2b 

of this section. * * * 

* * * * * 

(HHV)I = Measured high heat value of the 

fuel, for month ‘‘i’’ (which may be the 

arithmetic average of multiple 

determinations), or, if applicable, an 

appropriate substitute data value 

(mmBtu per mass or volume). 

(Fuel)I = Mass or volume of the fuel 

combusted during month ‘‘i,’’ from 

company records (express mass in short 

tons for solid fuel, volume in standard 

cubic feet for gaseous fuel, and volume 

in gallons for liquid fuel). 

n = Number of months in the year that the 

fuel is burned in the unit. 

(B) If the results of fuel sampling are 

received less frequently than monthly, 

or, for a unit with a maximum rated heat 

input capacity less than 100 mmBtu/hr 

(or a group of such units) regardless of 

the HHV sampling frequency, the 

annual average HHV shall either be 

computed according to paragraph 

(a)(2)(ii)(A) of this section or as the 

arithmetic average HHV for all values 

for the year (including valid samples 

and substitute data values under 

§ 98.35). 

* * * * * 

(3) * * * 

(iii) * * * 

CC = Annual average carbon content of the 

gaseous fuel (kg C per kg of fuel). The 

annual average carbon content shall be 

determined using the same procedures as 

specified for HHV in paragraph (a)(2)(ii) 

of this section. 

MW = Annual average molecular weight of 

the gaseous fuel (kg/kg-mole). The 

annual average molecular weight shall be 

determined using the same procedures as 

specified for HHV in paragraph (a)(2)(ii) 

of this section. 

MVC = Molar volume conversion factor at 

standard conditions, as defined in § 98.6. 

Use 849.5 scf per kg mole if you select 

68 °F as standard temperature and 836.6 

scf per kg mole if you select 60 °F as 

standard temperature. 

* * * * * 

(iv) Fuel flow meters that measure 

mass flow rates may be used for liquid 

or gaseous fuels, provided that the fuel 

density is used to convert the readings 

to volumetric flow rates. The density 

shall be measured at the same frequency 

as the carbon content. You must 

measure the density using one of the 

following appropriate methods. You 

may use a method published by a 

consensus-based standards organization, 

if such a method exists, or you may use 

industry standard practice. Consensusbased standards organizations include, 

but are not limited to, the following: 

ASTM International (100 Barr Harbor 

Drive, P.O. Box CB700, West 

Conshohocken, Pennsylvania 19428– 

B2959, (800) 262–1373, http:// 

www.astm.org), the American National 

Standards Institute (ANSI, 1819 L 

Street, NW., 6th floor, Washington, DC 

20036, (202) 293–8020, http:// 

www.ansi.org), the American Gas 

Association (AGA), 400 North Capitol 

Street, NW., 4th Floor, Washington, DC 

20001, (202) 824–7000, http:// 

www.aga.org), the American Society of 

Mechanical Engineers (ASME, Three 

Park Avenue, New York, NY 10016– 

5990, (800) 843–2763, http:// 

www.asme.org), the American 

Petroleum Institute (API, 1220 L Street, 

NW., Washington, DC 20005–4070, 

(202) 682–8000, http://www.api.org), 

and the North American Energy 

Standards Board (NAESB, 801 Travis 

Street, Suite 1675, Houston, TX 77002, 


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79142 Federal Register / Vol. 75, No. 242 / Friday, December 17, 2010 / Rules and Regulations 

(713) 356–0060, http://www.api.org). 

The method(s) used shall be 

documented in the GHG Monitoring 

Plan required under § 98.3(g)(5). 

(v) The following default density 

values may be used for fuel oil, in lieu 

of using the methods in paragraph 

(a)(3)(iv) of this section: 6.8 lb/gal for 

No. 1 oil; 7.2 lb/gal for No. 2 oil; 8.1 lb/ 

gal for No. 6 oil. 

* * * * * 

(4) * * * 

(iii) If the CO2 concentration is 

measured on a dry basis, a correction for 

the stack gas moisture content is 

required. You shall either continuously 

monitor the stack gas moisture content 

using a method described in 

§ 75.11(b)(2) of this chapter or use an 

appropriate default moisture percentage. 

For coal, wood, and natural gas 

combustion, you may use the default 

moisture values specified in 

§ 75.11(b)(1) of this chapter. 

Alternatively, for any type of fuel, you 

may determine an appropriate sitespecific default moisture value (or 

values), using measurements made with 

EPA Method 4—Determination Of 

Moisture Content In Stack Gases, in 

appendix A–3 to part 60 of this chapter. 

Moisture data from the relative accuracy 

test audit (RATA) of a CEMS may be 

used for this purpose. If this option is 

selected, the site-specific moisture 

default value(s) must represent the 

fuel(s) or fuel blends that are combusted 

in the unit during normal, stable 

operation, and must account for any 

distinct difference(s) in the stack gas 

moisture content associated with 

different process operating conditions. 

For each site-specific default moisture 

percentage, at least nine Method 4 runs 

are required, except where the option to 

use moisture data from a RATA is 

selected, and the applicable regulation 

allows a single moisture determination 

to represent two or more RATA runs. In 

that case, you may base the site-specific 

moisture percentage on the number of 

moisture runs allowed by the RATA 

regulation. Calculate each site-specific 

default moisture value by taking the 

arithmetic average of the Method 4 runs. 

Each site-specific moisture default value 

shall be updated whenever the owner or 

operator believes the current value is 

non-representative, due to changes in 

unit or process operation, but in any 

event no less frequently than annually. 

Use the updated moisture value in the 

subsequent CO2 emissions calculations. 

For each unit operating hour, a moisture 

correction must be applied to Equation 

C–6 of this section as follows: 

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 option is selected, the Ffactors used in Equations F–14a and F– 

14b shall be determined according to 

section 3.3.5 or section 3.3.6 of 

appendix F to part 75 of this chapter, as 

applicable. If Equation F–14b is used, 

the hourly moisture percentage in the 

stack gas shall be determined in 

accordance with paragraph (a)(4)(iii) of 

this section. 

* * * * * 

(viii) If a portion of the flue gases 

generated by a unit subject to Tier 4 

(e.g., a slip stream) is continuously 

diverted from the main flue gas exhaust 

system for the purpose of heat recovery 

or some other similar process, and then 

exhausts through a stack that is not 

equipped with the continuous emission 

monitors to measure CO2 mass 

emissions, CO2 emissions shall be 

determined as follows: 

(A) At least once a year, use EPA 

Methods 2 and 3A, and (if necessary) 

Method 4 in appendices A–2 and A–3 

to part 60 of this chapter to perform 

emissions testing at a set point that best 

represents normal, stable process 

operating conditions. A minimum of 

three one-hour Method 3A tests are 

required, to determine the CO2

concentration. A Method 2 test shall be 

performed during each Method 3A run, 

to determine the stack gas volumetric 

flow rate. If moisture correction is 

necessary, a Method 4 run shall also be 

performed during each Method 3A run. 

Important parametric information 

related to the stack gas flow rate (e.g., 

damper positions, fan settings, etc.) 

shall also be recorded during the test. 

(B) Calculate a CO2 mass emission 

rate (in metric tons/hr) from the stack 

test data, using a version of Equation C– 

6 in paragraph (a)(4)(ii) of this section, 

modified as follows. In the Equation C– 

6 nomenclature, replace the words 

‘‘Hourly average’’ in the definitions of 

‘‘CCO2’’ and ‘‘Q’’ with the words ‘‘3-run 

average’’. Substitute the arithmetic 

average values of CO2 concentration and 

stack gas flow rate from the emission 

testing into modified Equation C–6. If 

CO2 is measured on a dry basis, a 

moisture correction of the calculated 

CO2 mass emission rate is required. Use 

Equation C–7 in paragraph (a)(4)(ii) of 

this section to make this correction; 

replace the word ‘‘Hourly’’ with the 

words ‘‘3-run average’’ in the equation 

nomenclature. 

(C) The results of each annual stack 

test shall be used in the GHG emissions 

calculations for the year of the test. 

(D) If, for the majority of the operating 

hours during the year, the diverted 

stream is withdrawn at a steady rate at 

or near the tested set point (as 

evidenced by fan and damper settings 

and/or other parameters), you may use 

the calculated CO2 mass emission rate 

from paragraph (a)(4)(viii)(B) of this 

section to estimate the CO2 mass 

emissions for all operating hours in 

which flue gas is diverted from the main 

exhaust system. Otherwise, you must 

account for the variation in the flow rate 

of the diverted stream, as described in 

paragraph (c)(4)(viii)(E) of this section. 

(E) If the flow rate of the diverted 

stream varies significantly throughout 

the year, except as provided below, 

repeat the stack test and emission rate 

calculation procedures described in 

paragraphs (c)(4)(viii)(A) and 

(c)(4)(viii)(B) of this section at a 

minimum of two more set points across 

the range of typical operating conditions 

to develop a correlation between CO2

mass emission rate and the parametric 

data. If additional testing is not feasible, 

use the following approach to develop 

the necessary correlation. Assume that 

the average CO2 concentration obtained 

in the annual stack test is the same at 

all operating set points. Then, beginning 


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Federal Register / Vol. 75, No. 242 / Friday, December 17, 2010 / Rules and Regulations 79143 

with the measured flow rate from the 

stack test and the associated parametric 

data, perform an engineering analysis to 

estimate the stack gas flow rate at two 

or more additional set points. Calculate 

the CO2 mass emission rate at each set 

point. 

(F) Calculate the annual CO2 mass 

emissions for the diverted stream as 

follows. For a steady-state process, 

multiply the number of hours in which 

flue gas was diverted from the main 

exhaust system by the CO2 mass 

emission rate from the stack test. 

Otherwise, using the best available 

information and engineering judgment, 

apply the most representative CO2 mass 

emission rate from the correlation in 

paragraph (c)(4)(viii)(E) of this section to 

determine the CO2 mass emissions for 

each hour in which flue gas was 

diverted, and sum the results. To 

simplify the calculations, you may 

count partial operating hours as full 

hours. 

(G) Finally, add the CO2 mass 

emissions from paragraph(c)(4)(viii)(F) 

of this section to the annual CO2 mass 

emissions measured by the CEMS at the 

main stack. Report this sum as the total 

annual CO2 mass emissions for the unit. 

(H) The exact method and procedures 

used to estimate the CO2 mass emissions 

for the diverted portion of the flue gas 

exhaust stream shall be documented in 

the Monitoring Plan required under 

§ 98.3(g)(5). 

(5) Alternative methods for certain 

units subject to Part 75 of this chapter. 

Certain units that are not subject to 

subpart D of this part and that report 

data to EPA according to part 75 of this 

chapter may qualify to use the 

alternative methods in this paragraph 

(a)(5), in lieu of using any of the four 

calculation methodology tiers. 

(i) For a unit that combusts only 

natural gas and/or fuel oil, is not subject 

to subpart D of this part, monitors and 

reports heat input data year-round 

according to appendix D to part 75 of 

this chapter, but is not required by the 

applicable part 75 program to report 

CO2 mass emissions data, calculate the 

annual CO2 mass emissions for the 

purposes of this part as follows: 

(A) Use the hourly heat input data 

from appendix D to part 75 of this 

chapter, together with Equation G–4 in 

appendix G to part 75 of this chapter to 

determine the hourly CO2 mass 

emission rates, in units of tons/hr; 

(B) Use Equations F–12 and F–13 in 

appendix F to part 75 of this chapter to 

calculate the quarterly and cumulative 

annual CO2 mass emissions, 

respectively, in units of short tons; and 

* * * * * 

(ii) For a unit that combusts only 

natural gas and/or fuel oil, is not subject 

to subpart D of this part, monitors and 

reports heat input data year-round 

according to § 75.19 of this chapter but 

is not required by the applicable part 75 

program to report CO2 mass emissions 

data, calculate the annual CO2 mass 

emissions for the purposes of this part 

as follows: 

(A) Calculate the hourly CO2 mass 

emissions, in units of short tons, using 

Equation LM–11 in § 75.19(c)(4)(iii) of 

this chapter. 

* * * * * 

(iii) For a unit that is not subject to 

subpart D of this part, uses flow rate and 

CO2 (or O2) CEMS to report heat input 

data year-round according to part 75 of 

this chapter, but is not required by the 

applicable part 75 program to report 

CO2 mass emissions data, calculate the 

annual CO2 mass emissions as follows: 

(A) Use Equation F–11 or F–2 (as 

applicable) in appendix F to part 75 of 

this chapter to calculate the hourly CO2

mass emission rates from the CEMS 

data. If an O2 monitor is used, convert 

the hourly average O2 readings to CO2

using Equation F–14a or F–14b in 

appendix F to part 75 of this chapter (as 

applicable), before applying Equation F– 

11 or F–2. 

(B) Use Equations F–12 and F–13 in 

appendix F to part 75 of this chapter to 

calculate the quarterly and cumulative 

annual CO2 mass emissions, 

respectively, in units of short tons. 

* * * * * 

(iv) For units that qualify to use the 

alternative CO2 emissions calculation 

methods in paragraphs (a)(5)(i) through 

(a)(5)(iii) of this section, if both biomass 

and fossil fuel are combusted during the 

year, separate calculation and reporting 

of the biogenic CO2 mass emissions (as 

described in paragraph (e) of this 

section) is optional, only for the 2010 

reporting year, as provided in 

§ 98.3(c)(12). 

(b) * * * 

(1) * * * 

(iv) May not be used if you routinely 

perform fuel sampling and analysis for 

the fuel high heat value (HHV) or 

routinely receive the results of HHV 

sampling and analysis from the fuel 

supplier at the minimum frequency 

specified in § 98.34(a), or at a greater 

frequency. In such cases, Tier 2 shall be 

used. This restriction does not apply to 

paragraphs (b)(1)(ii), (b)(1)(v), (b)(1)(vi), 

and (b)(1)(vii) of this section. 

(v) May be used for natural gas 

combustion in a unit of any size, in 

cases where the annual natural gas 

consumption is obtained from fuel 

billing records in units of therms or 

mmBtu. 

(vi) May be used for MSW combustion 

in a small, batch incinerator that burns 

no more than 1,000 tons per year of 

MSW. 

(vii) May be used for the combustion 

of MSW and/or tires in a unit, provided 

that no more than 10 percent of the 

unit’s annual heat input is derived from 

those fuels, combined. Notwithstanding 

this requirement, if a unit combusts 

both MSW and tires and the reporter 

elects not to separately calculate and 

report biogenic CO2 emissions from the 

combustion of tires, Tier 1 may be used 

for the MSW combustion, provided that 

no more than 10 percent of the unit’s 

annual heat input is derived from MSW. 

(2) * * * 

(ii) May be used in a unit with a 

maximum rated heat input capacity 

greater than 250 mmBtu/hr for the 

combustion of natural gas and/or 

distillate fuel oil. 

* * * * * 

(3) * * * 

(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 C–1 of this subpart if the fuel 

is combusted in a unit with a maximum 

rated heat input capacity greater than 

250 mmBtu/hr (or, pursuant to 

§ 98.36(c)(3), in a group of units served 

by a common supply pipe, having at 

least one unit with a maximum rated 

heat input capacity greater than 250 

mmBtu/hr), provided that both of the 

following conditions apply: 

* * * * * 

(B) The fuel provides 10% or more of 

the annual heat input to the unit or, if 

§ 98.36(c)(3) applies, to the group of 

units served by a common supply pipe. 

(iv) Shall be used when specified in 

another applicable subpart of this part, 

regardless of unit size. 

(4) * * * 

(i) * * * Tier 4 may also be used for 

any group of stationary fuel combustion 

units, process units, or manufacturing 

units that share a common stack or duct. 

(ii) * * * 

(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, 


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79144 Federal Register / Vol. 75, No. 242 / Friday, December 17, 2010 / Rules and Regulations 

either in accordance with the 

requirements of part 75 of this chapter, 

part 60 of this chapter, or an applicable 

State continuous monitoring program. 

(F) The installed gas or stack gas 

volumetric flow rate monitors are 

required, either by an applicable Federal 

or State regulation or by the unit’s 

operating permit, to undergo periodic 

quality assurance testing in accordance 

with either appendix B to part 75 of this 

chapter, appendix F to part 60 of this 

chapter, or an applicable State 

continuous monitoring program. 

(iii) Shall be used for a unit with a 

maximum rated heat input capacity of 

250 mmBtu/hr or less and for a unit that 

combusts municipal solid waste with a 

maximum rated input capacity of 600 

tons of MSW per day or less, if the unit 

meets all of the following three 

conditions: 

* * * * * 

(iv) May apply to common stack or 

duct configurations where: 

(A) The combined effluent gas streams 

from two or more stationary fuel 

combustion units are vented through a 

monitored common stack or duct. In 

this case, Tier 4 shall be used if all of 

the conditions in paragraph 

(b)(4)(iv)(A)(1) of this section or if the 

conditions in paragraph (b)(4)(iv)(A)(2) 

of this section are met. 

(1) At least one of the units meets the 

requirements of paragraphs (b)(4)(ii)(A) 

through (b)(4)(ii)(C) of this section, and 

the CEMS installed at the common stack 

(or duct) meet the requirements of 

paragraphs (b)(4)(ii)(D) through 

(b)(4)(ii)(F) of this section. 

(2) At least one of the units and the 

monitors installed at the common stack 

or duct meet the requirements of 

paragraph (b)(4)(iii) of this section. 

(B) The combined effluent gas streams 

from a process or manufacturing unit 

and a stationary fuel combustion unit 

are vented through a monitored 

common stack or duct. In this case, Tier 

4 shall be used if the combustion unit 

and the monitors installed at the 

common stack or duct meet the 

applicability criteria specified in 

paragraph (b)(4)(iv)(A)(1), or 

(b)(4)(iv)(A)(2) of this section. 

(C) The combined effluent gas streams 

from two or more manufacturing or 

process units are vented through a 

common stack or duct. In this case, if 

any of the units is required by an 

applicable subpart of this part to use 

Tier 4, the CO2 mass emissions may be 

monitored at each individual unit, or 

the combined CO2 mass emissions may 

be monitored at the common stack or 

duct. However, if it is not feasible to 

monitor the individual units, the 

combined CO2 mass emissions shall be 

monitored at the common stack or duct. 

(5) The Tier 4 Calculation 

Methodology shall be used: 

(i) Starting on January 1, 2010, for a 

unit that is required to report CO2 mass 

emissions beginning on that date, if all 

of the monitors needed to measure CO2

mass emissions have been installed and 

certified by that date. 

(ii) No later than January 1, 2011, for 

a unit that is required to report CO2

mass emissions beginning on January 1, 

2010, if all of the monitors needed to 

measure CO2 mass emissions have not 

been installed and certified by January 

1, 2010. In this case, you may use Tier 

2 or Tier 3 to report GHG emissions for 

2010. However, if the required CEMS 

are certified some time in 2010, you 

need not wait until January 1, 2011 to 

begin using Tier 4. Rather, you may 

switch from Tier 2 or Tier 3 to Tier 4 

as soon as CEMS certification testing is 

successfully completed. If this reporting 

option is chosen, you must document 

the change in CO2 calculation 

methodology in the Monitoring Plan 

required under § 98.3(g)(5) and in the 

GHG emissions report under § 98.3(c). 

Data recorded by the CEMS during a 

certification test period in 2010 may be 

used for reporting under this part, 

provided that the following two 

conditions are met: 

(A) The certification tests are passed 

in sequence, with no test failures. 

(B) No unscheduled maintenance or 

repair of the CEMS is performed during 

the certification test period. 

(iii) No later than 180 days following 

the date on which a change is made that 

triggers Tier 4 applicability under 

paragraph (b)(4)(ii) or (b)(4)(iii) of this 

section (e.g., a change in the primary 

fuel, manner of unit operation, or 

installed continuous monitoring 

equipment). 

(6) * * * However, for units that use 

either the Tier 4 or the alternative 

calculation methodology specified in 

paragraph (a)(5)(iii) of this section, CO2

emissions from the combustion of all 

fuels shall be based solely on CEMS 

measurements. 

(c) * * * 

(1) Use Equation C–8 of this section 

to estimate CH4 and N2O emissions for 

any fuels for which you use the Tier 1 

or Tier 3 calculation methodologies for 

CO2, except when natural gas usage in 

units of therms or mmBtu is obtained 

from gas billing records. In that case, 

use Equation C–8a in paragraph (c)(1)(i) 

of this section or Equation C–8b in 

paragraph (c)(1)(ii) of this section (as 

applicable). For Equation C–8, use the 

same values for fuel consumption that 

you use for the Tier 1 or Tier 3 

calculation. 

* * * * * 

HHV = Default high heat value of the fuel 

from Table C–1 of this subpart; 

alternatively, for Tier 3, if actual HHV 

data are available for the reporting year, 

you may average these data using the 

procedures specified in paragraph 

(a)(2)(ii) of this section, and use the 

average value in Equation C–8 (mmBtu 

per mass or volume). 

* * * * * 

(i) Use Equation C–8a to calculate CH4

and N2O emissions when natural gas 

usage is obtained from gas billing 

records in units of therms. 

Where: 

CH4 or N2O = Annual CH4 or N2O emissions 

from the combustion of natural gas 

(metric tons). 

Fuel = Annual natural gas usage, from gas 

billing records (therms). 

EF = Fuel-specific default emission factor for 

CH4 or N2O, from Table C–2 of this 

subpart (kg CH4 or N2O per mmBtu). 

0.1 = Conversion factor from therms to 

mmBtu 

1 × 10¥3 = Conversion factor from kilograms 

to metric tons. 

(ii) Use Equation C–8b to calculate 

CH4 and N2O emissions when natural 

gas usage is obtained from gas billing 

records in units of mmBtu. 

CH4 or N2O = 1 × 10¥3 * Fuel * EF 

(Eq. C–8b) 

Where: 

CH4 or N2O = Annual CH4 or N2O emissions 

from the combustion of natural gas 

(metric tons). 

Fuel = Annual natural gas usage, from gas 

billing records (mmBtu). 

EF = Fuel-specific default emission factor for 

CH4 or N2O, from Table C–2 of this 

subpart (kg CH4 or N2O per mmBtu). 

1 × 10¥3 = Conversion factor from kilograms 

to metric tons. 


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(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 year-round 

according to part 75 of this chapter, 

obtain the cumulative annual heat input 

directly from the electronic data reports 

required under § 75.64 of this chapter. 

For Tier 4 units, use the best available 

information, as described in paragraph 

(c)(4)(ii)(C) of this section, to estimate 

the cumulative annual heat input (HI)A. 

(ii) If more than one type of fuel listed 

in Table C–2 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 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. 

(5) When multiple fuels are 

combusted during the reporting year, 

sum the fuel-specific results from 

Equations C–8, C–8a, C–8b, C–9a, C–9b, 

or C–10 of this section (as applicable) to 

obtain the total annual CH4 and N2O 

emissions, in metric tons. 

(6) Calculate the annual CH4 and N2O 

mass emissions from the combustion of 

blended fuels as follows: 

(i) If the mass or volume of each 

component fuel in the blend is 

measured before the fuels are mixed and 

combusted, calculate and report CH4

and N2O emissions separately for each 

component fuel, using the applicable 

procedures in this paragraph (c). 

(ii) If the mass or volume of each 

component fuel in the blend is not 

measured before the fuels are mixed and 

combusted, a reasonable estimate of the 

percentage composition of the blend, 

based on best available information, is 

required. Perform the following 

calculations for each component fuel ‘‘i’’ 

that is listed in Table C–2: 

(A) Multiply (% Fuel)i, the estimated 

mass or volume percentage (decimal 

fraction) of component fuel ‘‘i’’, by the 

total annual mass or volume of the 

blended fuel combusted during the 

reporting year, to obtain an estimate of 

the annual consumption of component 

‘‘i’’; 

(B) Multiply the result from paragraph 

(c)(6)(ii)(A) of this section by the HHV 

of the fuel (default value or, if available, 

the measured annual average value), to 

obtain an estimate of the annual heat 

input from component ‘‘i’’; 

(C) Calculate the annual CH4 and N2O 

emissions from component ‘‘i’’, using 

Equation C–8, C–8a, C–8b, C–9a, or 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 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 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, in 

accordance with § 98.3(c)(12), separate 

reporting of biogenic CO2 emissions is 

optional for the 2010 reporting year for 

units subject to subpart D of this part 

and for units that use the CO2 mass 

emissions calculation methodologies in 

part 75 of this chapter, pursuant to 

paragraph (a)(5) of this section. 

However, if the owner or operator opts 

to report biogenic CO2 emissions 

separately for these units, the 

appropriate method(s) in this paragraph 

(e) shall be used. Separate reporting of 

biogenic CO2 emissions from the 

combustion of tires is also optional, but 

may be reported by following the 

provisions of paragraph (e)(3) of this 

section. 


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79146 Federal Register / Vol. 75, No. 242 / Friday, December 17, 2010 / Rules and Regulations 

(1) You may use Equation C–1 of this 

subpart to calculate the annual CO2

mass emissions from the combustion of 

the biomass fuels listed in Table C–1 of 

this subpart (except MSW and tires), in 

a unit of any size, including units 

equipped with a CO2 CEMS, except 

when the use of Tier 2 is required as 

specified in paragraph (b)(1)(iv) of this 

section. Determine the quantity of 

biomass combusted using one of the 

following procedures in this paragraph 

(e)(1), as appropriate, and document the 

selected procedures in the Monitoring 

Plan under § 98.3(g): 

(i) Company records. 

(ii) The procedures in paragraph (e)(5) 

of this section. 

(iii) The best available information for 

premixed fuels that contain biomass and 

fossil fuels (e.g., liquid fuel mixtures 

containing biodiesel). 

(2) You may use the procedures of 

this paragraph if the following three 

conditions are met: First, a CO2 CEMS 

(or a surrogate O2 monitor) and a stack 

gas flow rate monitor are used to 

determine the annual CO2 mass 

emissions (either according to part 75 of 

this chapter, the Tier 4 Calculation 

Methodology, or the alternative 

calculation methodology specified in 

paragraph (a)(5)(iii) of this section); 

second, neither MSW nor tires is 

combusted in the unit during the 

reporting year; and third, the CO2

emissions consist solely of combustion 

products (i.e., no process or sorbent 

emissions included). 

* * * * * 

(iii) * * * 

Fc = Fuel-specific carbon based F-factor, 

either a default value from Table 1 in 

section 3.3.5 of appendix F to part 75 of 

this chapter, or a site-specific value 

determined under section 3.3.6 of 

appendix F to part 75 (scf CO2/mmBtu). 

* * * * * 

(iv) Subtract Vff from Vtotal to obtain 

Vbio, the annual volume of CO2 from the 

combustion of biomass. 

* * * * * 

(vi) * * * 

(C) From the electronic data report 

required under § 75.64 of this chapter, 

for units in the Acid Rain Program and 

other units using CEMS to monitor and 

report CO2 mass emissions according to 

part 75 of this chapter. However, before 

calculating the annual biogenic CO2

mass emissions, multiply the 

cumulative annual CO2 mass emissions 

by 0.91 to convert from short tons to 

metric tons. 

(3) You must use the procedures in 

paragraphs (e)(3)(i) through (e)(3)(iii) of 

this section to determine the annual 

biogenic CO2 emissions from the 

combustion of MSW, except as 

otherwise provided in paragraph 

(e)(3)(iv) of this section. These 

procedures also may be used for any 

unit that co-fires biomass and fossil 

fuels, including units equipped with a 

CO2 CEMS, and units for which optional 

separate reporting of biogenic CO2

emissions from the combustion of tires 

is selected. 

(i) Use an applicable CO2 emissions 

calculation method in this section to 

quantify the total annual CO2 mass 

emissions from the unit. 

(ii) Determine the relative proportions 

of biogenic and non-biogenic CO2

emissions in the flue gas on a quarterly 

basis using the method specified in 

§ 98.34(d) (for units that combust MSW 

as the primary fuel or as the only fuel 

with a biogenic component) or in 

§ 98.34(e) (for other units, including 

units that combust tires). 

(iii) Determine the annual biogenic 

CO2 mass emissions from the unit by 

multiplying the total annual CO2 mass 

emissions by the annual average 

biogenic decimal fraction obtained from 

§ 98.34(d) or § 98.34(e), as applicable. 

(iv) If the combustion of MSW and/or 

tires provides no more than 10 percent 

of the annual heat input to a unit, or if 

a small, batch incinerator combusts no 

more than 1,000 tons per year of MSW, 

you may estimate the annual biogenic 

CO2 emissions as follows, in lieu of 

following the procedures in paragraphs 

(e)(3)(i) through (e)(3)(iii) of this section: 

(A) Calculate the total annual CO2

emissions from combustion of MSW 

and/or tires in the unit, using the Tier 

1 calculation methodology in paragraph 

(a)(1) of this section. 

(B) Multiply the result from paragraph 

(e)(3)(iv)(A) of this section by the 

appropriate default factor to determine 

the annual biogenic CO2 emissions, in 

metric tons. For MSW, use a default 

factor of 0.60 and for tires, use a default 

factor of 0.20. 

(4) If Equation C–1 or Equation C–2a 

of this section is selected to calculate 

the annual biogenic mass emissions for 

wood, wood waste, or other solid 

biomass-derived fuel, Equation C–15 of 

this section may be used to quantify 

biogenic fuel consumption, provided 

that all of the required input parameters 

are accurately quantified. * * * 

(5) For units subject to subpart D of 

this part and for units that use the 

methods in part 75 of this chapter to 

quantify CO2 mass emissions in 

accordance with paragraph (a)(5) of this 

section, you may calculate biogenic CO2

emissions from the combustion of 

biomass fuels listed in Table C–1 of this 

subpart using Equation C–15a. This 

equation may not be used to calculate 

biogenic CO2 emissions from the 

combustion of tires or MSW; the 

methods described in paragraph (e)(3) of 

this section must be used for those fuels. 

Whenever (HI)A, the annual heat input 

from combustion of biomass fuel in 

Equation C–15a, cannot be determined 

solely from the information in the 

electronic emissions reports under 

§ 75.64 of this chapter (e.g., in cases 

where a unit uses CEMS in combination 

with multiple F-factors, a worst-case Ffactor, or a prorated F-factor to report 

heat input rather than reporting heat 

input based on fuel type), use the best 

available information (as described in 

§§ 98.33(c)(4)(ii)(C) and (c)(4)(ii)(D)) to 

determine (HI)A. 

CO2 = 0.001 * (HI)A * EF (Eq. C–15a) 

Where: 

CO2 = Annual CO2 mass emissions from the 

combustion of a particular type of 

biomass fuel listed in Table C–1 (metric 

tons) 

(HI)A = Annual heat input from the biomass 

fuel, obtained, where feasible, from the 

electronic emissions reports required 

under § 75.64 of this chapter. Where this 

is not feasible use best available 

information, as described in 

§§ 98.33(c)(4)(ii)(C) and (c)(4)(ii)(D) 

(mmBtu) 

EF = CO2 emission factor for the biomass 

fuel, from Table C–1 (kg CO2/mmBtu) 

0.001 = Conversion factor from kg to metric 

tons 

* * * * * 

■ 10. Section 98.34 is amended by: 

■ a. Revising paragraphs (a)(2), (a)(3), 

(a)(6), (b)(1) introductory text, (b)(1)(i), 

(b)(1)(ii), (b)(1)(iii), (b)(1)(vi), (b)(3)(ii), 

and (b)(3)(v). 

■ b. Removing paragraph (b)(4). 

■ c. Redesignating paragraph (b)(5) as 

(b)(4). 

■ d. Revising newly designated 

paragraph (b)(4). 

■ e. Revising paragraphs (c) 

introductory text, (c)(1)(i), (c)(1)(ii), 

(c)(2), (c)(3), and (c)(4). 

■ f. Adding paragraphs (c)(6) and (c)(7). 

■ g. Revising paragraphs (d), (e), (f) 

introductory text, (f)(1), (f)(3), (f)(5), and 

(f)(6). 

■ h. Adding paragraphs (f)(7) and (f)(8). 

■ i. Removing paragraph (g). 

§ 98.34 Monitoring and QA/QC 

requirements. 

* * * * * 

(a) * * * 

(2) The minimum required frequency 

of the HHV sampling and analysis for 

each type of fuel or fuel mixture (blend) 

is specified in this paragraph. When the 

specified frequency for a particular fuel 

or blend is based on a specified time 

period (e.g., week, month, quarter, or 

half-year), fuel sampling and analysis is 


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required only for those time periods in 

which the fuel or blend is combusted. 

The owner or operator may perform fuel 

sampling and analysis more often than 

the minimum required frequency, in 

order to obtain a more representative 

annual average HHV. 

(i) For natural gas, semiannual 

sampling and analysis is required (i.e., 

twice in a calendar year, with 

consecutive samples taken at least four 

months apart). 

(ii) For coal and fuel oil, and for any 

other solid or liquid fuel that is 

delivered in lots, analysis of at least one 

representative sample from each fuel lot 

is required. For fuel oil, as an alternative 

to sampling each fuel lot, a sample may 

be taken upon each addition of oil to the 

unit’s storage tank. Flow proportional 

sampling, continuous drip sampling, or 

daily manual oil sampling may also be 

used, in lieu of sampling each fuel lot. 

If the daily manual oil sampling option 

is selected, sampling from a particular 

tank is required only on days when oil 

from the tank is combusted by the unit 

(or units) served by the tank. If you elect 

to sample from the storage tank upon 

each addition of oil to the tank, you 

must take at least one sample from each 

tank that is currently in service and 

whenever oil is added to the tank, for 

as long as the tank remains in service. 

You need not take any samples from a 

storage tank while it is out of service. 

Rather, take a sample when the tank is 

brought into service and whenever oil is 

added to the tank, for as long as the tank 

remains in service. If multiple additions 

of oil are made to a particular in-service 

tank on a given day (e.g., from multiple 

deliveries), one sample taken after the 

final addition of oil is sufficient. For the 

purposes of this section, a fuel lot is 

defined as a shipment or delivery of a 

single type of fuel (e.g., ship load, barge 

load, group of trucks, group of railroad 

cars, oil delivery via pipeline from a 

tank farm, etc.). However, if multiple 

deliveries of a particular type of fuel are 

received from the same supply source in 

a given calendar month, the deliveries 

for that month may be considered, 

collectively, to comprise a fuel lot, 

requiring only one representative 

sample, subject to the following 

conditions: 

(A) For coal, the ‘‘type’’ of fuel means 

the rank of the coal (i.e., anthracite, 

bituminous, sub-bituminous, or lignite). 

For fuel oil, the ‘‘type’’ of fuel means the 

grade number or classification of the oil 

(e.g., No. 1 oil, No. 2 oil, kerosene, Jet 

A fuel, etc.). 

(B) The owner or operator shall 

document in the monitoring plan under 

§ 98.3(g)(5) how the monthly sampling 

of each type of fuel is performed. 

(iii) For liquid fuels other than fuel 

oil, and for gaseous fuels other than 

natural gas (including biogas), sampling 

and analysis is required at least once per 

calendar quarter. To the extent 

practicable, consecutive quarterly 

samples shall be taken at least 30 days 

apart. 

(iv) For other solid fuels (except 

MSW), weekly sampling is required to 

obtain composite samples, which are 

then analyzed monthly. 

(v) For fuel blends that are received 

already mixed, or that are mixed on-site 

without measuring the exact amount of 

each component, as described in 

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

determine the HHV of the blend as 

follows. For blends of solid fuels (except 

MSW), weekly sampling is required to 

obtain composite samples, which are 

analyzed monthly. For blends of liquid 

or gaseous fuels, sampling and analysis 

is required at least once per calendar 

quarter. More frequent sampling is 

recommended if the composition of the 

blend varies significantly during the 

year. 

(3) Special considerations for 

blending of fuels. In situations where 

different types of fuel listed in Table C– 

1 of this subpart (for example, different 

ranks of coal or different grades of fuel 

oil) are in the same state of matter (i.e., 

solid, liquid, or gas), and are blended 

prior to combustion, use the following 

procedures to determine the appropriate 

CO2 emission factor and HHV for the 

blend. 

(i) If the fuels to be blended are 

received separately, and if the quantity 

(mass or volume) of each fuel is 

measured before the fuels are mixed and 

combusted, then, for each component of 

the blend, calculate the CO2 mass 

emissions separately. Substitute into 

Equation C–2a of this subpart the total 

measured mass or volume of the 

component fuel (from company 

records), together with the appropriate 

default CO2 emission factor from Table 

C–1, and the annual average HHV, 

calculated according to § 98.33(a)(2)(ii). 

In this case, the fact that the fuels are 

blended prior to combustion is of no 

consequence. 

(ii) If the fuel is received as a blend 

(i.e., already mixed) or if the 

components are mixed on site without 

precisely measuring the mass or volume 

of each one individually, a reasonable 

estimate of the relative proportions of 

the components of the blend must be 

made, using the best available 

information (e.g., the approximate 

annual average mass or volume 

percentage of each fuel, based on the 

typical or expected range of values). 

Determine the appropriate CO2 emission 

factor and HHV for use in Equation C– 

2a of this subpart, as follows: 

(A) Consider the blend to be the ‘‘fuel 

type,’’ measure its HHV at the frequency 

prescribed in paragraph (a)(2)(v) of this 

section, and determine the annual 

average HHV value for the blend 

according to § 98.33(a)(2)(ii). 

(B) Calculate a heat-weighted CO2

emission factor, (EF)B, for the blend, 

using Equation C–16 of this section. 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. 

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) 


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(HHV)B = Annual average high heat value for 

the blend, calculated according to 

§ 98.33(a)(2)(ii) (mmBtu per mass or 

volume) 

(iii) Note that for the case described 

in paragraph (a)(3)(ii) of this section, if 

measured HHV values for the 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. 

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) 

(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 during 

the year multiplied by the sum of the 

mass or volume percentages of the Table 

C–1 fuels in the blend. For the example 

in paragraph (a)(3)(iv)(A) of this section, 

‘‘Fuel’’ = (Annual volume of the blend 

combusted)(0.80). 

* * * * * 

(6) You must use one of the following 

appropriate fuel sampling and analysis 

methods. The HHV may be calculated 

using chromatographic analysis together 

with standard heating values of the fuel 

constituents, provided that the gas 

chromatograph is operated, maintained, 

and calibrated according to the 

manufacturer’s instructions. 

Alternatively, you may use a method 

published by a consensus-based 

standards organization if such a method 

exists, or you may use industry standard 

practice to determine the high heat 

values. Consensus-based standards 

organizations include, but are not 

limited to, the following: ASTM 

International (100 Barr Harbor Drive, 

P.O. Box CB700, West Conshohocken, 

Pennsylvania 19428–B2959, (800) 262– 

1373, http://www.astm.org), the 

American National Standards Institute 

(ANSI, 1819 L Street, NW., 6th floor, 

Washington, DC 20036, (202) 293–8020, 

http://www.ansi.org), the American Gas 

Association (AGA, 400 North Capitol 

Street, NW., 4th Floor, Washington, DC 

20001, (202) 824–7000, http:// 

www.aga.org), the American Society of 

Mechanical Engineers (ASME, Three 

Park Avenue, New York, NY 10016– 

5990, (800) 843–2763, http:// 

www.asme.org), the American 

Petroleum Institute (API, 1220 L Street, 

NW., Washington, DC 20005–4070, 

(202) 682–8000, http://www.api.org), 

and the North American Energy 

Standards Board (NAESB, 801 Travis 

Street, Suite 1675, Houston, TX 77002, 

(713) 356–0060, http://www.api.org). 

The method(s) used shall be 

documented in the Monitoring Plan 

required under § 98.3(g)(5). 

(b) * * * 

(1) You must calibrate each oil and 

gas flow meter according to § 98.3(i) and 

the provisions of this paragraph (b)(1). 

(i) Perform calibrations using any of 

the test methods and procedures in this 

paragraph (b)(1)(i). The method(s) used 

shall be documented in the Monitoring 

Plan required under § 98.3(g)(5). 

(A) You may use the calibration 

procedures specified by the flow meter 

manufacturer. 

(B) You may use an appropriate flow 

meter calibration method published by 

a consensus-based standards 

organization, if such a method exists. 

Consensus-based standards 

organizations include, but are not 

limited to, the following: ASTM 

International (100 Barr Harbor Drive, 

P.O. Box CB700, West Conshohocken, 

Pennsylvania 19428–B2959, (800) 262– 

1373, http://www.astm.org), the 

American National Standards Institute 

(ANSI, 1819 L Street, NW., 6th floor, 

Washington, DC 20036, (202) 293–8020, 

http://www.ansi.org), the American Gas 

Association (AGA, 400 North Capitol 

Street, NW., 4th Floor, Washington, DC 

20001, (202) 824–7000, http:// 

www.aga.org), the American Society of 

Mechanical Engineers (ASME, Three 

Park Avenue, New York, NY 10016– 

5990, (800) 843–2763, http:// 

www.asme.org), the American 

Petroleum Institute (API, 1220 L Street, 

NW., Washington, DC 20005–4070, 

(202) 682–8000, http://www.api.org), 

and the North American Energy 

Standards Board (NAESB, 801 Travis 

Street, Suite 1675, Houston, TX 77002, 

(713) 356–0060, http://www.api.org). 

(C) You may use an industry-accepted 

practice. 

(ii) In addition to the initial 

calibration required by § 98.3(i), 

recalibrate each fuel flow meter (except 

as otherwise provided in paragraph 

(b)(1)(iii) of this section) according to 

one of the following. You may 

recalibrate annually, at the minimum 

frequency specified by the 

manufacturer, or at the interval 

specified by industry standard practice. 

(iii) Fuel billing meters are exempted 

from the initial and ongoing calibration 

requirements of this paragraph and from 

the Monitoring Plan and recordkeeping 


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Federal Register / Vol. 75, No. 242 / Friday, December 17, 2010 / Rules and Regulations 79149 

requirements of §§ 98.3(g)(5)(i)(C), (g)(6), 

and (g)(7), provided that the fuel 

supplier and the unit combusting the 

fuel do not have any common owners 

and are not owned by subsidiaries or 

affiliates of the same company. Meters 

used exclusively to measure the flow 

rates of fuels that are only used for unit 

startup are also exempted from the 

initial and ongoing calibration 

requirements of this paragraph. 

* * * * * 

(vi) If a mixture of liquid or gaseous 

fuels is transported by a common pipe, 

you may either separately meter each of 

the fuels prior to mixing, using flow 

meters calibrated according to § 98.3(i), 

or consider the fuel mixture to be the 

‘‘fuel type’’ and meter the mixed fuel, 

using a flow meter calibrated according 

to § 98.3(i). 

* * * * * 

(3) * * * 

(ii) For each type of fuel, the 

minimum required frequency for 

collecting and analyzing samples for 

carbon content and (if applicable) 

molecular weight is specified in this 

paragraph. When the sampling 

frequency is based on a specified time 

period (e.g., week, month, quarter, or 

half-year), fuel sampling and analysis is 

required for only those time periods in 

which the fuel is combusted. 

(A) For natural gas, semiannual 

sampling and analysis is required (i.e., 

twice in a calendar year, with 

consecutive samples taken at least four 

months apart). 

(B) For coal and fuel oil and for any 

other solid or liquid fuel that is 

delivered in lots, analysis of at least one 

representative sample from each fuel lot 

is required. For fuel oil, as an alternative 

to sampling each fuel lot, a sample may 

be taken upon each addition of oil to the 

storage tank. Flow proportional 

sampling, continuous drip sampling, or 

daily manual oil sampling may also be 

used, in lieu of sampling each fuel lot. 

If the daily manual oil sampling option 

is selected, sampling from a particular 

tank is required only on days when oil 

from the tank is combusted by the unit 

(or units) served by the tank. If you elect 

to sample from the storage tank upon 

each addition of oil to the tank, you 

must take at least one sample from each 

tank that is currently in service and 

whenever oil is added to the tank, for 

as long as the tank remains in service. 

You need not take any samples from a 

storage tank while it is out of service. 

Rather, take a sample when the tank is 

brought into service and whenever oil is 

added to the tank, for as long as the tank 

remains in service. If multiple additions 

of oil are made to a particular in service 

tank on a given day (e.g., from multiple 

deliveries), one sample taken after the 

final addition of oil is sufficient. For the 

purposes of this section, a fuel lot is 

defined as a shipment or delivery of a 

single type of fuel (e.g., ship load, barge 

load, group of trucks, group of railroad 

cars, oil delivery via pipeline from a 

tank farm, etc.). However, if multiple 

deliveries of a particular type of fuel are 

received from the same supply source in 

a given calendar month, the deliveries 

for that month may be considered, 

collectively, to comprise a fuel lot, 

requiring only one representative 

sample, subject to the following 

conditions: 

(1) For coal, the ‘‘type’’ of fuel means 

the rank of the coal (i.e., anthracite, 

bituminous, sub-bituminous, or lignite). 

For fuel oil, the ‘‘type’’ of fuel means the 

grade number or classification of the oil 

(e.g., No. 1 oil, No. 2 oil, kerosene, Jet 

A fuel, etc.). 

(2) The owner or operator shall 

document in the monitoring plan under 

§ 98.3(g)(5) how the monthly sampling 

of each type of fuel is performed. 

(C) For liquid fuels other than fuel oil 

and for biogas, sampling and analysis is 

required at least once per calendar 

quarter. To the extent practicable, 

consecutive quarterly samples shall be 

taken at least 30 days apart. 

(D) For other solid fuels (except 

MSW), weekly sampling is required to 

obtain composite samples, which are 

then analyzed monthly. 

(E) For gaseous fuels other than 

natural gas and biogas (e.g., process gas), 

daily sampling and analysis to 

determine the carbon content and 

molecular weight of the fuel is required 

if continuous, on-line equipment, such 

as a gas chromatograph, is in place to 

make these measurements. Otherwise, 

weekly sampling and analysis shall be 

performed. 

(F) For mixtures (blends) of solid 

fuels, weekly sampling is required to 

obtain composite samples, which are 

analyzed monthly. For blends of liquid 

fuels, and for gas mixtures consisting 

only of natural gas and biogas, sampling 

and analysis is required at least once per 

calendar quarter. For gas mixtures that 

contain gases other than natural gas 

(including biogas), daily sampling and 

analysis to determine the carbon content 

and molecular weight of the fuel is 

required if continuous, on-line 

equipment is in place to make these 

measurements. Otherwise, weekly 

sampling and analysis shall be 

performed. 

* * * * * 

(v) To calculate the CO2 mass 

emissions from combustion of a blend of 

fuels in the same state of matter (solid, 

liquid, or gas), you may either: 

(A) Apply Equation C–3, C–4 or C–5 

of this subpart (as applicable) to each 

component of the blend, if the mass or 

volume, the carbon content, and (if 

applicable), the molecular weight of 

each component are accurately 

measured prior to blending; or 

(B) Consider the blend to be the ‘‘fuel 

type.’’ Then, at the frequency specified 

in paragraph (b)(3)(ii)(F) of this section, 

measure the carbon content and, if 

applicable, the molecular weight of the 

blend and calculate the annual average 

value of each parameter in the manner 

described in § 98.33(a)(2)(ii). Also 

measure the mass or volume of the 

blended fuel combusted during the 

reporting year. Substitute these 

measured values into Equation C–3, C– 

4, or C–5 of this subpart (as applicable). 

(4) You must use one of the following 

appropriate fuel sampling and analysis 

methods. The results of 

chromatographic analysis of the fuel 

may be used, provided that the gas 

chromatograph is operated, maintained, 

and calibrated according to the 

manufacturer’s instructions. 

Alternatively, you may use a method 

published by a consensus-based 

standards organization if such a method 

exists, or you may use industry standard 

practice to determine the carbon content 

and molecular weight (for gaseous fuel) 

of the fuel. Consensus-based standards 

organizations include, but are not 

limited to, the following: ASTM 

International (100 Barr Harbor Drive, 

P.O. Box CB700, West Conshohocken, 

Pennsylvania 19428–B2959, (800) 262– 

1373, http://www.astm.org), the 

American National Standards Institute 

(ANSI, 1819 L Street, NW., 6th floor, 

Washington, DC 20036, (202) 293–8020, 

http://www.ansi.org), the American Gas 

Association (AGA, 400 North Capitol 

Street, NW., 4th Floor, Washington, DC 

20001, (202) 824–7000, http:// 

www.aga.org), the American Society of 

Mechanical Engineers (ASME, Three 

Park Avenue, New York, NY 10016– 

5990, (800) 843–2763, http:// 

www.asme.org), the American 

Petroleum Institute (API, 1220 L Street, 

NW., Washington, DC 20005–4070, 

(202) 682–8000, http://www.api.org), 

and the North American Energy 

Standards Board (NAESB, 801 Travis 

Street, Suite 1675, Houston, TX 77002, 

(713) 356–0060, http://www.api.org). 

The method(s) used shall be 

documented in the Monitoring Plan 

required under § 98.3(g)(5). 

(c) For the Tier 4 Calculation 

Methodology, the CO2, flow rate, and (if 

applicable) moisture monitors must be 


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79150 Federal Register / Vol. 75, No. 242 / Friday, December 17, 2010 / Rules and Regulations 

certified prior to the applicable deadline 

specified in § 98.33(b)(5). 

(1) * * * 

(i) §§ 75.20(c)(2), (c)(4), and (c)(5) 

through (c)(7) of this chapter and 

appendix A to part 75 of this chapter. 

(ii) The calibration drift test and 

relative accuracy test audit (RATA) 

procedures of Performance Specification 

3 in appendix B to part 60 of this 

chapter (for the CO2 concentration 

monitor) and Performance Specification 

6 in appendix B to part 60 of this 

chapter (for the continuous emission 

rate monitoring system (CERMS)). 

* * * * * 

(2) If an O2 concentration monitor is 

used to determine CO2 concentrations, 

the applicable provisions of part 75 of 

this chapter, part 60 of this chapter, or 

an applicable State continuous 

monitoring program shall be followed 

for initial certification and on-going 

quality assurance, and all required 

RATAs of the monitor shall be done on 

a percent CO2 basis. 

(3) For ongoing quality assurance, 

follow the applicable procedures in 

either appendix B to part 75 of this 

chapter, appendix F to part 60 of this 

chapter, or an applicable State 

continuous monitoring program. If 

appendix F to part 60 of this chapter is 

selected for on-going quality assurance, 

perform daily calibration drift 

assessments for both the CO2 monitor 

(or surrogate O2 monitor) and the flow 

rate monitor, conduct cylinder gas 

audits of the CO2 concentration monitor 

in three of the four quarters of each year 

(except for non-operating quarters), and 

perform annual RATAs of the CO2

concentration monitor and the CERMS. 

(4) For the purposes of this part, the 

stack gas volumetric flow rate monitor 

RATAs required by appendix B to part 

75 of this chapter and the annual 

RATAs of the CERMS required by 

appendix F to part 60 of this chapter 

need only be done at one operating 

level, representing normal load or 

normal process operating conditions, 

both for initial certification and for 

ongoing quality assurance. 

* * * * * 

(6) For certain applications where 

combined process emissions and 

combustion emissions are measured, the 

CO2 concentrations in the flue gas may 

be considerably higher than for 

combustion emissions alone. In such 

cases, the span of the CO2 monitor may, 

if necessary, be set higher than the 

specified levels in the applicable 

regulations. If the CO2 span value is set 

higher than 20 percent CO2, the cylinder 

gas audits of the CO2 monitor under 

appendix F to part 60 of this chapter 

may be performed at 40 to 60 percent 

and 80 to 100 percent of span, in lieu 

of the prescribed calibration levels of 5 

to 8 percent CO2 and 10 to 14 percent 

CO2. 

(7) Hourly average data from the 

CEMS shall be validated in a manner 

consistent with one of the following: 

§§ 60.13(h)(2)(i) through (h)(2)(vi) of this 

chapter; § 75.10(d)(1) of this chapter; or 

the hourly data validation requirements 

of an applicable State CEM regulation. 

(d) Except as otherwise provided in 

§ 98.33 (b)(1)(vi) and (b)(1)(vii), when 

municipal solid waste (MSW) is either 

the primary fuel combusted in a unit or 

the only fuel with a biogenic component 

combusted in the unit, determine the 

biogenic portion of the CO2 emissions 

using ASTM D6866–08 Standard Test 

Methods for Determining the Biobased 

Content of Solid, Liquid, and Gaseous 

Samples Using Radiocarbon Analysis 

(incorporated by reference, see § 98.7) 

and ASTM D7459–08 Standard Practice 

for Collection of Integrated Samples for 

the Speciation of Biomass (Biogenic) 

and Fossil-Derived Carbon Dioxide 

Emitted from Stationary Emissions 

Sources (incorporated by reference, see 

§ 98.7). Perform the ASTM D7459–08 

sampling and the ASTM D6866–08 

analysis at least once in every calendar 

quarter in which MSW is combusted in 

the unit. Collect each gas sample during 

normal unit operating conditions for at 

least 24 total (not necessarily 

consecutive) hours, or longer if the 

facility deems it necessary to obtain a 

representative sample. Notwithstanding 

this requirement, if the types of fuels 

combusted and their relative 

proportions are consistent throughout 

the year, the minimum required 

sampling time may be reduced to 8 

hours if at least two 8-hour samples and 

one 24-hour sample are collected under 

normal operating conditions, and 

arithmetic average of the biogenic 

fraction of the flue gas from the 8-hour 

samples (expressed as a decimal) is 

within ± 5 percent of the biogenic 

fraction from the 24-hour test. There 

must be no overlapping of the 8-hour 

and 24-hour test periods. Document the 

results of the demonstration in the 

unit’s monitoring plan. If the types of 

fuels and their relative proportions are 

not consistent throughout the year, an 

optional sampling approach that 

facilities may wish to consider to obtain 

a more representative sample is to 

collect an integrated sample by 

extracting a small amount of flue gas 

(e.g., 1 to 5 cc) in each unit operating 

hour during the quarter. Separate the 

total annual CO2 emissions into the 

biogenic and non-biogenic fractions 

using the average proportion of biogenic 

emissions of all samples analyzed 

during the reporting year. Express the 

results as a decimal fraction (e.g., 0.30, 

if 30 percent of the CO2 is biogenic). 

When MSW is the primary fuel for 

multiple units at the facility, and the 

units are fed from a common fuel 

source, testing at only one of the units 

is sufficient. 

(e) For other units that combust 

combinations of biomass fuel(s) (or 

heterogeneous fuels that have a biomass 

component, e.g., tires) and fossil (or 

other non-biogenic) fuel(s), in any 

proportions, ASTM D6866–08 

(incorporated by reference, see § 98.7) 

and ASTM D7459–08 (incorporated by 

reference, see § 98.7) may be used to 

determine the biogenic portion of the 

CO2 emissions in every calendar quarter 

in which biomass and non-biogenic 

fuels are co-fired in the unit. Follow the 

procedures in paragraph (d) of this 

section. If the primary fuel for multiple 

units at the facility consists of tires, and 

the units are fed from a common fuel 

source, testing at only one of the units 

is sufficient. 

(f) The records required under 

§ 98.3(g)(2)(i) shall include an 

explanation of how the following 

parameters are determined from 

company records (or, if applicable, from 

the best available information): 

(1) Fuel consumption, when the Tier 

1 and Tier 2 Calculation Methodologies 

are used, including cases where 

§ 98.36(c)(4) applies. 

* * * * * 

(3) Fossil fuel consumption when 

§ 98.33(e)(2) applies to a unit that uses 

CEMS to quantify CO2 emissions and 

that combusts both fossil and biomass 

fuels. 

* * * * * 

(5) Quantity of steam generated by a 

unit when § 98.33(a)(2)(iii) applies. 

(6) Biogenic fuel consumption and 

high heating value, as applicable, under 

§§ 98.33(e)(5) and (e)(6). 

(7) Fuel usage for CH4 and N2O 

emissions calculations under 

§ 98.33(c)(4)(ii). 

(8) Mass of biomass combusted, for 

premixed fuels that contain biomass and 

fossil fuels under § 98.33(e)(1)(iii). 

■ 11. Section 98.35 is amended by 

revising paragraph (a) to read as follows: 

§ 98.35 Procedures for estimating missing 

data. 

* * * * * 

(a) For all units subject to the 

requirements of the Acid Rain Program, 

and all other stationary combustion 

units subject to the requirements of this 

part that monitor and report emissions 

and heat input data year-round in 


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Federal Register / Vol. 75, No. 242 / Friday, December 17, 2010 / Rules and Regulations 79151 

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. Removing and reserving paragraphs 

(c)(1)(ii) and (c)(1)(iii). 

■ g. Revising paragraphs (c)(1)(vi) and 

(c)(1)(vii). 

■ h. Redesignating paragraph (c)(1)(viii) 

as paragraph (c)(1)(x), and revising 

newly designated paragraph (c)(1)(x). 

■ i. Removing paragraph (c)(1)(ix). 

■ j. Adding new paragraphs (c)(1)(viii) 

and (c)(1)(ix). 

■ k. Revising paragraphs (c)(2) 

introductory text, (c)(2)(ii), (c)(2)(iii), 

and (c)(2)(v). 

■ l. Removing paragraph (c)(2)(viii). 

■ m. Redesignating paragraphs (c)(2)(vi) 

and (c)(2)(vii) as paragraphs (c)(2)(viii) 

and (c)(2)(ix), and revising newly 

designated paragraphs (c)(2)(viii) and 

(c)(2)(ix). 

■ n. Adding new paragraphs (c)(2)(vi) 

and (c)(2)(vii). 

■ o. Removing and reserving paragraph 

(c)(3)(ii). 

■ p. Revising paragraphs (c)(3) 

introductory text, (c)(3)(iii), and 

(c)(3)(vii). 

■ q. Removing paragraph (c)(3)(viii). 

■ r. Adding new paragraphs (c)(3)(viii), 

(c)(3)(ix), and (c)(4). 

■ s. Revising paragraph (d). 

■ t. Revising paragraphs (e)(1)(iii), 

(e)(2)(i), (e)(2)(ii)(C), (e)(2)(ii)(D), 

(e)(2)(iii), (e)(2)(iv)(A), and (e)(2)(iv)(C). 

■ u. Adding paragraphs (e)(2)(iv)(F) and 

(e)(2)(iv)(G). 

■ v. Revising paragraph (e)(2)(v)(C). 

■ w. Adding paragraph (e)(2)(v)(E). 

■ x. Revising paragraphs (e)(2)(vii)(A), 

(e)(2)(ix) introductory text, and (e)(2)(x) 

introductory text. 

■ y. Removing paragraphs (e)(2)(x)(B) 

and (e)(2)(x)(C). 

■ z. Redesignating paragraph (e)(2)(x)(D) 

as (e)(2)(x)(B), and revising newly 

designated paragraph (e)(2)(x)(B). 

■ aa. 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: 

(i) If the total annual CO2 mass 

emissions measured by the CEMS 

consists entirely of non-biogenic CO2

(i.e., CO2 from fossil fuel combustion 

plus, if applicable, CO2 from sorbent 

and/or process CO2), report the total 

annual CO2 mass emissions, expressed 

in metric tons. You are not required to 

report the combustion CO2 emissions by 

fuel type. 

(ii) Report the total annual CO2 mass 

emissions measured by the CEMS. If 

this total includes both biogenic and 

non-biogenic CO2, separately report the 

annual non-biogenic CO2 mass 

emissions and the annual CO2 mass 

emissions from biomass combustion, 

each expressed in metric tons. You are 

not required to report the combustion 

CO2 emissions by fuel type. 

(iii) An estimate of the heat input 

from each type of fuel listed in Table C– 

2 of this subpart that was combusted in 

the unit during the report year, and the 

annual CH4 and N2O emissions for each 

of these fuels, expressed in metric tons 

of each gas and in metric tons of CO2e. 

* * * * * 

(c) * * * 

(1) * * * 

(ii) [Reserved] 

(iii) [Reserved] 

* * * * * 

(vi) Annual CO2 mass emissions and 

annual CH4, and N2O mass emissions, 

aggregated for each type of fuel 

combusted in the group of units during 

the report year, expressed in metric tons 

of each gas and in metric tons of CO2e. 

If any of the units burn both fossil fuels 

and biomass, report also the annual CO2

emissions from combustion of all fossil 

fuels combined and annual CO2

emissions from combustion of all 

biomass fuels combined, expressed in 

metric tons. 

(vii) The methodology (i.e., tier) used 

to calculate the CO2 mass emissions for 

each type of fuel combusted in the units 

(i.e., Tier 1, Tier 2, or Tier 3). 

(viii) The methodology start date, for 

each fuel type. 

(ix) The methodology end date, for 

each fuel type. 

(x) The calculated CO2 mass 

emissions (if any) from sorbent 

expressed in metric tons. 

(2) Monitored common stack or duct 

configurations. When the flue gases 

from two or more stationary fuel 

combustion units at a facility are 

combined together in a common stack or 

duct before exiting to the atmosphere 

and if CEMS are used to continuously 

monitor CO2 mass emissions at the 

common stack or duct according to the 

Tier 4 Calculation Methodology, you 

may report the combined emissions 

from the units sharing the common 

stack or duct, in lieu of separately 

reporting the GHG emissions from the 

individual units. This monitoring and 

reporting alternative may also be used 

when process off-gases or a mixture of 

combustion products and process gases 

are combined together in a common 

stack or duct before exiting to the 

atmosphere. Whenever the common 

stack or duct monitoring option is 

applied, the following information shall 

be reported instead of the information in 

paragraph (b) of this section: 

* * * * * 

(ii) Number of units sharing the 

common stack or duct. Report ‘‘1’’ when 

the flue gas flowing through the 

common stack or duct includes 

combustion products and/or process offgases, and all of the effluent comes from 

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

petrochemical production unit, or 

smelter). 

(iii) Combined maximum rated heat 

input capacity of the units sharing the 

common stack or duct (mmBtu/hr). This 

data element is required only when all 

of the units sharing the common stack 

are stationary fuel combustion units. 

* * * * * 

(v) The methodology (tier) used to 

calculate the CO2 mass emissions, i.e., 

Tier 4. 

(vi) The methodology start date. 

(vii) The methodology end date. 

(viii) Total annual CO2 mass 

emissions measured by the CEMS, 

expressed in metric tons. If any of the 

units burn both fossil fuels and biomass, 

separately report the annual nonbiogenic 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 


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79152 Federal Register / Vol. 75, No. 242 / Friday, December 17, 2010 / Rules and Regulations 

this subpart that was combusted during 

the report year in the units sharing the 

common stack or duct during the report 

year, and, for each of these fuels, the 

annual CH4 and N2O mass emissions 

from the units sharing the common 

stack or duct, expressed in metric tons 

of each gas and in metric tons of CO2e. 

(3) Common pipe configurations. 

When two or more stationary 

combustion units at a facility combust 

the same type of liquid or gaseous fuel 

and the fuel is fed to the individual 

units through a common supply line or 

pipe, you may report the combined 

emissions from the units served by the 

common supply line, in lieu of 

separately reporting the GHG emissions 

from the individual units, provided that 

the total amount of fuel combusted by 

the units is accurately measured at the 

common pipe or supply line using a fuel 

flow meter, or, for natural gas, the 

amount of fuel combusted may be 

obtained from gas billing records. For 

Tier 3 applications, the flow meter shall 

be calibrated in accordance with 

§ 98.34(b). If a portion of the fuel 

measured (or obtained from gas billing 

records) at the main supply line is 

diverted to either: A flare; or another 

stationary fuel combustion unit (or 

units), including units that use a CO2

mass emissions calculation method in 

part 75 of this chapter; or a chemical or 

industrial process (where it is used as a 

raw material but not combusted), and 

the remainder of the fuel is distributed 

to a group of combustion units for 

which you elect to use the common pipe 

reporting option, you may use company 

records to subtract out the diverted 

portion of the fuel from the fuel 

measured (or obtained from gas billing 

records) at the main supply line prior to 

performing the GHG emissions 

calculations for the group of units using 

the common pipe option. If the diverted 

portion of the fuel is combusted, the 

GHG emissions from the diverted 

portion shall be accounted for in 

accordance with the applicable 

provisions of this part. When the 

common pipe option is selected, the 

applicable tier shall be used based on 

the maximum rated heat input capacity 

of the largest unit served by the 

common pipe configuration, except 

where the applicable tier is based on 

criteria other than unit size. For 

example, if the maximum rated heat 

input capacity of the largest unit is 

greater than 250 mmBtu/hr, Tier 3 will 

apply, unless the fuel transported 

through the common pipe is natural gas 

or distillate oil, in which case Tier 2 

may be used, in accordance with 

§ 98.33(b)(2)(ii). As a second example, 

in accordance with § 98.33(b)(1)(v), Tier 

1 may be used regardless of unit size 

when natural gas is transported through 

the common pipe, if the annual fuel 

consumption is obtained from gas 

billing records in units of therms. When 

the common pipe reporting option is 

selected, the following information shall 

be reported instead of the information in 

paragraph (b) of this section: 

* * * * * 

(iii) The highest maximum rated heat 

input capacity of any unit served by the 

common pipe (mmBtu/hr). 

* * * * * 

(vii) Annual CO2 mass emissions and 

annual CH4 and N2O emissions from 

each fuel type for the units served by 

the common pipe, expressed in metric 

tons of each gas and in metric tons of 

CO2e. 

(viii) Methodology start date 

(ix) Methodology end date 

(4) The following alternative reporting 

option applies to facilities at which a 

common liquid or gaseous fuel supply 

is shared between one or more large 

combustion units, such as boilers or 

combustion turbines (including units 

subject to subpart D of this part and 

other units subject to part 75 of this 

chapter) and small combustion sources, 

including, but not limited to, space 

heaters, hot water heaters, and lab 

burners. In this case, you may simplify 

reporting by attributing all of the GHG 

emissions from combustion of the 

shared fuel to the large combustion 

unit(s), provided that: 

(i) The total quantity of the fuel 

combusted during the report year in the 

units sharing the fuel supply is 

measured, either at the ‘‘gate’’ to the 

facility or at a point inside the facility, 

using a fuel flow meter, billing meter, or 

tank drop measurements (as applicable); 

(ii) On an annual basis, at least 95 

percent (by mass or volume) of the 

shared fuel is combusted in the large 

combustion unit(s), and the remainder 

is combusted in the small combustion 

sources. Company records may be used 

to determine the percentage distribution 

of the shared fuel to the large and small 

units; and 

(iii) The use of this reporting option 

is documented in the Monitoring Plan 

required under § 98.3(g)(5). Indicate in 

the Monitoring Plan which units share 

the common fuel supply and the 

method used to demonstrate that this 

alternative reporting option applies. For 

the small combustion sources, a 

description of the types of units and the 

approximate number of units is 

sufficient. 

(d) Units subject to part 75 of this 

chapter. 

(1) For stationary combustion units 

that are subject to subpart D of this part, 

you shall report the following unit-level 

information: 

(i) Unit or stack identification 

numbers. Use exact same unit, common 

stack, common pipe, or multiple stack 

identification numbers that represent 

the monitored locations (e.g., 1, 2, 

CS001, MS1A, CP001, etc.) that are 

reported under § 75.64 of this chapter. 

(ii) Annual CO2 emissions at each 

monitored location, expressed in both 

short tons and metric tons. Separate 

reporting of biogenic CO2 emissions 

under § 98.3(c)(4)(ii) and 

§ 98.3(c)(4)(iii)(A) is optional only for 

the 2010 reporting year, as provided in 

§ 98.3(c)(12). 

(iii) Annual CH4 and N2O emissions at 

each monitored location, for each fuel 

type listed in Table C–2 that was 

combusted during the year (except as 

otherwise provided in 

§ 98.33(c)(4)(ii)(B)), expressed in metric 

tons of CO2e. 

(iv) The total heat input from each 

fuel listed in Table C–2 that was 

combusted during the year (except as 

otherwise provided in 

§ 98.33(c)(4)(ii)(B)), expressed in 

mmBtu. 

(v) Identification of the Part 75 

methodology used to determine the CO2

mass emissions. 

(vi) Methodology start date. 

(vii) Methodology end date. 

(viii) Acid Rain Program indicator. 

(ix) Annual CO2 mass emissions from 

the combustion of biomass, expressed in 

metric tons of CO2e, except where the 

reporting provisions of §§ 98.3(c)(12)(i) 

through (c)(12)(iii) are implemented for 

the 2010 reporting year. 

(2) For units that use the alternative 

CO2 mass emissions calculation 

methods provided in § 98.33(a)(5), you 

shall report the following unit-level 

information: 

(i) Unit, stack, or pipe ID numbers. 

Use exact same unit, common stack, 

common pipe, or multiple stack 

identification numbers that represent 

the monitored locations (e.g., 1, 2, 

CS001, MS1A, CP001, etc.) that are 

reported under § 75.64 of this chapter. 

(ii) For units that use the alternative 

methods specified in § 98.33(a)(5)(i) and 

(ii) to monitor and report heat input 

data year-round according to appendix 

D to part 75 of this chapter or § 75.19 

of this chapter: 

(A) Each type of fuel combusted in the 

unit during the reporting year. 

(B) The methodology used to calculate 

the CO2 mass emissions for each fuel 

type. 

(C) Methodology start date. 

(D) Methodology end date. 


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Federal Register / Vol. 75, No. 242 / Friday, December 17, 2010 / Rules and Regulations 79153 

(E) A code or flag to indicate whether 

heat input is calculated according to 

appendix D to part 75 of this chapter or 

§ 75.19 of this chapter. 

(F) Annual CO2 emissions at each 

monitored location, across all fuel types, 

expressed in metric tons of CO2e. 

(G) Annual heat input from each type 

of fuel listed in Table C–2 of this 

subpart that was combusted during the 

reporting year, expressed in mmBtu. 

(H) Annual CH4 and N2O emissions at 

each monitored location, from each fuel 

type listed in Table C–2 of this subpart 

that was combusted during the reporting 

year (except as otherwise provided in 

§ 98.33(c)(4)(ii)(D)), expressed in metric 

tons CO2e. 

(I) Annual CO2 mass emissions from 

the combustion of biomass, expressed in 

metric tons CO2e, except where the 

reporting provisions of §§ 98.3(c)(12)(i) 

through (c)(12)(iii) are implemented for 

the 2010 reporting year. 

(iii) For units with continuous 

monitoring systems that use the 

alternative method for units with 

continuous monitoring systems in 

§ 98.33(a)(5)(iii) to monitor heat input 

year-round according to part 75 of this 

chapter: 

(A) Each type of fuel combusted 

during the reporting year. 

(B) Methodology used to calculate the 

CO2 mass emissions. 

(C) Methodology start date. 

(D) Methodology end date. 

(E) A code or flag to indicate that the 

heat input data is derived from CEMS 

measurements. 

(F) The total annual CO2 emissions at 

each monitored location, expressed in 

metric tons of CO2e. 

(G) Annual heat input from each type 

of fuel listed in Table C–2 of this 

subpart that was combusted during the 

reporting year, expressed in mmBtu. 

(H) Annual CH4 and N2O emissions at 

each monitored location, from each fuel 

type listed in Table C–2 of this subpart 

that was combusted during the reporting 

year (except as otherwise provided in 

§ 98.33(c)(4)(ii)(B)), expressed in metric 

tons CO2e. 

(I) Annual CO2 mass emissions from 

the combustion of biomass, expressed in 

metric tons CO2e, except where the 

reporting provisions of §§ 98.3(c)(12)(i) 

through (c)(12)(iii) are implemented for 

the 2010 reporting year. 

(e) * * * 

(1) * * * 

(iii) Are not in the Acid Rain Program, 

but are required to monitor and report 

CO2 mass emissions and heat input data 

year-round, in accordance with part 75 

of this chapter. 

(2) * * * 

(i) For the Tier 1 Calculation 

Methodology, report the total quantity 

of each type of fuel combusted in the 

unit or group of aggregated units (as 

applicable) during the reporting year, in 

short tons for solid fuels, gallons for 

liquid fuels and standard cubic feet for 

gaseous fuels, or, if applicable, therms 

or mmBtu for natural gas. 

(ii) * * * 

(C) The high heat values used in the 

CO2 emissions calculations for each 

type of fuel combusted during the 

reporting year, in mmBtu per short ton 

for solid fuels, mmBtu per gallon for 

liquid fuels, and mmBtu per scf for 

gaseous fuels. Report a HHV value for 

each calendar month in which HHV 

determination is required. If multiple 

values are obtained in a given month, 

report the arithmetic average value for 

the month. Indicate whether each 

reported HHV is a measured value or a 

substitute data value. 

(D) If Equation C–2c of this subpart is 

used to calculate CO2 mass emissions, 

report the total quantity (i.e., pounds) of 

steam produced from MSW or solid fuel 

combustion during each month of the 

reporting year, and the 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 content as a decimal fraction for 

solid fuels, kg C per gallon for liquid 

fuels, and kg C per kg of fuel for gaseous 

fuels. Express the gas molecular weights 

in units of kg per kg-mole. 

* * * * * 

(F) The annual average HHV, when 

measured HHV data, rather than a 

default HHV from Table C–1 of this 

subpart, are used to calculate CH4 and 

N2O emissions for a Tier 3 unit, in 

accordance with § 98.33(c)(1). 

(G) The value of the molar volume 

constant (MVC) used in Equation C–5 (if 

applicable). 

(v) * * * 

(C) The methods used to determine 

the carbon content and (if applicable) 

the molecular weight of each type of 

fuel combusted. 

* * * * * 

(E) The date on which each fuel 

sample was taken, except where fuel 

sampling data are received from the fuel 

supplier. In that case, keep records of 

the dates on which the results of the 

fuel analyses for carbon content and (if 

applicable) molecular weight are 

received. 

* * * * * 

(vii) * * * 

(A) Whether the CEMS certification 

and quality assurance procedures of part 

75 of this chapter, part 60 of this 

chapter, or an applicable State 

continuous monitoring program were 

used. 

* * * * * 

(ix) For units that combust both fossil 

fuel and biomass, when biogenic CO2 is 

determined according to § 98.33(e)(2), 

you shall report the following additional 

information, as applicable: 

* * * * * 

(x) When ASTM methods D7459–08 

(incorporated by reference, see § 98.7) 

and D6866–08 (incorporated by 

reference, see § 98.7) are used to 

determine the biogenic portion of the 

annual CO2 emissions from MSW 

combustion, as described in § 98.34(d), 

report: 

* * * * * 

(B) The annual biogenic CO2 mass 

emissions from MSW combustion, in 

metric tons. 

(xi) When ASTM methods D7459–08 

(incorporated by reference, see § 98.7) 

and D6866–08 (incorporated by 

reference, see § 98.7) are used in 

accordance with § 98.34(e) to determine 

the biogenic portion of the annual CO2

emissions from a unit that co-fires 

biogenic fuels (or partly-biogenic fuels, 

including tires if you are electing to 

report biogenic CO2 emissions from tire 

combustion) and non-biogenic fuels, 

you shall report the results of each 

quarterly sample analysis, expressed as 

a decimal fraction (e.g., if the biogenic 

fraction of the CO2 emissions is 30 

percent, report 0.30). 

* * * * * 

■ 13. Table C–1 to Subpart C is 

amended by: 


srobinson on DSKHWCL6B1PROD with RULES2
79154 Federal Register / Vol. 75, No. 242 / Friday, December 17, 2010 / Rules and Regulations 

■ a. Revising the heading. 

■ b. Removing the entry for ‘‘Pipeline 

(Weighted U.S. Average)’’ and adding an 

entry for ‘‘(Weighted U.S. Average)’’ in 

its place. 

■ c. Removing the entry for ‘‘Still Gas.’’ 

■ d. Adding an entry for ‘‘Used Oil’’, 

following the entry for ‘‘Residual Fuel 

Oil No. 6.’’ 

■ e. Revising the entry for ‘‘Ethane’’. 

■ f. Adding an entry for ‘‘Ethanol’’, 

following the entry for ‘‘Ethane.’’ 

■ g. Revising the phrase ‘‘Fossil fuelderived fuels (solid)’’ to read ‘‘Other 

fuels-solid.’’ 

■ h. Revising the entry for ‘‘Municipal 

Solid Waste.’’ 

■ i. Adding entries for ‘‘Plastics’’ and 

‘‘Petroleum Coke’’, following the entry 

for ‘‘Tires.’’ 

■ j. Revising the phrase ‘‘Fossil fuelderived fuels (gaseous)’’ to read ‘‘Other 

fuels—gaseous.’’ 

■ k. Adding entries for ‘‘Propane Gas’’ 

and ‘‘Fuel Gas,’’ following the entry for 

‘‘Coke Oven Gas.’’ 

■ l. Amending the entry for ‘‘Biomass 

fuels—liquid’’ by centering ‘‘Biomass 

fuels—liquid.’’ 

■ m. Revising the entries for ‘‘Ethanol’’ 

and ‘‘Biodiesel’’ that follow the entry for 

‘‘Biomass fuels—liquid.’’ 

■ n. Revising footnote ‘‘1.’’ 

■ o. Adding footnote ‘‘2.’’ 

TABLE C–1 TO SUBPART C—DEFAULT CO2 EMISSION FACTORS AND HIGH HEAT VALUES FOR VARIOUS TYPES OF FUEL

Fuel type Default high 

heat value 

Default CO2

emission factor 

*******

(Weighted U.S. Average) ................................................................................................................................... 1.028 × 10¥3 53.02 

* * * * * * * 

Used Oil ............................................................................................................................................................. 0.135 74.00 

* * * * * * * 

Ethane ................................................................................................................................................................ 0.069 62.64 

Ethanol ............................................................................................................................................................... 0.084 68.44 

* * * * * * * 

Other fuels (solid) .............................................................................................................................................. mmBtu/short ton kg CO2/mmBtu 

Municipal Solid Waste ....................................................................................................................................... 9.95 1 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 × 10¥3 61.46 

Fuel Gas 2 .......................................................................................................................................................... 1.388 × 10¥3 59.00 

* * * * * * * 

Ethanol ............................................................................................................................................................... 0.084 68.44 

Biodiesel ............................................................................................................................................................. 0.128 73.84 

* * * * * * * 

1 Use of this default HHV is allowed only for: (a) Units that combust MSW, do not generate steam, and are allowed to use Tier 1; (b) units that 

derive no more than 10 percent of their annual heat input from MSW and/or tires; and (c) small batch incinerators that combust no more than 

1,000 tons of MSW per year. 2 Reporters subject to subpart X of this part that are complying with § 98.243(d) or subpart Y of this part may only use the default HHV and the 

default CO2 emission factor for fuel gas combustion under the conditions prescribed in § 98.243(d)(2)(i) and (d)(2)(ii) and § 98.252(a)(1) and 

(a)(2), respectively. Otherwise, reporters subject to subpart X or subpart Y shall use either Tier 3 (Equation C–5) or Tier 4. 

■ 14. The first Table C–2 to Subpart C 

is removed, and the second Table C–2 

to Subpart C is revised to read as 

follows: 

TABLE C–2 TO SUBPART C—DEFAULT CH4 AND N2O EMISSION FACTORS FOR VARIOUS TYPES OF FUEL

Fuel type 

Default CH4

emission factor 

(kg CH4/mmBtu) 

Default N2O 

emission factor 

(kg N2O/mmBtu) 

Coal and Coke (All fuel types in Table C–1) .................................................................................................... 1.1 × 10¥02 1.6 × 10¥03

Natural Gas ........................................................................................................................................................ 1.0 × 10¥03 1.0 × 10¥04

Petroleum (All fuel types in Table C–1) ............................................................................................................ 3.0 × 10¥03 6.0 × 10¥04

Municipal Solid Waste ....................................................................................................................................... 3.2 × 10¥02 4.2 × 10¥03

Tires ................................................................................................................................................................... 3.2 × 10¥02 4.2 × 10¥03

Blast Furnace Gas ............................................................................................................................................. 2.2 × 10¥05 1.0 × 10¥04

Coke Oven Gas ................................................................................................................................................. 4.8 × 10¥04 1.0 × 10¥04

Biomass Fuels—Solid (All fuel types in Table C–1) ......................................................................................... 3.2 × 10¥02 4.2 × 10¥03

Biogas ................................................................................................................................................................ 3.2 × 10¥03 6.3 × 10¥04


srobinson on DSKHWCL6B1PROD with RULES2
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TABLE C–2 TO SUBPART C—DEFAULT CH4 AND N2O EMISSION FACTORS FOR VARIOUS TYPES OF FUEL—Continued 

Fuel type 

Default CH4

emission factor 

(kg CH4/mmBtu) 

Default N2O 

emission factor 

(kg N2O/mmBtu) 

Biomass Fuels—Liquid (All fuel types in Table C–1) ........................................................................................ 1.1 × 10¥03 1.1 × 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 1g 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 yearround according to 40 CFR part 75. 

* * * * * 

■ 16. Section 98.43 is revised to read as 

follows: 

§ 98.43 Calculating GHG emissions. 

(a) Except as provided in paragraph 

(b) of this section, continue to monitor 

and report CO2 mass emissions as 

required under § 75.13 or section 2.3 of 

appendix G to 40 CFR part 75, and 

§ 75.64. Calculate CO2, CH4, and N2O 

emissions as follows: 

(1) Convert the cumulative annual 

CO2 mass emissions reported in the 

fourth quarter electronic data report 

required under § 75.64 from units of 

short tons to metric tons. To convert 

tons to metric tons, divide by 1.1023. 

(2) Calculate and report annual CH4

and N2O mass emissions under this 

subpart by following the applicable 

method specified in § 98.33(c). 

(b) Calculate and report biogenic CO2

emissions under this subpart by 

following the applicable methods 

specified in § 98.33(e). The CO2

emissions (excluding biogenic CO2) for 

units subject to this subpart that are 

reported under §§ 98.3(c)(4)(i) and 

(c)(4)(iii)(B) shall be calculated by 

subtracting the biogenic CO2 mass 

emissions calculated according to 

§ 98.33(e) from the cumulative annual 

CO2 mass emissions from paragraph 

(a)(1) of this section. Separate 

calculation and reporting of biogenic 

CO2 emissions is optional only for the 

2010 reporting year pursuant to 

§ 98.3(c)(12) and required every year 

thereafter. 

■ 17. Section 98.46 is revised to read as 

follows: 

§ 98.46 Data reporting requirements. 

The annual report shall comply with 

the data reporting requirements 

specified in § 98.36(d)(1). 

■ 18. Section 98.47 is revised to read as 

follows: 

§ 98.47 Records that must be retained. 

You shall comply with the 

recordkeeping requirements of 

§§ 98.3(g) and 98.37. Records retained 

under § 75.57(h) of this chapter for 

missing data events satisfy the 

recordkeeping requirements of 

§ 98.3(g)(4) for those same events. 

Subpart F—[Amended] 

■ 19. Section 98.62 is amended by 

revising paragraphs (a) and (b) to read 

as follows: 

§ 98.62 GHGs to report. 

* * * * * 

(a) Perfluoromethane (CF4), and 

perfluoroethane (C2F6) emissions from 

anode effects in all prebake and 

S<derberg electrolysis cells. 

(b) CO2 emissions from anode 

consumption during electrolysis in all 

prebake and S<derberg electrolysis cells. 

* * * * * 

■ 20. Section 98.63 is amended by: 

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

sentence and the definitions of ‘‘EPFC,’’ 

and ‘‘Em’’ in Equation F–1. 

■ b. Revising the only sentence of 

paragraph (b). 

■ c. Revising paragraph (c). 

§ 98.63 Calculating GHG emissions. 

(a) The annual value of each PFC 

compound (CF4, C2F6) shall be 

estimated from the sum of monthly 

values using Equation F–1 of this 

section: 

* * * * * 

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 S<derberg electrolysis cell. 

* * * * * 

(c) You must calculate and report the 

annual process CO2 emissions from 

anode consumption during electrolysis 

and anode baking of prebake cells using 

either the procedures in paragraph (d) of 

this section, the procedures in 

paragraphs (e) and (f) of this section, or 

the procedures in paragraph (g) of this 

section. 

* * * * * 

■ 21. Section 98.64 is amended by 

revising the first sentence of paragraph 

(a); and by revising paragraph (b) to read 

as follows: 

§ 98.64 Monitoring and QA/QC 

requirements. 

(a) Effective December 31, 2010 for 

smelters with no prior measurement or 

effective December 31, 2012, for 

facilities with historic measurements, 

the smelter-specific slope coefficients, 

overvoltage emission factors, and weight 

fractions used in Equations F–2, F–3, 

and F–4 of this subpart must be 

measured in accordance with the 

recommendations of the EPA/IAI 

Protocol for Measurement of 

Tetrafluoromethane (CF4) and 

Hexafluoroethane (C2F6) Emissions from 

Primary Aluminum Production (2008) 

(incorporated by reference, see § 98.7), 

except the minimum frequency of 

measurement shall be every 10 years 

unless a change occurs in the control 

algorithm that affects the mix of types 

of anode effects or the nature of the 

anode effect termination routine. * * * 

(b) The minimum frequency of the 

measurement and analysis is annually 

except as follows: 

(1) Monthly for anode effect minutes 

per cell day (or anode effect overvoltage 

and current efficiency). 

(2) Monthly for aluminum 

production. 

(3) Smelter-specific slope coefficients, 

overvoltage emission factors, and weight 

fractions according to paragraph (a) of 

this section. 

* * * * * 


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■ 22. Section 98.65 is amended by 

revising the only sentence of paragraph 

(a) to read as follows: 

§ 98.65 Procedures for estimating missing 

data. 

* * * * * 

(a) Where anode or paste 

consumption data are missing, CO2

emissions can be estimated from 

aluminum production per Equation F–8 

of this section. 

* * * * * 

■ 23. Section 98.66 is amended by 

revising paragraph (c)(1) to read as 

follows: 

§ 98.66 Data reporting requirements. 

* * * * * 

(c) * * * 

(1) Perfluoromethane emissions and 

perfluoroethane emissions from anode 

effects in all prebake and all S<derberg 

electrolysis cells combined. 

* * * * * 

■ 24. Table F–1 to Subpart F of Part 98 

is revised to read as follows: 

TABLE F–1 TO SUBPART F OF PART 98—SLOPE AND OVERVOLTAGE COEFFICIENTS FOR THE CALCULATION OF PFC 

EMISSIONS FROM ALUMINUM PRODUCTION

Technology 

CF4 slope coefficient 

[(kg CF4/metric ton Al)/ 

(AE–Mins/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 S<derberg (VSS) ................................ 0.092 NA 0.053 

Horizontal Stud S<derberg (HSS) ........................... 0.099 NA 0.085 

■ 25. Table F–2 to Subpart F of Part 98 

is amended by removing the entry for 

‘‘CO2 Emissions from Pitch Volatiles 

Combustion (VSS and HSS)’’ and adding 

a new entry in its place to read as 

follows: 

TABLE F–2 TO SUBPART F OF PART 98—DEFAULT DATA SOURCES FOR PARAMETERS USED FOR CO2 EMISSIONS

Parameter Data source 

CO2 Emissions From Prebake Cells (CWPB and SWPB) 

* * * * * * * 

CO2 Emissions From Pitch Volatiles Combustion (CWPB and SWPB) 

* * * * * * * 

Subpart G—[Amended] 

■ 26. Section 98.72 is amended by 

revising paragraphs (a) and (b) to read 

as follows: 

§ 98.72 GHGs to report. 

* * * * * 

(a) CO2 process emissions from steam 

reforming of a hydrocarbon or the 

gasification of solid and liquid raw 

material, reported for each ammonia 

manufacturing process unit following 

the requirements of this subpart (CO2

process emissions reported under this 

subpart may include CO2 that is later 

consumed on site for urea production, 

and therefore is not released to the 

ambient air from the ammonia 

manufacturing process unit). 

(b) CO2, CH4, and N2O emissions from 

each stationary fuel combustion unit. 

You must report these emissions under 

subpart C of this part (General 

Stationary Fuel Combustion Sources), 

by following the requirements of 

subpart C, except that for ammonia 

manufacturing processes subpart C does 

not apply to any CO2 resulting from 

combustion of the waste recycle stream 

(commonly referred to as the purge gas 

stream). 

* * * * * 

■ 27. Section 98.73 is amended by: 

■ a. Revising paragraph (b) introductory 

text. 

■ b. Revising the definition of ‘‘CO2,G’’ in 

Equation G–1 of paragraph (b)(1). 

■ c. Revising the definition of ‘‘CO2,L’’ in 

Equation G–2 of paragraph (b)(2). 

■ 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) * * * 

CO2 = Annual combined CO2 emissions from 

all ammonia processing units (metric 

tons) (CO2 process emissions reported 

under this subpart may include CO2 that 

is later consumed on site for urea 

production, and therefore is not released 

to the ambient air from the ammonia 

manufacturing process unit(s)). 

* * * * * 

■ 28. Section 98.74 is amended by 

revising paragraph (d) to read as set 

forth below and by removing and 

reserving paragraph (f): 

§ 98.74 Monitoring and QA/QC 

requirements. 

* * * * * 

(d) Calibrate all oil and gas flow 

meters that are used to measure liquid 

and gaseous feedstock volumes and flow 

rates (except for gas billing meters) 

according to the monitoring and QA/QC 


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requirements for the Tier 3 methodology 

in § 98.34(b)(1). Perform oil tank drop 

measurements (if used to quantify 

feedstock volumes) according to 

§ 98.34(b)(2). 

* * * * * 

■ 29. Section 98.75 is amended by 

revising the first sentence of paragraph 

(a); and by revising paragraph (b) to read 

as follows: 

§ 98.75 Procedures for estimating missing 

data. 

* * * * * 

(a) For missing data on monthly 

carbon contents of feedstock, the 

substitute data value shall be the 

arithmetic average of the quality-assured 

values of that carbon content in the 

month preceding and the month 

immediately following the missing data 

incident. * * * 

(b) For missing feedstock supply rates 

used to determine monthly feedstock 

consumption, you must determine the 

best available estimate(s) of the 

parameter(s), based on all available 

process data. 

■ 30. Section 98.76 is amended by: 

■ a. Revising paragraphs (a) 

introductory text and (b)(6). 

■ b. Removing paragraphs (b)(12) 

through (b)(15). 

■ c. Redesignating paragraph (b)(16) as 

paragraph (b)(12). 

■ d. Adding paragraph (b)(13). 

■ e. Removing paragraphs (b)(17) and 

(c). 

§ 98.76 Data reporting requirements. 

* * * * * 

(a) If a CEMS is used to measure CO2

emissions, then you must report the 

relevant information required under 

§ 98.36 for the Tier 4 Calculation 

Methodology and the following 

information in this paragraph (a): 

* * * * * 

(b) * * * 

(6) Sampling analysis results of 

carbon content of feedstock as 

determined for QA/QC of supplier data 

under § 98.74(e). 

* * * * * 

(13) CO2 from the steam reforming of 

a hydrocarbon or the gasification of 

solid and liquid raw material at the 

ammonia manufacturing process unit 

used to produce urea and the method 

used to determine the CO2 consumed in 

urea production. 

Subpart P—[Amended] 

■ 31. Section 98.163 is amended by 

revising the definitions of ‘‘CCn’’ and 

‘‘MW’’ in Equation P–1 of paragraph 

(b)(1) to read as follows: 

§ 98.163 Calculating GHG emissions. 

* * * * * 

(b) * * * 

(1) * * * 

CCn = Average carbon content of the gaseous 

fuel and feedstock, from the results of 

one or more analyses for month n (kg 

carbon per kg of fuel and feedstock). If 

measurements are taken more frequently 

than monthly, use the arithmetic average 

of measurement values within the month 

to calculate a monthly average. 

MWn = Average molecular weight of the 

gaseous fuel and feedstock from the 

results of one or more analyses for month 

n (kg/kg-mole). 

* * * * * 

■ 32. Section 98.164 is amended by 

revising paragraphs (b)(1), (b)(2), and 

(b)(5) introductory text to read as 

follows: 

§ 98.164 Monitoring and QA/QC 

requirements. 

* * * * * 

(b) * * * 

(1) Calibrate all oil and gas flow 

meters that are used to measure liquid 

and gaseous feedstock volumes (except 

for gas billing meters) according to the 

monitoring and QA/QC requirements for 

the Tier 3 methodology in § 98.34(b)(1). 

Perform oil tank drop measurements (if 

used to quantify liquid fuel or feedstock 

consumption) according to § 98.34(b)(2). 

Calibrate all solids weighing equipment 

according to the procedures in § 98.3(i). 

(2) Determine the carbon content and 

the molecular weight annually of 

standard gaseous hydrocarbon fuels and 

feedstocks having consistent 

composition (e.g., natural gas). For other 

gaseous fuels and feedstocks (e.g., 

biogas, refinery gas, or process gas), 

sample and analyze no less frequently 

than weekly to determine the carbon 

content and molecular weight of the fuel 

and feedstock. 

* * * * * 

(5) You must use the following 

applicable methods to determine the 

carbon content for all fuels and 

feedstocks, and molecular weight of 

gaseous fuels and feedstocks. 

Alternatively, you may use the results of 

continuous chromatographic analysis of 

the fuel and feedstock, provided that the 

gas chromatograph (GC) is operated, 

maintained, and calibrated according to 

the manufacturer’s instructions; and the 

methods used for operation, 

maintenance, and calibration of the GC 

are documented in the written 

monitoring plan for the unit under 

§ 98.3(g)(5). 

* * * * * 

Subpart V—[Amended] 

■ 33. Section 98.226 is amended by 

removing and reserving paragraph (o). 

Subpart X—[Amended] 

■ 34. Section 98.240 is amended by 

revising paragraph (a); and by adding 

paragraph (g) to read as follows: 

§ 98.240 Definition of the source category. 

(a) The petrochemical production 

source category consists of all processes 

that produce acrylonitrile, carbon black, 

ethylene, ethylene dichloride, ethylene 

oxide, or methanol, except as specified 

in paragraphs (b) through (g) of this 

section. The source category includes 

processes that produce the 

petrochemical as an intermediate in the 

on-site production of other chemicals as 

well as processes that produce the 

petrochemical as an end product for sale 

or shipment off site. 

* * * * * 

(g) A process that solely distills or 

recycles waste solvent that contains a 

petrochemical is not part of the 

petrochemical production source 

category. 

■ 35. Section 98.242 is amended by 

revising paragraph (a)(1) and paragraph 

(b) introductory text to read as follows: 

§ 98.242 GHGs to report. 

* * * * * 

(a) * * * 

(1) If you comply with § 98.243(b) or 

(d), report under this subpart the 

calculated CO2, CH4, and N2O emissions 

for each stationary combustion source 

and flare that burns any amount of 

petrochemical process off-gas. If you 

comply with § 98.243(b), also report 

under this subpart the measured CO2

emissions from process vents routed to 

stacks that are not associated with 

stationary combustion units. 

* * * * * 

(b) CO2, CH4, and N2O combustion 

emissions from stationary combustion 

units. 

* * * * * 

■ 36. Section 98.243 is amended by: 

■ a. Revising the second sentence of 

paragraph (b). 

■ b. Revising paragraph (c)(3). 

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

Equation X–1 in paragraph (c)(5)(i). 

■ d. Revising paragraph (d). 

§ 98.243 Calculating GHG emissions. 

* * * * * 

(b) * * * For each stack (except flare 

stacks) that includes emissions from 

combustion of petrochemical process 

off-gas, calculate CH4 and N20 emissions 

in accordance with subpart C of this 


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part (use the Tier 3 methodology, 

emission factors for ‘‘Petroleum’’ in 

Table C–2 of subpart C of this part, and 

either the default high heat value for 

fuel gas in Table C–1 of subpart C of this 

part or a calculated HHV, as allowed in 

Equation C–8 of subpart C of this 

part). * * * 

(c) * * * 

(3) Collect a sample of each feedstock 

and product at least once per month and 

determine the carbon content of each 

sample according to the procedures of 

§ 98.244(b)(4). If multiple valid carbon 

content measurements are made during 

the monthly measurement period, 

average them arithmetically. However, if 

a particular liquid or solid feedstock is 

delivered in lots, and if multiple 

deliveries of the same feedstock are 

received from the same supply source in 

a given calendar month, only one 

representative sample is required. 

Alternatively, you may use the results of 

analyses conducted by a fuel or 

feedstock supplier, provided the 

sampling and analysis is conducted at 

least once per month using any of the 

procedures specified in § 98.244(b)(4). 

* * * * * 

(5) * * * 

(i) * * * 

MVC = Molar volume conversion factor 

(849.5 scf per kg-mole at 68 °F and 14.7 

pounds per square inch absolute or 836.6 

scf/kg-mole at 60 °F and 14.7 pounds per 

square inch absolute). 

* * * * * 

(d) Optional combustion methodology 

for ethylene production processes. For 

each ethylene production process, 

calculate GHG emissions from 

combustion units that burn fuel that 

contains any off-gas from the ethylene 

process as specified in paragraphs (d)(1) 

through (d)(5) of this section. 

(1) Except as specified in paragraphs 

(d)(2) and (d)(5) of this section, calculate 

CO2 emissions using the Tier 3 or Tier 

4 methodology in subpart C of this part. 

(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 offgas streams that meet either of the 

conditions in paragraphs (d)(2)(i) or 

(d)(2)(ii) of this section (for any default 

values in the calculation, use the 

defaults for fuel gas in Table C–1 of 

subpart C of this part). Follow the 

otherwise applicable procedures in 

subpart C to calculate emissions from 

combustion of all other fuels in the 

combustion unit. 

(i) The annual average flow rate of 

fuel gas (that contains ethylene process 

off-gas) in the fuel gas line to the 

combustion unit, prior to any split to 

individual burners or ports, does not 

exceed 345 standard cubic feet per 

minute at 60 °F and 14.7 pounds per 

square inch absolute, and a flow meter 

is not installed at any point in the line 

supplying fuel gas or an upstream 

common pipe. Calculate the annual 

average flow rate using company 

records assuming total flow is evenly 

distributed over 525,600 minutes per 

year. 

(ii) The combustion unit has a 

maximum rated heat input capacity of 

less than 30 mmBtu/hr, and a flow 

meter is not installed at any point in the 

line supplying fuel gas (that contains 

ethylene process off-gas) or an upstream 

common pipe. 

(3) Except as specified in paragraph 

(d)(5) of this section, calculate CH4 and 

N2O emissions using the applicable 

procedures in § 98.33(c) for the same 

tier methodology that you used for 

calculating CO2 emissions. 

(i) For all gaseous fuels that contain 

ethylene process off-gas, use the 

emission factors for ‘‘Petroleum’’ in 

Table C–2 of subpart C of this part 

(General Stationary Fuel Combustion 

Sources). 

(ii) For Tier 3, use either the default 

high heat value for fuel gas in Table C– 

1 of subpart C of this part or a calculated 

HHV, as allowed in Equation C–8 of 

subpart C of this part. 

(4) You are not required to use the 

same Tier for each stationary 

combustion unit that burns ethylene 

process off-gas. 

(5) For each flare, calculate CO2, CH4, 

and N2O emissions using the 

methodology specified in 

§§ 98.253(b)(1) through (b)(3). 

■ 37. Section 98.244 is amended by 

revising paragraphs (b)(1) through (b)(3), 

(b)(4) introductory text, and (b)(4)(viii); 

and by adding paragraphs (b)(4)(xi) 

through (b)(4)(xv) to read as follows: 

§ 98.244 Monitoring and QA/QC 

requirements. 

* * * * * 

(b) * * * 

(1) Operate, maintain, and calibrate 

belt scales or other weighing devices as 

described in Specifications, Tolerances, 

and Other Technical Requirements for 

Weighing and Measuring Devices NIST 

Handbook 44 (2009) (incorporated by 

reference, see § 98.7), or follow 

procedures specified by the 

measurement device manufacturer. You 

must recalibrate each weighing device 

according to one of the following 

frequencies. You may recalibrate either 

at the minimum frequency specified by 

the manufacturer or biennially (i.e., 

once every two years). 

(2) Operate and maintain all flow 

meters used for gas and liquid 

feedstocks and products according to 

the manufacturer’s recommended 

procedures. You must calibrate each of 

these flow meters as specified in 

paragraphs (b)(2)(i) and (b)(2)(ii) of this 

section: 

(i) You may use either the calibration 

methods specified by the flow meter 

manufacturer or an industry consensus 

standard method. Each flow meter must 

meet the applicable accuracy 

specification in § 98.3(i), except as 

otherwise specified in §§ 98.3(i)(4) 

through (i)(6). 

(ii) You must recalibrate each flow 

meter according to one of the following 

frequencies. You may recalibrate at the 

minimum frequency specified by the 

manufacturer, biennially (every two 

years), or at the interval specified by the 

industry consensus standard practice 

used. 

(3) You must perform tank level 

measurements (if used to determine 

feedstock or product flows) according to 

one of the following methods. You may 

use any standard method published by 

a consensus-based standards 

organization or you may use an industry 

standard practice. Consensus-based 

standards organizations include, but are 

not limited to, the following: ASTM 

International (100 Barr Harbor Drive, 

P.O. Box CB700, West Conshohocken, 

Pennsylvania 19428–B2959, (800) 262– 

1373, http://www.astm.org), the 

American National Standards Institute 

(ANSI, 1819 L Street, NW., 6th Floor, 

Washington, DC 20036, (202) 293–8020, 

http://www.ansi.org), the American Gas 

Association (AGA, 400 North Capitol 

Street, NW., 4th Floor, Washington, DC 

20001, (202) 824–7000, http:// 

www.aga.org), the American Society of 

Mechanical Engineers (ASME, Three 

Park Avenue, New York, NY 10016– 

5990, (800) 843–2763, http:// 

www.asme.org), the American 

Petroleum Institute (API, 1220 L Street, 

NW., Washington, DC 20005–4070, 

(202) 682–8000, http://www.api.org,) 

and the North American Energy 

Standards Board (NAESB, 801 Travis 

Street, Suite 1675, Houston, TX 77002, 

(713) 356–0060, http://www.api.org). 

(4) Beginning January 1, 2010, use any 

applicable methods specified in 

paragraphs (b)(4)(i) through (b)(4)(xiv) of 

this section to determine the carbon 

content or composition of feedstocks 

and products and the average molecular 

weight of gaseous feedstocks and 

products. Calibrate instruments in 

accordance with paragraphs (b)(4)(i) 

through (b)(4)(xvi), as applicable. For 

coal used as a feedstock, the samples for 

carbon content determinations shall be 


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taken at a location that is representative 

of the coal feedstock used during the 

corresponding monthly period. For 

carbon black products, samples shall be 

taken of each grade or type of product 

produced during the monthly period. 

Samples of coal feedstock or carbon 

black product for carbon content 

determinations may be either grab 

samples collected and analyzed 

monthly or a composite of samples 

collected more frequently and analyzed 

monthly. Analyses conducted in 

accordance with methods specified in 

paragraphs (b)(4)(i) through (b)(4)(xv) of 

this section may be performed by the 

owner or operator, by an independent 

laboratory, or by the supplier of a 

feedstock. 

* * * * * 

(viii) Method 8015C, Method 8021B, 

Method 8031, or Method 9060A (all 

incorporated by reference, see § 98.7). 

* * * * * 

(xi) ASTM D2593–93 (Reapproved 

2009) Standard Test Method for 

Butadiene Purity and Hydrocarbon 

Impurities by Gas Chromatography 

(incorporated by reference, see § 98.7). 

(xii) ASTM D7633–10 Standard Test 

Method for Carbon Black—Carbon 

Content (incorporated by reference, see 

§ 98.7). 

(xiii) The results of chromatographic 

analysis of a feedstock or product, 

provided that the gas chromatograph is 

operated, maintained, and calibrated 

according to the manufacturer’s 

instructions. 

(xiv) The carbon content results of 

mass spectrometer analysis of a 

feedstock or product, provided that the 

mass spectrometer is operated, 

maintained, and calibrated according to 

the manufacturer’s instructions. 

(xv) Beginning on January 1, 2010, the 

methods specified in paragraphs 

(b)(4)(xv)(A) and (B) of this section may 

be used as alternatives for the methods 

specified in paragraphs (b)(4)(i) through 

(b)(4)(xiv) of this section. 

(A) An industry standard practice for 

carbon black feedstock oils and carbon 

black products. 

(B) Modifications of existing 

analytical methods or other methods 

that are applicable to your process 

provided that the methods listed in 

paragraphs (b)(4)(i) through (b)(4)(xiv) of 

this section are not appropriate because 

the relevant compounds cannot be 

detected, the quality control 

requirements are not technically 

feasible, or use of the method would be 

unsafe. 

■ 38. Section 98.246 is amended by: 

■ a. Revising paragraphs (a) 

introductory text and (a)(4). 

■ b. Removing and reserving paragraph 

(a)(7). 

■ c. Revising paragraph (a)(10). 

■ d. Adding paragraph (a)(11). 

■ e. Revising paragraphs (b) 

introductory text, and (b)(1) through 

(b)(5). 

■ f. Revising paragraph (c). 

§ 98.246 Data reporting requirements. 

* * * * * 

(a) If you use the mass balance 

methodology in § 98.243(c), you must 

report the information specified in 

paragraphs (a)(1) through (a)(11) of this 

section for each type of petrochemical 

produced, reported by process unit. 

* * * * * 

(4) Each of the monthly volume, mass, 

and carbon content values used in 

Equations X–1 through X–3 of this 

subpart (i.e., the directly measured 

values, substitute values, or the 

calculated values based on other 

measured data such as tank levels or gas 

composition) and the molecular weights 

for gaseous feedstocks and products 

used in Equation X–1 of this subpart, 

and the temperature (in °F) at which the 

gaseous feedstock and product volumes 

used in Equation X–1 of this subpart 

were determined. Indicate whether you 

used the alternative to sampling and 

analysis specified in § 98.243(c)(4). 

* * * * * 

(10) You may elect to report the flow 

and carbon content of wastewater, and 

you may elect to report the annual mass 

of carbon released in fugitive emissions 

and in process vents that are not 

controlled with a combustion device. 

These values may be estimated based on 

engineering analyses. These values are 

not to be used in the mass balance 

calculation. 

(11) If you determine carbon content 

or composition of a feedstock or product 

using a method under 

§ 98.244(b)(4)(xv)(B), report the 

information listed in paragraphs 

(a)(11)(i) through (a)(11)(iv) of this 

section. Include the information in 

paragraph (a)(11)(i) of this section in 

each annual report. Include the 

information in paragraphs (a)(11)(ii) and 

(a)(11)(iii) of this section only in the 

first applicable annual report, and 

provide any changes to this information 

in subsequent annual reports. 

(i) Name or title of the analytical 

method. 

(ii) A copy of the method. If the 

method is a modification of a method 

listed in §§ 98.244(b)(4)(i) through (xiv), 

you may provide a copy of only the 

sections that differ from the listed 

method. 

(iii) An explanation of why an 

alternative to the methods listed in 

§§ 98.244(b)(4)(i) through (xii) is 

needed. 

(b) If you measure emissions in 

accordance with § 98.243(b), then you 

must report the information listed in 

paragraphs (b)(1) through (b)(8) of this 

section. 

(1) The petrochemical process unit ID 

or other appropriate descriptor, and the 

type of petrochemical produced. 

(2) For CEMS used on stacks for 

stationary combustion units, report the 

relevant information required under 

§ 98.36 for the Tier 4 calculation 

methodology. Section 98.36(b)(9)(iii) 

does not apply for the purposes of this 

subpart. 

(3) For CEMS used on stacks that are 

not used for stationary combustion 

units, report the information required 

under § 98.36(e)(2)(vi). 

(4) The CO2 emissions from each stack 

and the combined CO2 emissions from 

all stacks (except flare stacks) that 

handle process vent emissions and 

emissions from stationary combustion 

units that burn process off-gas for the 

petrochemical process unit. For each 

stationary combustion unit (or group of 

combustion units monitored with a 

single CO2 CEMS) that burns 

petrochemical process off-gas, provide 

an estimate based on engineering 

judgment of the fraction of the total 

emissions that is attributable to 

combustion of off-gas from the 

petrochemical process unit. 

(5) For stationary combustion units 

that burn process off-gas from the 

petrochemical process unit, report the 

information related to CH4 and N2O 

emissions as specified in paragraphs 

(b)(5)(i) through (b)(5)(iv) of this section. 

(i) The CH4 and N2O emissions from 

each stack that is monitored with a CO2

CEMS, expressed in metric tons of each 

gas and in metric tons of CO2e. For each 

stack provide an estimate based on 

engineering judgment of the fraction of 

the total emissions that is attributable to 

combustion of off-gas from the 

petrochemical process unit. 

(ii) The combined CH4 and N2O 

emissions from all stationary 

combustion units, expressed in metric 

tons of each gas and in metric tons of 

CO2e. 

(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 


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stationary combustion unit or group of 

combustion units (as applicable). 

* * * * * 

(c) If you comply with the combustion 

methodology specified in § 98.243(d), 

you must report under this subpart the 

information listed in paragraphs (c)(1) 

through (c)(5) of this section. 

(1) The ethylene process unit ID or 

other appropriate descriptor. 

(2) For each stationary combustion 

unit that burns ethylene process off-gas 

(or group of stationary sources with a 

common pipe), except flares, the 

relevant information listed in § 98.36 for 

the applicable Tier methodology. For 

each stationary combustion unit or 

group of units (as applicable) that burns 

ethylene process off-gas, provide an 

estimate based on engineering judgment 

of the fraction of the total emissions that 

is attributable to combustion of off-gas 

from the ethylene process unit. 

(3) Information listed in § 98.256(e) of 

subpart Y of this part for each flare that 

burns ethylene process off-gas. 

(4) Name and annual quantity of each 

feedstock. 

(5) Annual quantity of ethylene 

produced from each process unit (metric 

tons). 

■ 39. Section 98.247 is amended by: 

■ a. Revising paragraph (a). 

■ b. Adding paragraph (b)(4). 

■ c. Revising paragraph (c). 

§ 98.247 Records that must be retained. 

* * * * * 

(a) If you comply with the CEMS 

measurement methodology in 

§ 98.243(b), then you must retain under 

this subpart the records required for the 

Tier 4 Calculation Methodology in 

§ 98.37, records of the procedures used 

to develop estimates of the fraction of 

total emissions attributable to 

combustion of petrochemical process 

off-gas as required in § 98.246(b), and 

records of any annual average HHV 

calculations. 

(b) * * * 

(4) The dates and results (e.g., percent 

calibration error) of the calibrations of 

each measurement device. 

(c) If you comply with the combustion 

methodology in § 98.243(d), then you 

must retain under this subpart the 

records required for the applicable Tier 

Calculation Methodologies in § 98.37. If 

you comply with § 98.243(d)(2), you 

must also keep records of the annual 

average flow calculations. 

Subpart Y—[Amended] 

■ 40. Section 98.252 is amended by 

revising paragraph (a) and the first 

sentence of paragraph (i) to read as 

follows: 

§ 98.252 GHGs to report. 

* * * * * 

(a) CO2, CH4, and N2O combustion 

emissions from stationary combustion 

units and from each flare. Calculate and 

report the emissions from stationary 

combustion units under subpart C of 

this part (General Stationary Fuel 

Combustion Sources) by following the 

requirements of subpart C, except for 

emissions from combustion of fuel gas. 

For CO2 emissions from combustion of 

fuel gas, use either Equation C–5 in 

subpart C of this part or the Tier 4 

methodology in subpart C of this part, 

unless either of the conditions in 

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

are 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 C–1)’’ in Table C–2 of this part. 

For Tier 3, use either the default high 

heat value for fuel gas in Table C–1 of 

subpart C of this part or a calculated 

HHV, as allowed in Equation C–8 of 

subpart C of this part.) You may 

aggregate units, monitor common stacks, 

or monitor common (fuel) pipes as 

provided in § 98.36(c) when calculating 

and reporting emissions from stationary 

combustion units. Calculate and report 

the emissions from flares under this 

subpart. 

(1) The annual average fuel gas flow 

rate in the fuel gas line to the 

combustion unit, prior to any split to 

individual burners or ports, does not 

exceed 345 standard cubic feet per 

minute at 60 °F 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: 

(i) A flow meter is not installed at any 

point in the line supplying fuel gas or 

an upstream common pipe; or 

(ii) The fuel gas line contains only 

vapors from loading or unloading, waste 

or wastewater handling, and 

remediation activities that are 

combusted in a thermal oxidizer or 

thermal incinerator. 

* * * * * 

(i) CO2 emissions from non-merchant 

hydrogen production process units (not 

including hydrogen produced from 

catalytic reforming units) under this 

subpart. * * * 

■ 41. Section 98.253 is amended by: 

■ a. Revising paragraph (b)(1)(ii)(A). 

■ b. Revising the definition of ‘‘(Flare)p’’ 

in Equation Y–2 in paragraph 

(b)(1)(ii)(B). 

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

Equation Y–3 in paragraph (b)(1)(iii)(C). 

■ d. Revising paragraph (c)(1)(ii). 

■ e. Revising the definition of ‘‘MVC’’ in 

Equation Y–6 in paragraph (c)(2)(i). 

■ f. Revising paragraph (c)(2)(ii). 

■ g. Revising the definitions of ‘‘CBQ’’ 

and ‘‘n’’ in Equation Y–11 in paragraph 

(e)(3). 

■ h. Revising the first sentence of 

paragraph (f) introductory text and the 

last sentence of paragraph (f)(1). 

■ i. Revising the definition of ‘‘MVC’’ in 

Equation Y–12 in paragraph (f)(4). 

■ j. Revising the definition of ‘‘Mdust’’ in 

Equation Y–13 in paragraph (g)(2). 

■ k. Revising paragraphs (h) 

introductory text and (h)(2). 

■ l. In paragraph (i)(1), revising the first 

two sentences and the definition of 

‘‘MVC’’ in Equation Y–18. 

■ m. In paragraph (j), revising the first 

two sentences; and revising the 

definitions of ‘‘(VR)p,’’ ‘‘(MFx)p,’’ and 

‘‘MVC’’ in Equation Y–19. 

■ n. In paragraph (k), revising the first 

sentence and the definition of ‘‘MVC’’ in 

Equation Y–20. 

■ o. Revising paragraph (m) 

introductory text. 

■ p. Revising the only sentence of 

paragraph (m)(1). 

■ p. Revising the definitions of ‘‘MFCH4’’ 

and ‘‘MVC’’ in Equation Y–23 in 

paragraph (m)(2). 

■ q. Revising paragraph (n). 

§ 98.253 Calculating GHG emissions. 

* * * * * 

(b) * * * 

(1) * * * 

(ii) * * * 

(A) If you monitor gas composition, 

calculate the CO2 emissions from the 

flare using either Equation Y–1a or 

Equation Y–1b of this section. If daily or 

more frequent measurement data are 

available, you must use daily values 

when using Equation Y–1a or Equation 

Y–1b of this section; otherwise, use 

weekly values. 


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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/kg-mole). 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/kg-mole at 68 °F and 14.7 

pounds per square inch absolute (psia) or 

836.6 scf/kg-mole at 60 °F and 14.7 psia). 

(CC)p = Average carbon content of the flare 

gas combusted during measurement 

period (kg C per kg flare gas). If 

measurements are taken more frequently 

than daily, use the arithmetic average of 

measurement values within the day to 

calculate a daily average. 

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/kg-mole at 68 °F and 14.7 psia 

or 836.6 scf/kg-mole at 60 °F and 14.7 

psia). 

0.001 = Unit conversion factor (metric tons 

per kilogram, mt/kg). 

(%CO2)p = Mole percent CO2 concentration 

in the flare gas stream during the 

measurement period (mole percent = 

percent by volume). 

y = Number of carbon-containing compounds 

other than CO2 in the flare gas stream. 

x = Index for carbon-containing compounds 

other than CO2. 

0.98 = Assumed combustion efficiency of a 

flare (mole CO2 per mole carbon). 

(%Cx)p = Mole percent concentration of 

compound ‘‘x’’ in the flare gas stream 

during the measurement period (mole 

percent = percent by volume) 

CMNx = Carbon mole number of compound 

‘‘x’’ in the flare gas stream (mole carbon 

atoms per mole compound). E.g., CMN 

for ethane (C2H6) is 2; CMN for propane 

(C3H8) is 3. 

(B) * * * 

(Flare)p = Volume of flare gas combusted 

during measurement period (million 

(MM) scf/period). If a mass flow meter is 

used, you must also measure molecular 

weight and convert the mass flow to a 

volumetric flow as follows: Flare[MMscf] 

= 0.000001 × Flare[kg] × MVC/(MW)p, 

where MVC is the molar volume 

conversion factor [849.5 scf/kg-mole at 

68 °F and 14.7 psia or 836.6 scf/kg-mole 

at 60 °F and 14.7 psia depending on the 

standard conditions used when 

determining (HHV)p] and (MW)p is the 

average molecular weight of the flare gas 

combusted during measurement period 

(kg/kg-mole). 

* * * * * 

(iii) * * * 

(C) * * * 

MVC = Molar volume conversion factor 

(849.5 scf/kg-mole at 68 °F and 14.7 psia 

or 836.6 scf/kg-mole at 60 °F and 14.7 

psia). 

* * * * * 

(c) * * * 

(1) * * * 

(ii) For catalytic cracking units whose 

process emissions are discharged 

through a combined stack with other 

CO2 emissions (e.g., co-mingled with 

emissions from a CO boiler) you must 

also calculate the other CO2 emissions 

using the applicable methods for the 

applicable subpart (e.g., subpart C of 

this part in the case of a CO boiler). 

Calculate the process emissions from 

the catalytic cracking unit or fluid 

coking unit as the difference in the CO2

CEMS emissions and the calculated 

emissions associated with the additional 

units discharging through the combined 

stack. 

(2) * * * 

(i) * * * 

MVC = Molar volume conversion factor 

(849.5 scf/kg-mole at 68 °F and 14.7 psia 

or 836.6 scf/kg-mole at 60 °F 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. 

Where: Qr = Volumetric flow rate of exhaust gas from 

the fluid catalytic cracking unit 

regenerator or fluid coking unit burner 


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79162 Federal Register / Vol. 75, No. 242 / Friday, December 17, 2010 / Rules and Regulations 

prior to the combustion of other fossil 

fuels (dscfh). 

Qa = Volumetric flow rate of air to the fluid 

catalytic cracking unit regenerator or 

fluid coking unit burner, as determined 

from control room instrumentation 

(dscfh). 

Qoxy = Volumetric flow rate of oxygen 

enriched air to the fluid catalytic 

cracking unit regenerator or fluid coking 

unit burner as determined from control 

room instrumentation (dscfh). 

%O2 = Hourly average percent oxygen 

concentration in exhaust gas stream from 

the fluid catalytic cracking unit 

regenerator or fluid coking unit burner 

(percent by volume—dry basis). 

%Ooxy = O2 concentration in oxygen enriched 

gas stream inlet to the fluid catalytic 

cracking unit regenerator or fluid coking 

unit burner based on oxygen purity 

specifications of the oxygen supply used 

for enrichment (percent by volume—dry 

basis). 

%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. 

Where: 

Qr = Volumetric flow rate of exhaust gas from 

the fluid catalytic cracking unit 

regenerator or fluid coking unit burner 

prior to the combustion of other fossil 

fuels (dscfh). 

Qa = Volumetric flow rate of air to the fluid 

catalytic cracking unit regenerator or 

fluid coking unit burner, as determined 

from control room instrumentation 

(dscfh). 

Qoxy = Volumetric flow rate of oxygen 

enriched air to the fluid catalytic 

cracking unit regenerator or fluid coking 

unit burner as determined from control 

room instrumentation (dscfh). 

%N2,oxy = N2 concentration in oxygen 

enriched gas stream inlet to the fluid 

catalytic cracking unit regenerator or 

fluid coking unit burner based on 

measured value or maximum N2

impurity specifications of the oxygen 

supply used for enrichment (percent by 

volume—dry basis). 

%N2,exhaust = Hourly average percent N2

concentration in the exhaust gas stream 

from the fluid catalytic cracking unit 

regenerator or fluid coking unit burner 

(percent by volume—dry basis). 

* * * * * 

(e) * * * 

(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 nonClaus sulfur recovery plants only) 

follow the requirements in paragraph (j) 

of this section to determine CO2

emissions for the sulfur recovery plant. 

* * * * * 

(4) * * * 

MVC = Molar volume conversion factor 

(849.5 scf/kg-mole at 68 °F and 14.7 psia 

or 836.6 scf/kg-mole at 60 °F and 14.7 

psia). 

* * * * * 

(g) * * * 

(2) * * * 

Mdust = Annual mass of petroleum coke dust 

removed from the process through the 

dust collection system of the coke 

calcining unit from facility records 

(metric ton petroleum coke dust/year). 

For coke calcining units that recycle the 

collected dust, the mass of coke dust 

removed from the process is the mass of 

coke dust collected less the mass of coke 

dust recycled to the process. 

* * * * * 

(h) For asphalt blowing operations, 

calculate CO2 and CH4 emissions 

according to the requirements in 

paragraph (j) of this section regardless of 

the CO2 and CH4 concentrations or 

according to the applicable provisions 

in paragraphs (h)(1) and (h)(2) of this 

section. 

* * * * * 

(2) For asphalt blowing operations 

controlled by thermal oxidizer or flare, 

calculate CO2 using either Equation Y– 

16a or Equation Y–16b of this section 

and calculate CH4 emissions using 

Equation Y–17 of this section, provided 

these emissions are not already 

included in the flare emissions 

calculated in paragraph (b) of this 

section or in the stationary combustion 

unit emissions required under subpart C 

of this part (General Stationary Fuel 

Combustion Sources). 

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). 


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Where: 

CO2 = Annual CO2 emissions from controlled 

asphalt blowing (metric tons CO2/year). 

QAB = Quantity of asphalt blown (MMbbl/ 

year). 

0.98 = Assumed combustion efficiency of 

thermal oxidizer or flare. 

EFAB,CO2 = Emission factor for CO2 from 

uncontrolled asphalt blowing from 

facility-specific test data (metric tons 

CO2/MMbbl asphalt blown); default = 

1,100. 

CEFAB = Carbon emission factor from asphalt 

blowing from facility-specific test data 

(metric tons C/MMbbl asphalt blown); 

default = 2,750. 

44 = Molecular weight of CO2 (kg/kg-mole). 

12 = Atomic weight of C (kg/kg-mole). 

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. 

* * * * * 

MVC = Molar volume conversion factor 

(849.5 scf/kg-mole at 68 °F and 14.7 psia 

or 836.6 scf/kg-mole at 60 °F and 14.7 

psia). 

* * * * * 

(j) For each process vent not covered 

in paragraphs (a) through (i) of this 

section that can reasonably be expected 

to contain greater than 2 percent by 

volume CO2 or greater than 0.5 percent 

by volume of CH4 or greater than 0.01 

percent by volume (100 parts per 

million) of N2O, calculate GHG 

emissions using the Equation Y–19 of 

this section. You must use Equation Y– 

19 of this section to calculate CH4

emissions for catalytic reforming unit 

depressurization and purge vents when 

methane is used as the purge gas or if 

you elected this method as an 

alternative to the methods in paragraphs 

(f), (h), or (k) of this section. 

* * * * * 

(VR)p = Average volumetric flow rate of 

process gas during the event (scf per 

hour) from measurement data, process 

knowledge, or engineering estimates. 

(MFx)p = Mole fraction of GHG x in process 

vent during the event (kg-mol of GHG x/ 

kg-mol vent gas) from measurement data, 

process knowledge, or engineering 

estimates. 

* * * * * 

MVC = Molar volume conversion factor 

(849.5 scf/kg-mole at 68 °F and 14.7 psia 

or 836.6 scf/kg-mole at 60 °F and 14.7 

psia). 

* * * * * 

(k) For uncontrolled blowdown 

systems, you must calculate CH4 

emissions either using the methods for 

process vents in paragraph (j) of this 

section regardless of the CH4

concentration or using Equation Y20 of 

this section. * * * 

* * * * * 

MVC = Molar volume conversion factor 

(849.5 scf/kg-mole at 68 °F and 14.7 psia 

or 836.6 scf/kg-mole at 60 °F and 14.7 

psia). 

* * * * * 

(m) For storage tanks, except as 

provided in paragraph (m)(4) of this 

section, calculate CH4 emissions using 

the applicable methods in paragraphs 

(m)(1) through (m)(3) of this section. 

(1) For storage tanks other than those 

processing unstabilized crude oil, you 

must either calculate CH4 emissions 

from storage tanks that have a vaporphase methane concentration of 0.5 

volume percent or more using tankspecific methane composition data 

(from measurement data or product 

knowledge) and the emission estimation 

methods provided in AP 42, Section 7.1 

(incorporated by reference, see § 98.7) or 

estimate CH4 emissions from storage 

tanks using Equation Y–22 of this 

section. 

* * * * * 

(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/kg-mole at 68 °F and 14.7 psia 

or 836.6 scf/kg-mole at 60 °F and 14.7 

psia). 

* * * * * 

(n) For crude oil, intermediate, or 

product loading operations for which 

the vapor-phase concentration of 

methane is 0.5 volume percent or more, 

calculate CH4 emissions from loading 

operations using vapor-phase methane 

composition data (from measurement 

data or process knowledge) and the 

emission estimation procedures 

provided in AP 42, Section 5.2 

(incorporated by reference, see § 98.7). 

For loading operations in which the 

vapor-phase concentration of methane is 

less than 0.5 volume percent, you may 

assume zero methane emissions. 

■ 42. Section 98.254 is amended by: 

■ a. Revising paragraph (a). 

■ b. Revising paragraph (b). 

■ c. Revising paragraph (c). 

■ d. Revising paragraph (d) introductory 

text. 

■ e. Adding paragraph (d)(6). 

■ f. Revising paragraph (e) introductory 

text. 

■ g. Revising paragraph (f) introductory 

text and (f)(1). 

■ h. Removing and reserving paragraph 

(f)(2). 

■ i. Removing paragraph (f)(4). 

■ j. Revising paragraph (g). 

■ k. Revising the second sentence of 

paragraph (h). 

■ l. Removing paragraph (l). 

§ 98.254 Monitoring and QA/QC 

requirements. 

(a) Fuel flow meters, gas composition 

monitors, and heating value monitors 

that are associated with sources that use 

a CEMS to measure CO2 emissions 


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79164 Federal Register / Vol. 75, No. 242 / Friday, December 17, 2010 / Rules and Regulations 

according to subpart C of this part or 

that are associated with stationary 

combustion sources must meet the 

applicable monitoring and QA/QC 

requirements in § 98.34. 

(b) All gas flow meters, gas 

composition monitors, and heating 

value monitors that are used to provide 

data for the GHG emissions calculations 

in this subpart for sources other than 

those subject to the requirements in 

paragraph (a) of this section shall be 

calibrated according to the procedures 

specified by the manufacturer, or 

according to the procedures in the 

applicable methods specified in 

paragraphs (c) through (g) of this 

section. In the case of gas flow meters, 

all gas flow meters must meet the 

calibration accuracy requirements in 

§ 98.3(i). All gas flow meters, gas 

composition monitors, and heating 

value monitors must be recalibrated at 

the applicable frequency specified in 

paragraph (b)(1) or (b)(2) of this section. 

(1) You must recalibrate each gas flow 

meter according to one of the following 

frequencies. You may recalibrate at the 

minimum frequency specified by the 

manufacturer, biennially (every two 

years), or at the interval specified by the 

industry consensus standard practice 

used. 

(2) You must recalibrate each gas 

composition monitor and heating value 

monitor according to one of the 

following frequencies. You may 

recalibrate at the minimum frequency 

specified by the manufacturer, annually, 

or at the interval specified by the 

industry standard practice used. 

(c) For flare or sour gas flow meters 

and gas flow meters used to comply 

with the requirements in § 98.253(j), 

operate, calibrate, and maintain the flow 

meter according to one of the following. 

You may use the procedures specified 

by the flow meter manufacturer, or a 

method published by a consensus-based 

standards organization. Consensusbased standards organizations include, 

but are not limited to, the following: 

ASTM International (100 Barr Harbor 

Drive, P.O. Box CB700, West 

Conshohocken, Pennsylvania 19428– 

B2959, (800) 262–1373, http:// 

www.astm.org), the American National 

Standards Institute (ANSI, 1819 L 

Street, NW., 6th floor, Washington, DC 

20036, (202) 293–8020, http:// 

www.ansi.org), the American Gas 

Association (AGA, 400 North Capitol 

Street, NW., 4th Floor, Washington, DC 

20001, (202) 824–7000, http:// 

www.aga.org), the American Society of 

Mechanical Engineers (ASME, Three 

Park Avenue, New York, NY 10016– 

5990, (800) 843–2763, http:// 

www.asme.org), the American 

Petroleum Institute (API, 1220 L Street, 

NW., Washington, DC 20005–4070, 

(202) 682–8000, http://www.api.org), 

and the North American Energy 

Standards Board (NAESB, 801 Travis 

Street, Suite 1675, Houston, TX 77002, 

(713) 356–0060, http://www.api.org). 

(d) Except as provided in paragraph 

(g) of this section, determine gas 

composition and, if required, average 

molecular weight of the gas using any of 

the following methods. Alternatively, 

the results of chromatographic analysis 

of the fuel may be used, provided that 

the gas chromatograph is operated, 

maintained, and calibrated according to 

the manufacturer’s instructions; and the 

methods used for operation, 

maintenance, and calibration of the gas 

chromatograph are documented in the 

written Monitoring Plan for the unit 

under § 98.3(g)(5). 

* * * * * 

(6) ASTM D2503–92 (Reapproved 

2007) Standard Test Method for Relative 

Molecular Mass (Molecular Weight) of 

Hydrocarbons by Thermoelectric 

Measurement of Vapor Pressure 

(incorporated by reference, see § 98.7). 

(e) Determine flare gas higher heating 

value using any of the following 

methods. Alternatively, the results of 

chromatographic analysis of the fuel 

may be used, provided that the gas 

chromatograph is operated, maintained, 

and calibrated according to the 

manufacturer’s instructions; and the 

methods used for operation, 

maintenance, and calibration of the gas 

chromatograph are documented in the 

written Monitoring Plan for the unit 

under § 98.3(g)(5). 

* * * * * 

(f) For gas flow meters used to comply 

with the requirements in 

§ 98.253(c)(2)(ii), install, operate, 

calibrate, and maintain each gas flow 

meter according to the requirements in 

40 CFR 63.1572(c) and the following 

requirements. 

(1) Locate the flow monitor at a site 

that provides representative flow rates. 

Avoid locations where there is swirling 

flow or abnormal velocity distributions 

due to upstream and downstream 

disturbances. 

* * * * * 

(g) For exhaust gas CO2/CO/O2

composition monitors used to comply 

with the requirements in § 98.253(c)(2), 

install, operate, calibrate, and maintain 

exhaust gas composition monitors 

according to the requirements in 40 CFR 

60.105a(b)(2) or 40 CFR 63.1572(c) or 

according to the manufacturer’s 

specifications and requirements. 

(h) * * * Calibrate the measurement 

device according to the procedures 

specified by NIST handbook 44 

(incorporated by reference, see § 98.7) or 

the procedures specified by the 

manufacturer. * * * 

* * * * * 

■ 43. Section 98.256 is amended by: 

■ a. Revising paragraph (e)(6). 

■ b. Redesignating paragraphs (e)(7) 

through (e)(9) as (e)(8) through (e)(10), 

respectively. 

■ c. Adding paragraph (e)(7). 

■ d. Revising newly designated 

paragraphs (e)(8) and (e)(9). 

■ e. Revising paragraphs (f)(6) through 

(f)(8). 

■ f. Redesignating paragraphs (f)(9) 

through (f)(12) as (f)(10) through (f)(13), 

respectively. 

■ g. Adding paragraph (f)(9). 

■ h. Revising newly designated 

paragraphs (f)(11) through (f)(13). 

■ i. Revising paragraphs (g)(5), (h)(2), 

and (h)(4), and the first sentence of 

paragraph (h)(6). 

■ j. Adding paragraph (h)(7). 

■ k. Revising paragraphs (i)(5), (i)(6), 

(i)(8), and (j)(2). 

■ l. Redesignating paragraph (j)(8) as 

(j)(9). 

■ m. Adding paragraph (j)(8). 

■ n. Revising paragraphs (k)(1), (k)(3), (l) 

introductory text, (l)(5), and (m). 

■ o. Revising paragraphs (o)(1) through 

(o)(4). 

§ 98.256 Data reporting requirements. 

* * * * * 

(e) * * * 

(6) If you use Equation Y–1a of this 

subpart, an indication of whether daily 

or weekly measurement periods are 

used, the annual volume of flare gas 

combusted (in scf/year) and the annual 

average molecular weight (in kg/kgmole), the molar volume conversion 

factor (in scf/kg-mole), 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 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 


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or weekly measurement periods are 

used, the annual volume of flare gas 

combusted (in million (MM) scf/year), 

the annual average higher heating value 

of the flare gas (in mmBtu/mmscf), and 

an indication of whether the annual 

volume of flare gas combusted and the 

annual average higher heating value of 

the flare gas were determined using 

standard conditions of 68 °F and 14.7 

psia or 60 °F and 14.7 psia. 

(9) If you use Equation Y–3 of this 

subpart, the annual volume of flare gas 

combusted (in MMscf/year) during 

normal operations, the annual average 

higher heating value of the flare gas (in 

mmBtu/mmscf), the number of SSM 

events exceeding 500,000 scf/day, the 

volume of gas flared (in scf/event), the 

average molecular weight (in kg/kgmole), the molar volume conversion 

factor (in scf/kg-mole), and carbon 

content of the flare gas (in kg carbon per 

kg flare) for each SSM event over 

500,000 scf/day. 

* * * * * 

(f) * * * 

(6) If you use a CEMS, the relevant 

information required under § 98.36 for 

the Tier 4 Calculation Methodology, the 

CO2 annual emissions as measured by 

the CEMS (unadjusted to remove CO2

combustion emissions associated with 

additional units, if present) and the 

process CO2 emissions as calculated 

according to § 98.253(c)(1)(ii). Report 

the CO2 annual emissions associated 

with sources other than those from the 

coke burn-off in the applicable subpart 

(e.g., subpart C of this part in the case 

of a CO boiler). 

(7) If you use Equation Y–6 of this 

subpart, the annual average exhaust gas 

flow rate, %CO2, %CO, and the molar 

volume conversion factor (in scf/kgmole). 

(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 

emission factor is based on coke burnoff 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 burnoff 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) * * * 

(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/kg-mole), 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) * * * 

(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 burnoff rate, the annual quantity of coke 

burned), and the basis for the factor. 

(j) * * * 

(2) The quantity of asphalt blown (in 

million bbl) at the unit in the reporting 

year. 

* * * * * 

(8) If you use Equation Y–16b of this 

subpart, the CO2 emission factor used 

and the basis for its value and the 

carbon emission factor used and the 

basis for its value. 

* * * * * 

(k) * * * 

(1) The cumulative annual CH4

emissions (in metric tons of CH4) for all 

delayed coking units at the facility. 

* * * * * 

(3) The total number of delayed 

coking units at the facility, the total 

number of delayed coking drums at the 

facility, and for each coke drum or 

vessel: The dimensions, the typical 

gauge pressure of the coking drum when 

first vented to the atmosphere, typical 

void fraction, the typical drum outage 

(i.e. the unfilled distance from the top 

of the drum, in feet), the molar volume 

conversion factor (in scf/kg-mole), and 

annual number of coke-cutting cycles. 

* * * * * 

(l) For each process vent subject to 

§ 98.253(j), the owner or operator shall 

report: 

* * * * * 

(5) The annual volumetric flow 

discharged to the atmosphere (in scf), 

and an indication of the measurement or 

estimation method, annual average mole 

fraction of each GHG above the 

concentration threshold or otherwise 

required to be reported and an 

indication of the measurement or 

estimation method, the molar volume 

conversion factor (in scf/kg-mole), and 

for intermittent vents, the number of 


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79166 Federal Register / Vol. 75, No. 242 / Friday, December 17, 2010 / Rules and Regulations 

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/kgmole). 

(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 (i.e., 

either AP 42, Section 7.1 (incorporated 

by reference, see § 98.7), or Equation Y– 

22 of this section). 

(ii) The total quantity (in MMbbl) of 

crude oil plus the quantity of 

intermediate products received from off 

site that are processed at the facility in 

the reporting year. 

(3) The cumulative CH4 emissions (in 

metric tons of CH4) for storage tanks 

used to process unstabilized crude oil or 

a statement that the facility did not 

receive any unstabilized crude oil 

during the reporting year. 

(4) For storage tanks that process 

unstabilized crude oil: 

(i) The method used to calculate the 

reported unstabilized crude oil storage 

tank emissions. 

(ii) The quantity of unstabilized crude 

oil received during the calendar year (in 

MMbbl). 

(iii) The average pressure differential 

(in psi). 

(iv) The molar volume conversion 

factor (in scf/kg-mole). 

(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 tank-specific 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. 

* * * * * 

■ 44. Section 98.257 is revised to read 

as follows: 

§ 98.257 Records that must be retained. 

In addition to the records required by 

§ 98.3(g), you must retain the records of 

all parameters monitored under 

§ 98.255. If you comply with the 

combustion methodology in § 98.252(a), 

then you must retain under this subpart 

the records required for the Tier 3 and/ 

or Tier 4 Calculation Methodologies in 

§ 98.37 and you must keep records of 

the annual average flow calculations. 

Subpart AA—[Amended] 

■ 45. Section 98.273 is amended by: 

■ a. Revising paragraphs (a)(1) and 

(a)(2). 

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

Equation AA–1 of paragraph (a)(3). 

■ c. Revising paragraphs (b)(1) and 

(b)(2). 

■ d. Revising paragraphs (c)(1) and 

(c)(2). 

§ 98.273 Calculating GHG emissions. 

(a) * * * 

(1) Calculate fossil fuel-based CO2

emissions from direct measurement of 

fossil fuels consumed and default 

emissions factors according to the Tier 

1 methodology for 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 fossil fuel-based CH4 and 

N2O emissions from direct measurement 

of fossil fuels consumed, default or sitespecific HHV, and default emissions 

factors and convert to metric tons of CO2

equivalent according to the 

methodology for stationary combustion 

sources in § 98.33(c). 

(3) * * * 

(EF) = Default or site-specific emission factor 

for CO2, CH4, or N2O, from Table AA–1 

of this subpart (kg CO2, CH4, or N2O per 

mmBtu). 

* * * * * 

(b) * * * 

(1) Calculate fossil CO2 emissions 

from fossil fuels from direct 

measurement of fossil fuels consumed 

and default emissions factors according 

to the Tier 1 Calculation Methodology 

for stationary combustion sources in 

§ 98.33(a)(1). A higher tier from 

§ 98.33(a) may be used to calculate fossil 

fuel-based CO2 emissions if the 

respective monitoring and QA/QC 

requirements described in § 98.34 are 

met. 

(2) Calculate CH4 and N2O emissions 

from fossil fuels from direct 

measurement of fossil fuels consumed, 

default or site-specific HHV, and default 

emissions factors and convert to metric 

tons of CO2 equivalent according to the 

methodology for stationary combustion 

sources in § 98.33(c). 

* * * * * 

(c) * * * 

(1) Calculate CO2 emissions from 

fossil fuel from direct measurement of 

fossil fuels consumed and default HHV 

and default emissions factors, according 

to the Tier 1 Calculation Methodology 

for stationary combustion sources in 

§ 98.33(a)(1). A higher tier from 

§ 98.33(a) may be used to calculate fossil 

fuel-based CO2 emissions if the 

respective monitoring and QA/QC 

requirements described in § 98.34 are 

met. 

(2) Calculate CH4 and N2O emissions 

from fossil fuel from direct 

measurement of fossil fuels consumed, 

default or site-specific HHV, and default 

emissions factors and convert to metric 

tons of CO2 equivalent according to the 

methodology for stationary combustion 

sources in § 98.33(c); use the default 

HHV listed in Table C–1 of subpart C 

and the default CH4 and N2O emissions 

factors listed in Table AA–2 of this 

subpart. 

* * * * * 

■ 46. Section 98.276 is amended by 

revising the introductory text and 

revising paragraph (e) to read as follows: 

§ 98.276 Data reporting requirements. 

In addition to the information 

required by § 98.3(c) and the applicable 

information required by § 98.36, each 

annual report must contain the 

information in paragraphs (a) through 

(k) of this section as applicable: 

* * * * * 

(e) The default or site-specific 

emission factor for CO2, CH4, or N2O, 

used in Equation AA–1 of this subpart 

(kg CO2, CH4, or N2O per mmBtu). 

* * * * * 

■ 47. Table AA–2 to Subpart AA is 

revised to read as follows: 


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Federal Register / Vol. 75, No. 242 / Friday, December 17, 2010 / Rules and Regulations 79167 

TABLE AA–2 TO SUBPART AA—KRAFT LIME KILN AND CALCINER EMISSIONS FACTORS FOR FOSSIL FUEL-BASED CH4 AND

N2O 

Fuel 

Fossil fuel-based emissions factors (kg/mmBtu HHV) 

Kraft lime kilns Kraft calciners 

CH4 N2O CH4 N2O 

Residual Oil ..................................................................................... ............................ ............................ ............................ 0.0003 

Distillate Oil ...................................................................................... ............................ ............................ 0.0027 0.0004 

Natural Gas ...................................................................................... 0.0027 ............................ 0.0001 

Biogas .............................................................................................. ............................ ............................ ............................ 0.0001 

Petroleum coke ................................................................................ ............................ ............................ NA a NA 

aEmission factors for kraft calciners are not available. 

Subpart OO—[Amended] 

■ 48. Section 98.410 is amended by 

revising paragraph (b) to read as follows: 

§ 98.410 Definition of the source category. 

* * * * * 

(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 HFC–23) 

that is captured and shipped off site for 

any reason, including destruction. 

Producing a fluorinated GHG does not 

include the reuse or recycling of a 

fluorinated GHG, the creation of HFC– 

23 during the production of HCFC–22, 

the creation of intermediates that are 

created and transformed in a single 

process with no storage of the 

intermediates, or the creation of 

fluorinated GHGs that are released or 

destroyed at the production facility 

before the production measurement at 

§ 98.414(a). 

* * * * * 

■ 49. Section 98.414 is amended by: 

■ a. Adding second and third sentences 

to 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 lowconcentration constituents, shall be 

measured as set forth in paragraph (n) 

of this section. For each fluorinated 

GHG, the mean of the concentrations of 

that fluorinated GHG (mass fraction) 

measured under paragraph (n) of this 

section shall be multiplied by the mass 

measurement to obtain the mass of that 

fluorinated GHG coming out of the 

production process. 

* * * * * 

(h) You must measure the mass of 

each fluorinated GHG that is fed into the 

destruction device and that was 

previously produced as defined at 

§ 98.410(b). Such fluorinated GHGs 

include but are not limited to quantities 

that are shipped to the facility by 

another facility for destruction and 

quantities that are returned to the 

facility for reclamation but are found to 

be irretrievably contaminated and are 

therefore destroyed. You must use 

flowmeters, weigh scales, or a 

combination of volumetric and density 

measurements with an accuracy and 

precision of one percent of full scale or 

better. If the measured mass includes 

more than trace concentrations of 

materials other than the fluorinated 

GHG being destroyed, you must 

estimate the concentrations of the 

fluorinated GHG being destroyed 

considering current or previous 

representative concentration 

measurements and other relevant 

process information. You must multiply 

this concentration (mass fraction) by the 

mass measurement to obtain the mass of 

the fluorinated GHG fed into the 

destruction device. 

* * * * * 

(n) If the mass coming out of the 

production process includes more than 

one fluorinated GHG, you shall measure 

the concentrations of all of the 

fluorinated GHGs, other than lowconcentration constituents, as follows: 

(1) Analytical Methods. Use a qualityassured analytical measurement 

technology capable of detecting the 

analyte of interest at the concentration 

of interest and use a procedure 

validated with the analyte of interest at 

the concentration of interest. Where 

standards for the analyte are not 

available, a chemically similar surrogate 

may be used. Acceptable analytical 

measurement technologies include but 

are not limited to gas chromatography 

(GC) with an appropriate detector, 

infrared (IR), fourier transform infrared 

(FTIR), and nuclear magnetic resonance 

(NMR). Acceptable methods include 

EPA Method 18 in Appendix A–1 of 40 

CFR part 60; EPA Method 320 in 

Appendix A of 40 CFR part 63; the 

Protocol for Measuring Destruction or 

Removal Efficiency (DRE) of Fluorinated 

Greenhouse Gas Abatement Equipment 

in Electronics Manufacturing, Version 1, 

EPA–430–R–10–003, (March 2010) 

(incorporated by reference, see § 98.7); 

ASTM D6348–03 Standard Test Method 

for Determination of Gaseous 

Compounds by Extractive Direct 

Interface Fourier Transform Infrared 

(FTIR) Spectroscopy (incorporated by 

reference, see § 98.7); or other analytical 

methods validated using EPA Method 

301 in Appendix A of 40 CFR part 63 

or some other scientifically sound 

validation protocol. The validation 

protocol may include analytical 

technology manufacturer specifications 

or recommendations. 

(2) Documentation in GHG Monitoring 

Plan. Describe the analytical method(s) 

used under paragraph (n)(1) of this 

section in the site GHG Monitoring Plan 

as required under § 98.3(g)(5). At a 

minimum, include in the description of 

the method a description of the 

analytical measurement equipment and 

procedures, quantitative estimates of the 

method’s accuracy and precision for the 

analytes of interest at the concentrations 

of interest, as well as a description of 

how these accuracies and precisions 

were estimated, including the validation 

protocol used. 

(3) Frequency of measurement. 

Perform the measurements at least once 

by February 15, 2011 if the fluorinated 

GHG product is being produced on 

December 17, 2010. Perform the 

measurements within 60 days of 

commencing production of any 

fluorinated GHG product that was not 


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being produced on December 17, 2010. 

Repeat the measurements if an 

operational or process change occurs 

that could change the identities or 

significantly change the concentrations 

of the fluorinated GHG constituents of 

the fluorinated GHG product. Complete 

the repeat measurements within 60 days 

of the operational or process change. 

(4) Measure all product grades. Where 

a fluorinated GHG is produced at more 

than one purity level (e.g., 

pharmaceutical grade and refrigerant 

grade), perform the measurements for 

each purity level. 

(5) Number of samples. Analyze a 

minimum of three samples of the 

fluorinated GHG product that have been 

drawn under conditions that are 

representative of the process producing 

the fluorinated GHG product. If the 

relative standard deviation of the 

measured concentrations of any of the 

fluorinated GHG constituents (other 

than low-concentration constituents) is 

greater than or equal to 15 percent, draw 

and analyze enough additional samples 

to achieve a total of at least six samples 

of the fluorinated GHG product. 

(o) All analytical equipment used to 

determine the concentration of 

fluorinated GHGs, including but not 

limited to gas chromatographs and 

associated detectors, IR, FTIR and NMR 

devices, shall be calibrated at a 

frequency needed to support the type of 

analysis specified in the site GHG 

Monitoring Plan as required under 

§ 98.414(n) and § 98.3(g)(5) of this part. 

Quality assurance samples at the 

concentrations of concern shall be used 

for the calibration. Such quality 

assurance samples shall consist of or be 

prepared from certified standards of the 

analytes of concern where available; if 

not available, calibration shall be 

performed by a method specified in the 

GHG Monitoring Plan. 

(p) Isolated intermediates that are 

produced and transformed at the same 

facility are exempt from the monitoring 

requirements of this section. 

(q) Low-concentration constituents 

are exempt from the monitoring and 

QA/QC requirements of this section. 

■ 50. Section 98.416 is amended by: 

■ a. Revising paragraph (a)(3). 

■ b. Removing and reserving paragraph 

(a)(4). 

■ c. Revising paragraphs (a)(11) and 

(a)(15). 

■ d. Revising paragraphs (b) 

introductory text and (b)(1). 

■ e. Revising paragraphs (c) 

introductory text, (c)(1), and (c)(10). 

■ f. Revising paragraph (d) introductory 

text. 

■ g. Revising paragraph (e) introductory 

text. 

■ h. Adding paragraphs (f) through (h). 

§ 98.416 Data reporting requirements. 

* * * * * 

(a) * * * 

(3) Mass in metric tons of each 

fluorinated GHG that is destroyed at that 

facility and that was previously 

produced as defined at § 98.410(b). 

Quantities to be reported under this 

paragraph (a)(3) of this section include 

but are not limited to quantities that are 

shipped to the facility by another 

facility for destruction and quantities 

that are returned to the facility for 

reclamation but are found to be 

irretrievably contaminated and are 

therefore destroyed. 

* * * * * 

(11) Mass in metric tons of each 

fluorinated GHG that is fed into the 

destruction device and that was 

previously produced as defined at 

§ 98.410(b). Quantities to be reported 

under this paragraph (a)(11) of this 

section include but are not limited to 

quantities that are shipped to the facility 

by another facility for destruction and 

quantities that are returned to the 

facility for reclamation but are found to 

be irretrievably contaminated and are 

therefore destroyed. 

* * * * * 

(15) Names and addresses of facilities 

to which any fluorinated GHGs were 

sent for destruction, and the quantities 

(metric tons) of each fluorinated GHG 

that were sent to each for destruction. 

* * * * * 

(b) By March 31, 2011 or within 60 

days of commencing fluorinated GHG 

destruction, whichever is later, a 

fluorinated GHG production facility or 

importer that destroys fluorinated GHGs 

shall submit a one-time report 

containing the following information for 

each destruction process: 

(1) Destruction efficiency (DE). 

* * * * * 

(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 twentyfive kilograms of fluorinated GHGs or 

nitrous oxide, transshipments, and heels 

that meet the conditions set forth at 

§ 98.417(e). The report shall contain the 

following information for each import: 

(1) Total mass in metric tons of 

nitrous oxide and each fluorinated GHG 

imported in bulk, including each 

fluorinated GHG constituent of the 

fluorinated GHG product that makes up 

between 0.5 percent and 100 percent of 

the product by mass. 

* * * * * 

(10) If applicable, the names and 

addresses of the persons and facilities to 

which the fluorinated GHGs were sold 

or transferred for destruction, and the 

quantities (metric tons) of each 

fluorinated GHG that were sold or 

transferred to each facility for 

destruction. 

(d) Each bulk exporter of fluorinated 

GHGs or nitrous oxide shall submit an 

annual report that summarizes its 

exports at the corporate level, except for 

shipments including less than twentyfive kilograms of fluorinated GHGs or 

nitrous oxide, transshipments, and 

heels. The report shall contain the 

following information for each export: 

* * * * * 

(e) By March 31, 2011, or within 60 

days of commencing fluorinated GHG 

production, whichever is later, a 

fluorinated GHG production facility 

shall submit a one-time report 

describing the following information: 

* * * * * 

(f) By March 31, 2011, all fluorinated 

GHG production facilities shall submit a 

one-time report that includes the 

concentration of each fluorinated GHG 

constituent in each fluorinated GHG 

product as measured under § 98.414(n). 

If the facility commences production of 

a fluorinated GHG product that was not 

included in the initial report or 

performs a repeat measurement under 

§ 98.414(n) that shows that the identities 

or concentrations of the fluorinated 

GHG constituents of a fluorinated GHG 

product have changed, then the new or 

changed concentrations, as well as the 

date of the change, must be reflected in 

a revision to the report. The revised 

report must be submitted to EPA by the 

March 31st that immediately follows the 

measurement under § 98.414(n). 

(g) Isolated intermediates that are 

produced and transformed at the same 

facility are exempt from the reporting 

requirements of this section. 

(h) Low-concentration constituents 

are exempt from the reporting 

requirements of this section. 

■ 51. Section 98.417 is amended by 

revising paragraphs (a)(2), (b), and 

(d)(2); and by adding paragraphs (f) and 

(g) to read as follows: 

§ 98.417 Records that must be retained. 

(a) * * * 

(2) Records documenting the initial 

and periodic calibration of the 

analytical equipment (including but not 

limited to GC, IR, FTIR, or NMR), weigh 

scales, flowmeters, and volumetric and 

density measures used to measure the 

quantities reported under this subpart, 

including the manufacturer directions 

or industry standards used for 


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calibration pursuant to § 98.414(m) and 

(o). 

(b) In addition to the data required by 

paragraph (a) of this section, any 

fluorinated GHG production facility that 

destroys fluorinated GHGs shall keep 

records of test reports and other 

information documenting the facility’s 

one-time destruction efficiency report in 

§ 98.416(b). 

* * * * * 

(d) * * * 

(2) The invoice for the export. 

* * * * * 

(f) Isolated intermediates that are 

produced and transformed at the same 

facility are exempt from the 

recordkeeping requirements of this 

section. 

(g) Low-concentration constituents are 

exempt from the recordkeeping 

requirements of this section. 

■ 52. Section 98.418 is revised to read 

as follows: 

§ 98.418 Definitions. 

Except as provided below, all of the 

terms used in this subpart have the 

same meaning given in the Clean Air 

Act and subpart A of this part. If a 

conflict exists between a definition 

provided in this subpart and a 

definition provided in subpart A, the 

definition in this subpart shall take 

precedence for the reporting 

requirements in this subpart. 

Isolated intermediate means a product 

of a process that is stored before 

subsequent processing. An isolated 

intermediate is usually a product of 

chemical synthesis. Storage of an 

isolated intermediate marks the end of 

a process. Storage occurs at any time the 

intermediate is placed in equipment 

used solely for storage. 

Low-concentration constituent means, 

for purposes of fluorinated GHG 

production and export, a fluorinated 

GHG 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. Low-concentration 

constituents do not include fluorinated 

GHGs that are deliberately combined 

with the product (e.g., to affect the 

performance characteristics of the 

product). 

Subpart PP—[Amended] 

■ 53. Section 98.422 is amended by 

revising paragraphs (a) and (b) to read 

as follows: 

§ 98.422 GHGs to report. 

(a) Mass of CO2 captured from 

production process units. 

(b) Mass of CO2 extracted from CO2

production wells. 

* * * * * 

■ 54. Section 98.423 is amended by: 

■ a. Revising the first sentence of 

paragraph (a) introductory text. 

■ b. Revising the first sentences of 

paragraphs (a)(1) and (a)(2). 

■ c. Revising the definitions of ‘‘CCO2,p’’ 

and ‘‘Dp’’ in Equation PP–2 in paragraph 

(a)(2). 

■ d. Revising paragraph (a)(3). 

■ e. Redesignating paragraph (b) as 

paragraph (c) and revising newly 

designated paragraph (c). 

■ f. Adding paragraph (b). 

§ 98.423 Calculating CO2 Supply. 

(a) Except as allowed in paragraph (b) 

of this section, calculate the annual 

mass of CO2 captured, extracted, 

imported, or exported through each flow 

meter in accordance with the 

procedures specified in either paragraph 

(a)(1) or (a)(2) of this section. * * * 

(1) For each mass flow meter, you 

shall calculate quarterly the mass of CO2

in a CO2 stream in metric tons by 

multiplying the mass flow by the 

composition data, according to Equation 

PP–1 of this section. * * * 

* * * * * 

(2) For each volumetric flow meter, 

you shall calculate quarterly the mass of 

CO2 in a CO2 stream in metric tons by 

multiplying the volumetric flow by the 

concentration and density data, 

according to Equation PP–2 of this 

section. * * * 

* * * * * 

CCO2,p = Quarterly CO2 concentration 

measurement in flow for flow meter u in 

quarter p (measured as either volume % 

CO2 or weight % CO2). 

* * * * * 

Dp = Density of CO2 in quarter p (metric tons 

CO2 per standard cubic meter) for flow 

meter u if CCO2,p is measured as volume 

% CO2, or density of the whole CO2

stream for flow meter u (metric tons per 

standard cubic meter) if CCO2,p is 

measured as weight % CO2. 

* * * * * 

(3) To aggregate data, use either 

Equation PP–3a or PP–3b in this 

paragraph, as appropriate. 

(i) For facilities with production 

process units that capture a CO2 stream 

and either measure it after segregation 

or do not segregate the flow, calculate 

the total CO2 supplied in accordance 

with Equation PP–3a. 

Where: 

CO2 = Total annual mass of CO2 (metric 

tons). 

CO2,u = Annual mass of CO2 (metric tons) 

through flow meter u. 

u = Flow meter. 

(ii) For facilities with production 

process units that capture a CO2 stream 

and measure it ahead of segregation, 

calculate the total CO2 supplied in 

accordance with Equation PP–3b. 

Where: 

CO2 = Total annual mass of CO2 (metric 

tons). 

CO2,u = Annual mass of CO2 (metric tons) 

through main flow meter u. 

CO2,v = Annual mass of CO2 (metric tons) 

through subsequent flow meter v for use 

on site. 

u = Main flow meter. 

v = Subsequent flow meter. 

(b) As an alternative to paragraphs 

(a)(1) through (3) of this section for CO2

that is supplied in containers, calculate 

the annual mass of CO2 supplied in 

containers delivered by each CO2 stream 


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79170 Federal Register / Vol. 75, No. 242 / Friday, December 17, 2010 / Rules and Regulations 

in accordance with the procedures 

specified in either paragraph (b)(1) or 

(b)(2) of this section. If multiple CO2

streams are used to deliver CO2 to 

containers, you shall calculate the 

annual mass of CO2 supplied in 

containers delivered by all CO2 streams 

according to the procedures specified in 

paragraph (b)(3) of this section. 

(1) For each CO2 stream that delivers 

CO2 to containers, for which mass is 

measured, you shall calculate CO2

supply in containers using Equation PP– 

1 of this section. 

Where: 

CO2,u = Annual mass of CO2 (metric tons) 

supplied in containers delivered by CO2

stream u. 

CCO2,p,u = Quarterly CO2 concentration 

measurement of CO2 stream u that 

delivers CO2 to containers in quarter p 

(wt. %CO2). 

Qp,u = Quarterly mass of contents supplied in 

all containers delivered by CO2 stream u 

in quarter p (metric tons). 

p = Quarter of the year. 

u = CO2 stream that delivers to containers. 

(2) For each CO2 stream that delivers 

to containers, for which volume is 

measured, you shall calculate CO2

supply in containers using Equation PP– 

2 of this section. 

Where: 

CO2,u = Annual mass of CO2 (metric tons) 

supplied in containers delivered by CO2

stream u. 

CCO2,p = Quarterly CO2 concentration 

measurement of CO2 stream u that 

delivers CO2 to containers in quarter p 

(measured as either volume % CO2 or 

weight % CO2). 

Qp = Quarterly volume of contents supplied 

in all containers delivered by CO2 stream 

u in quarter p (standard cubic meters). 

Dp = Quarterly CO2 density determination for 

CO2 stream u in quarter p (metric tons 

per standard cubic meter) if CO2,p is 

measured as volume % CO2, or density 

of CO2 stream u (metric tons per 

standard cubic meter) if CO2,p is 

measured as weight % CO2. 

p = Quarter of the year. 

u = CO2 stream that delivers to containers. 

(3) To aggregate data, sum the mass of 

CO2 supplied in containers delivered by 

all CO2 streams in accordance with 

Equation PP–3a of this section. 

Where: 

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. 

Where: 

CO2 = Annual mass of CO2 (metric tons). 

Q = Annual mass in all CO2 containers 

imported or exported during the 

reporting year (metric tons). 

■ 55. Section 98.424 is amended by: 

■ a. Revising paragraphs (a)(1), (a)(2), 

and (a)(5). 

■ b. Revising the second sentence of 

paragraph (b)(2). 

■ c. Adding paragraph (c). 

§ 98.424 Monitoring and QA/QC 

requirements. 

(a) * * * 

(1) Reporters following the procedures 

in § 98.423(a) shall determine quantity 

using a flow meter or meters located in 

accordance with this paragraph. 

(i) If the CO2 stream is segregated such 

that only a portion is captured for 

commercial application or for injection, 

you must locate the flow meter 

according to the following: 

(A) For reporters following the 

procedures in § 98.423(a)(3)(i), you must 

locate the flow meter(s) after the point 

of segregation. 

(B) For reporters following the 

procedures in paragraph (a)(3)(ii) of 

§ 98.423, you must locate the main flow 

meter(s) on the captured CO2 stream(s) 

prior to the point of segregation and the 

subsequent flow meter(s) on the CO2

stream(s) for on-site use after the point 

of segregation. You may only follow the 

procedures in paragraph (a)(3)(ii) of 

§ 98.423 if the CO2 stream(s) for on-site 

use is/are the only diversion(s) from the 

main, captured CO2 stream(s) after the 

main flow meter location(s). 

(ii) Reporters that have a mass flow 

meter or volumetric flow meter installed 

to measure the flow of a CO2 stream that 

meets the requirements of paragraph 

(a)(1)(i) of this section shall base 

calculations in § 98.423 of this subpart 

on the installed mass flow or volumetric 

flow meters. 

(iii) Reporters that do not have a mass 

flow meter or volumetric flow meter 

installed to measure the flow of the CO2

stream that meets the requirements of 

paragraph (a)(1)(i) of this section shall 

base calculations in § 98.423 of this 

subpart on the flow of gas transferred off 

site using a mass flow meter or a 

volumetric flow meter located at the 

point of off-site transfer. 

(2) Reporters following the procedures 

in paragraph (b) of § 98.423 shall 

determine quantity in accordance with 

this paragraph. 

(i) Reporters that supply CO2 in 

containers using weigh bills, scales, or 

load cells shall measure the mass of 

contents of each CO2 container to which 

the CO2 stream is delivered, sum the 

mass of contents supplied in all 

containers to which the CO2 stream is 

delivered during each quarter, sample 

the CO2 stream delivering CO2 to 

containers on a quarterly basis to 

determine the composition of the CO2

stream, and apply Equation PP–1. 

(ii) Reporters that supply CO2 in 

containers using loaded container 

volumes shall measure the volume of 

contents of each CO2 container to which 

the CO2 stream is delivered, sum the 

volume of contents supplied in all 

containers to which the CO2 stream is 

delivered during each quarter, sample 

the CO2 stream on a quarterly basis to 

determine the composition of the CO2

stream, determine the density quarterly, 

and apply Equation PP–2. 

* * * * * 

(5) Reporters using Equation PP–2 of 

this subpart and measuring CO2

concentration as weight % CO2 shall 

determine the density of the CO2 stream 

on a quarterly basis in order to calculate 

the mass of the CO2 stream according to 

one of the following procedures: 

(i) You may use a method published 

by a consensus-based standards 

organization. Consensus-based 

standards organizations include, but are 

not limited to, the following: ASTM 

International (100 Barr Harbor Drive, 

P.O. Box CB700, West Conshohocken, 

Pennsylvania 19428–B2959, (800) 262– 

1373, http://www.astm.org), the 

American National Standards Institute 

(ANSI, 1819 L Street, NW., 6th floor, 

Washington, DC 20036, (202) 293–8020, 

http://www.ansi.org), the American Gas 

Association (AGA, 400 North Capitol 

Street, NW., 4th Floor, Washington, DC 

20001, (202) 824–7000, http:// 

www.aga.org), the American Society of 


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Mechanical Engineers (ASME, Three 

Park Avenue, New York, NY 10016– 

5990, (800) 843–2763, http:// 

www.asme.org), the American 

Petroleum Institute (API, 1220 L Street, 

NW., Washington, DC 20005–4070, 

(202) 682–8000, http://www.api.org), 

and the North American Energy 

Standards Board (NAESB, 801 Travis 

Street, Suite 1675, Houston, TX 77002, 

(713) 356–0060, http://www.api.org). 

The method(s) used shall be 

documented in the Monitoring Plan 

required under § 98.3(g)(5). 

(ii) You may follow an industry 

standard method. 

(b) * * * 

(2) * * * Acceptable methods 

include, but are not limited to, the U.S. 

Food and Drug Administration foodgrade specifications for CO2 (see 21 CFR 

184.1240) and ASTM standard E1747– 

95 (Reapproved 2005) Standard Guide 

for Purity of Carbon Dioxide Used in 

Supercritical Fluid Applications (ASTM 

International, 100 Barr Harbor Drive, 

P.O. Box CB700, West Conshohocken, 

Pennsylvania 19428–B2959, (800) 262– 

1373, http://www.astm.org). 

(c) You shall convert the density of 

the CO2 stream(s) and all measured 

volumes of carbon dioxide to the 

following standard industry temperature 

and pressure conditions: Standard cubic 

meters at a temperature of 60 degrees 

Fahrenheit and at an absolute pressure 

of 1 atmosphere. If you apply the 

density value for CO2 at standard 

conditions, you must use 0.001868 

metric tons per standard cubic meter. 

■ 56. Section 98.425 is amended by 

revising paragraph (a) introductory text; 

and by adding paragraph (d) to read as 

follows: 

§ 98.425 Procedures for estimating 

missing data. 

(a) Whenever the quality assurance 

procedures in § 98.424(a)(1) of this 

subpart cannot be followed to measure 

quarterly mass flow or volumetric flow 

of CO2, the most appropriate of the 

following missing data procedures shall 

be followed: 

* * * * * 

(d) Whenever the quality assurance 

procedures in § 98.424(a)(2) of this 

subpart cannot be followed to measure 

quarterly quantity of CO2 in containers, 

the most appropriate of the following 

missing data procedures shall be 

followed: 

(1) A quarterly quantity of CO2 in 

containers that is missing may be 

substituted with a quarterly value 

measured during another representative 

quarter of the current reporting year. 

(2) A quarterly quantity of CO2 in 

containers that is missing may be 

substituted with a quarterly value 

measured during the same quarter from 

the past reporting year. 

(3) The quarterly quantity of CO2 in 

containers recorded for purposes of 

product tracking and billing according 

to the reporter’s established procedures 

may be substituted for any period 

during which measurement equipment 

is inoperable. 

■ 57. Section 98.426 is amended by: 

■ a. Revising paragraphs (a) 

introductory text and (a)(2). 

■ b. Adding paragraph (a)(5). 

■ c. Revising paragraphs (b) 

introductory text, (b)(2), (b)(3), and 

(b)(4). 

■ d. Adding paragraph (b)(7). 

■ e. Revising paragraphs (c) and (e)(1). 

§ 98.426 Data reporting requirements. 

* * * * * 

(a) If you use Equation PP–1 of this 

subpart, report the following 

information for each mass flow meter or 

CO2 stream that delivers CO2 to 

containers: 

* * * * * 

(2) Quarterly mass in metric tons of 

CO2.

* * * * * 

(5) The location of the flow meter in 

your process chain in relation to the 

points of CO2 stream capture, 

dehydration, compression, and other 

processing. 

* * * * * 

(b) If you use Equation PP–2 of this 

subpart, report the following 

information for each volumetric flow 

meter or CO2 stream that delivers CO2

to containers: 

* * * * * 

(2) Quarterly volume in standard 

cubic meters of CO2.

(3) Quarterly concentration of the CO2

stream in volume or weight percent. 

(4) Report density as follows: 

(i) Quarterly density of CO2 in metric 

tons per standard cubic meter if you 

report the concentration of the CO2

stream in paragraph (b)(3) of this section 

in weight percent. 

(ii) Quarterly density of the CO2

stream in metric tons per standard cubic 

meter if you report the concentration of 

the CO2 stream in paragraph (b)(3) of 

this section in volume percent. 

* * * * * 

(7) The location of the flow meter in 

your process chain in relation to the 

points of CO2 stream capture, 

dehydration, compression, and other 

processing. 

(c) For the aggregated annual mass of 

CO2 emissions calculated using 

Equation PP–3a or PP–3b, report the 

following: 

(1) If you use Equation PP–3a of this 

subpart, report the annual CO2 mass in 

metric tons from all flow meters and 

CO2 streams that deliver CO2 to 

containers. 

(2) If you use Equation PP–3b of this 

subpart, report: 

(i) The total annual CO2 mass through 

main flow meter(s) in metric tons. 

(ii) The total annual CO2 mass 

through subsequent flow meter(s) in 

metric tons. 

(iii) The total annual CO2 mass 

supplied in metric tons. 

(iv) The location of each flow meter 

in relation to the point of segregation. 

* * * * * 

(e) * * * 

(1) The type of equipment used to 

measure the total flow of the CO2 stream 

or the total mass or volume in CO2

containers. 

* * * * * 

[FR Doc. 2010–30286 Filed 12–16–10; 8:45 am] 

BILLING CODE 6560–50–P 


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