Wednesday, 

August 11, 2010 

Part II 

Environmental 

Protection Agency 

40 CFR Part 98 

Mandatory Reporting of Greenhouse 

Gases; Proposed Rule 


srobinson on DSKHWCL6B1PROD with PROPOSALS2
48744 Federal Register / Vol. 75, No. 154 / Wednesday, August 11, 2010 / Proposed Rules 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 98 

[EPA–HQ–OAR–2008–0508; FRL–9179–8] 

RIN 2060–AQ33 

Mandatory Reporting of Greenhouse 

Gases 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Proposed Rule. 

SUMMARY: EPA is proposing to amend 

specific provisions in the GHG reporting 

rule to clarify certain provisions, to 

correct technical and editorial errors, 

and to address certain questions and 

issues that have arisen since 

promulgation. These proposed changes 

include providing additional 

information and clarity on existing 

requirements, allowing greater 

flexibility or simplified calculation 

methods for certain sources in a facility, 

amending data reporting requirements 

to provide additional clarity on when 

different types of GHG emissions need 

to be calculated and reported, clarifying 

terms and definitions in certain 

equations, and technical corrections. 

DATES: Comments. Comments must be 

received on or before September 27, 

2010. 

Public Hearing. EPA does not plan to 

conduct a public hearing unless 

requested. To request a hearing, please 

contact the person listed in the FOR

FURTHER INFORMATION CONTACT section 

by August 18, 2010. If requested, the 

hearing will be conducted August 26, 

2010, at 1310 L St., NW., Washington, 

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

EPA will provide further information 

about the hearing on its Web page if a 

hearing is requested. 

ADDRESSES: You may submit your 

comments, identified by docket ID No. 

EPA–HQ–OAR–2008–0508 by any of the 

following methods: 

• Federal eRulemaking Portal: http:// 

www.regulations.gov. Follow the online 

instructions for submitting comments. 

• E-mail: MRR_Revisions@epa.gov. 

Include docket ID No. EPA–HQ–OAR– 

2008–0508 [and/or RIN number 2060– 

aq33] in the subject line of the message. 

• Fax: (202) 566–1741. 

• Mail: Environmental Protection 

Agency, EPA Docket Center (EPA/DC), 

Mailcode 2822T, Attention Docket ID 

No. EPA–HQ–OAR–2008–0508, 1200 

Pennsylvania Avenue, NW., 

Washington, DC 20004. 

• Hand/Courier Delivery: EPA Docket 

Center, Public Reading Room, EPA West 

Building, Room 3334, 1301 Constitution 

Avenue, NW., Washington, DC 20004. 

Such deliveries are only accepted 

during the Docket’s normal hours of 

operation, and special arrangements 

should be made for deliveries of boxed 

information. 

Instructions: Direct your comments to 

Docket ID No. EPA–HQ–OAR–2008– 

0508, Revision of Certain GHGMRR 

Provisions and Other Corrections. EPA’s 

policy is that all comments received 

will be included in the public docket 

without change and may be made 

available online at http:// 

www.regulations.gov, including any 

personal information provided, unless 

the comment includes information 

claimed to be confidential business 

information (CBI) or other information 

whose disclosure is restricted by statute. 

Do not submit information that you 

consider to be CBI or otherwise 

protected through http:// 

www.regulations.gov or e-mail. The 

http://www.regulations.gov Web site is 

an ‘‘anonymous access’’ system, which 

means EPA will not know your identity 

or contact information unless you 

provide it in the body of your comment. 

If you send an e-mail comment directly 

to EPA without going through http:// 

www.regulations.gov your e-mail 

address will be automatically captured 

and included as part of the comment 

that is placed in the public docket and 

made available on the Internet. If you 

submit an electronic comment, EPA 

recommends that you include your 

name and other contact information in 

the body of your comment and with any 

disk or CD–ROM you submit. If EPA 

cannot read your comment due to 

technical difficulties and cannot contact 

you for clarification, EPA may not be 

able to consider your comment. 

Electronic files should avoid the use of 

special characters, any form of 

encryption, and be free of any defects or 

viruses. 

Docket: All documents in the docket 

are listed in the http:// 

www.regulations.gov index. Although 

listed in the index, some information is 

not publicly available, e.g., CBI or other 

information whose disclosure is 

restricted by statute. Certain other 

material, such as copyrighted material, 

will be publicly available only in hard 

copy. Publicly available docket 

materials are available either 

electronically in http:// 

www.regulations.gov or in hard copy at 

the Air Docket, EPA/DC, EPA West 

Building, Room 3334, 1301 Constitution 

Ave., NW., Washington, DC. This 

Docket Facility is open from 8:30 a.m. 

to 4:30 p.m., Monday through Friday, 

excluding legal holidays. The telephone 

number for the Public Reading Room is 

(202) 566–1744, and the telephone 

number for the Air Docket is (202) 566– 

1742. 

FOR FURTHER GENERAL INFORMATION

CONTACT: Carole Cook, Climate Change 

Division, Office of Atmospheric 

Programs (MC–6207J), Environmental 

Protection Agency, 1200 Pennsylvania 

Ave., NW., Washington, DC 20460; 

telephone number: (202) 343–9263; fax 

number: (202) 343–2342; e-mail address: 

GHGReportingRule@epa.gov. For 

technical information contact the 

Greenhouse Gas Reporting Rule Hotline 

at telephone number: (877) 444–1188; or 

e-mail: ghgmrr@epa.gov. To obtain 

information about the public hearings or 

to register to speak at the hearings, 

please go to http://www.epa.gov/

climatechange/emissions/

ghgrulemaking.html. Alternatively, 

contact Carole Cook at 202–343–9263. 

Worldwide Web (WWW). In addition 

to being available in the docket, an 

electronic copy of today’s proposal will 

also be available through the WWW. 

Following the Administrator’s signature, 

a copy of this action will be posted on 

EPA’s greenhouse gas reporting rule 

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

change/emissions/ghgrulemaking.html. 

SUPPLEMENTARY INFORMATION: 

Additional Information on Submitting 

Comments: To expedite review of your 

comments by Agency staff, you are 

encouraged to send a separate copy of 

your comments, in addition to the copy 

you submit to the official docket, to 

Carole Cook, U.S. EPA, Office of 

Atmospheric Programs, Climate Change 

Division, Mail Code 6207–J, 

Washington, DC 20460, telephone (202) 

343–9263, e-mail address: 

GHGReportingRule@epa.gov. 

Regulated Entities. The Administrator 

determined that this action is subject to 

the provisions of Clean Air Act (CAA) 

section 307(d). See CAA section 

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

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

the Administrator may determine’’). 

These are proposed amendments to 

existing regulations. If finalized, these 

amended regulations would affect 

owners or operators of certain fossil fuel 

and industrial gas suppliers, and direct 

emitters of GHGs. Regulated categories 

and entities include those listed in 

Table 1 of this preamble: 


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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. 

Iron and Steel Production ...... 331111 Integrated iron and steel mills, steel companies, sinter plants, blast furnaces, basic oxygen process furnace shops. 

Lead Production ..................... 331419 Primary lead smelting and refining facilities. 

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

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

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 Management1 ........... 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. 

1EPA will not be implementing subpart JJ of Part 98 using funds provided in its FY2010 appropriations due to a Congressional restriction prohibiting the expenditure of funds for this purpose. 


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1Consolidated Appropriations Act, 2008, Public 

Law 110–161, 121 Stat. 1844, 2128. 

Table 1 of this preamble is not 

intended to be exhaustive, but rather 

provides a guide for readers regarding 

facilities likely to be affected by this 

action. Table 1 of this preamble lists the 

types of facilities that EPA is now aware 

could potentially be affected by the 

reporting requirements. Other types of 

facilities than those listed in the table 

could also be subject to reporting 

requirements. To determine whether 

you are affected by this action, you 

should carefully examine the 

applicability criteria found in 40 CFR 

part 98, subpart A or the relevant 

criteria in the sections related to fossil 

fuel and industrial gas suppliers, and 

direct emitters of GHGs. If you have 

questions regarding the applicability of 

this action to a particular facility, 

consult the person listed in the 

preceding FOR FURTHER GENERAL

INFORMATION CONTACT Section. 

Acronyms and Abbreviations. The 

following acronyms and abbreviations 

are used in this document. 

ACC American Chemistry Council 

AGA American Gas Association 

API American Petroleum Institute 

ARP Acid Rain Program 

ASME American Society of Mechanical 

Engineers 

ASTM American Society for Testing and 

Materials 

BAMM best available monitoring method 

Btu/scf British thermal unit per standard 

cubic foot 

CAA Clean Air Act 

CAIR Clean Air Interstate Rule 

CBI confidential business information 

cc cubic centimeters 

CE calibration error 

CEMS continuous emission monitoring 

system 

CFR Code of Federal Regulations 

CGA Cylinder gas audit 

CH4 methane 

CO carbon monoxide 

CO2 carbon dioxide 

CO2e CO2-equivalent 

CWPB center worked prebake 

EGU electricity generating unit 

EIA Energy Information Administration 

EO Executive Order 

EPA U.S. Environmental Protection Agency 

ERC Energy Recovery Council 

FGD flue gas desulfurization 

FR Federal Register 

FTIR fourier transform infrared 

GC gas chromatography 

GHG greenhouse gas 

GPA Gas Processors Association 

GWP global warming potential 

HCl hydrogen chloride 

HHV high heat value 

HSS horizontal stud 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 

MWC municipal waste combustor 

NESHAP National Emission Standards for 

Hazardous Air Pollutants 

NIST National Institute of Standards and 

Technology 

NMR nuclear magnetic resonance 

NSPS New Source Performance Standards 

N2O nitrous oxide 

NAICS North American Industry 

Classification System 

NGLs natural gas liquids 

O2 oxygen 

O&M operation and maintenance 

OMB Office of Management and Budget 

PFC perfluorocarbon 

psia pounds per square inch absolute 

QA quality assurance 

QA/QC quality assurance/quality control 

RATA relative accuracy test audit 

RFA Regulatory Flexibility Act 

RFG Refinery fuel gas 

RGGI Regional Greenhouse Gas Initiative 

scf standard cubic feet 

scfm standard cubic feet per minute 

SO2 sulfur dioxide 

SWPB side worked prebake 

U.S. United States 

UMRA Unfunded Mandates Reform Act of 

1995 

VSS vertical stud S<derberg 

Table of Contents 

I. Background 

A. How is this preamble organized? 

B. Background on This Action 

C. Legal Authority 

D. How would these amendments apply to 

2011 reports? 

II. Revisions and Other Amendments 

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 

I. Background 

A. How is this preamble organized? 

The first section of this preamble 

contains the basic background 

information about the origin of these 

proposed rule amendments and request 

for public comment. This section also 

discusses EPA’s use of our legal 

authority under the Clean Air Act to 

collect data on GHGs. 

The second section of this preamble 

describes in detail the changes that are 

being proposed to correct technical 

errors or to address implementation 

issues identified by EPA and others. 

This section also presents EPA’s 

rationale for the proposed changes and 

identifies issues on which EPA is 

particularly interested in receiving 

public comments. 

Finally, the last (third) section 

discusses the various statutory and 

executive order requirements applicable 

to this proposed rulemaking. 

B. Background on This Action 

The final Part 98 was signed by EPA 

Administrator Lisa Jackson on 

September 22, 2009 and published in 

the Federal Register on October 30, 

2009 (74 FR 56260–56519, October 30, 

2009). Part 98, which became effective 

on December 29, 2009, included 

reporting of GHG information from 

facilities and suppliers, consistent with 

the 2008 Consolidated Appropriations 

Act. 1 These source categories capture 

approximately 85 percent of U.S. GHG 

emissions through reporting by direct 

emitters as well as suppliers of fossil 

fuels and industrial gases. 

This is the second time that EPA has 

published a notice proposing 

amendments to Part 98 to, among other 

things, correct certain technical and 

editorial errors that have been identified 

since promulgation and clarify or 


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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. 

propose amendments to certain 

provisions that have been the subject of 

questions from reporting entities. The 

first proposal was published on June 15, 

2010 (75 FR 33950). This proposal 

complements the proposal published on 

June 15, 2010 and is not intended to 

duplicate or replace the proposed 

amendments published on June 15, 

2010. We are seeking public comment 

only on the issues specifically identified 

in this proposal for the identified 

subparts. We will not respond to any 

comments addressing other aspects of 

Part 98 or any other related 

rulemakings. 

C. Legal Authority 

EPA is proposing these rule 

amendments under its existing CAA 

authority, specifically authorities 

provided in section 114 of the CAA. 

As stated in the preamble to the final 

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

CAA section 114 provides EPA broad 

authority to require the information 

proposed to be gathered by Part 98 

because such data would inform and are 

relevant to EPA’s obligation to carry out 

a wide variety of CAA provisions. As 

discussed in the preamble to the initial 

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

section 114(a)(1) of the CAA authorizes 

the Administrator to require emissions 

sources, persons subject to the CAA, 

manufacturers of control equipment, or 

persons whom the Administrator 

believes may have necessary 

information to monitor and report 

emissions and provide such other 

information the Administrator requests 

for the purposes of carrying out any 

provision of the CAA. For further 

information about EPA’s legal authority, 

see the preambles to the proposed and 

final rule, and Response to Comments 

Documents.2

D. How would these amendments apply 

to 2011 reports? 

EPA is planning to address the 

comments on these proposed 

amendments and publish the final 

amendments before the end of 2010. 

Therefore, reporters would be expected 

to calculate emissions and other 

relevant data for the reports that are 

submitted in 2011 using Part 98, as 

amended by this and the other revisions 

package (75 FR 33950), as finalized. We 

have determined that it is feasible for 

the sources to implement these changes 

for the 2010 reporting year since the 

revisions primarily provide additional 

clarifications or flexibility regarding the 

existing regulatory requirements, 

generally do not affect the type of 

information that must be collected, and 

do not substantially affect how 

emissions are calculated. 

For example, many proposed 

revisions simply provide additional 

information and clarity on existing 

requirements. For example, we are 

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

to clarify that suppliers of industrial 

flourinated GHGs need to calculate and 

report GHG emissions in metric tons of 

CO2 equivalents (mtCO2e) only for those 

flourinated GHGs that are listed in Table 

A–1. This proposed clarification is 

consistent with clarifications we have 

issued in response to industry questions 

and would not change how facilities 

collected data during 2010. 

Some of the proposed amendments 

provide greater flexibility or simplified 

calculation methods for certain 

facilities. For example, we are proposing 

to amend subpart C by adding a new 

equation that would enable sources that 

receive natural gas billing data from 

their suppliers in therms to calculate 

CO2 mass emissions directly from the 

information on the billing records, 

without having to request or obtain 

additional data from the fuel suppliers. 

Some proposed amendments are to 

the data reporting requirements to 

provide additional clarity on when 

different types of GHG emissions need 

to be calculated and reported. For 

example, in subpart G, Ammonia 

Manufacturing, we are proposing to 

eliminate the calculation and reporting 

of CO2 emissions associated with the 

use of the waste recycle stream or 

‘‘purge’’ as fuel under subpart C because 

these emissions are already accounted 

for in the calculation of total process 

emissions in subpart G, which includes 

CO2 emissions resulting from the use of 

purge gas as a fuel. We have concluded 

that amendments such as these can be 

implemented for the reports submitted 

to EPA in 2011 because the proposed 

changes are consistent with the 

calculation methodologies already in 

part 98 and the owners or operators are 

not required to actually report until 

March 2011, several months after we 

expect this proposal to be finalized. 

For some subparts, we are proposing 

amendments to address issues identified 

as a result of working with the affected 

sources during rule implementation. 

These proposed revisions provide 

additional flexibility to the sources, or 

reduce the reporting burden. For 

example, in subparts X (Petrochemical 

Production) and Y (Petroleum 

Refineries), reporters have requested 

that allowance be made for alternative 

standard conditions within the molar 

volume conversion factor (MVC) used in 

various equations. Therefore, we are 

proposing to amend those subparts to 

include MVCs at standard conditions 

defined at both 60ßF or 68ßF, so the 

facilities will not have to make those 

corrections in their data. 

We are also proposing corrections to 

terms and definitions in certain 

equations. For example, in subpart Y, 

Petroleum Refineries, we are proposing 

to clarify in an equation that for coke 

calcining units that recycle the collected 

coke dust, the mass of coke dust 

removed from the process is the mass of 

coke dust collected less the mass of coke 

dust recycled to the process. These 

clarifications do not result in additional 

requirements; therefore, we have 

concluded that reporters can follow Part 

98, as amended, in submitting their first 

reports in 2011. 

Finally, we are proposing other 

technical corrections that have no 

impact on facility’s data collection 

efforts in 2010. For example, we are 

proposing to amend subpart C to remove 

a second copy of Table C–2 that was 

inadvertently included in the final Part 

98 published on October 30, 2009. 

In summary, these amendments 

would not require any additional 

monitoring or information collection 

above what was already included in Part 

98. Therefore, we expect that sources 

can use the same information that they 

have been collecting under the current 

version of Part 98 to calculate and report 

GHG emissions for 2010 and submit 

reports in 2011 under the amended Part 

98. 

We seek comment on the conclusion 

that it is appropriate to implement these 

amendments and incorporate the 

requirements in the data reported to 

EPA by March 31, 2011. Further, we 

seek comment on whether there are 

specific subparts of Part 98 for which 

this timeline may not be feasible or 

appropriate due to the nature of the 

proposed changes or the way in which 

data have been collected thus far in 

2010. We request that commenters 

provide specific examples of how the 

proposed implementation schedule 

would or would not work. 

II. Revisions and Other Amendments 

Following promulgation of Part 98, 

we have identified errors in the 

regulatory language that we are now 

proposing to correct. These errors were 

identified as a result of working with 

affected industries to implement the 

various subparts of Part 98. We have 

also identified certain rule provisions 

that should be amended to provide 

greater clarity. We are also proposing 

revisions to provide additional 


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flexibility for certain requirements 

based in part on our better 

understanding of various industries. 

Finally, we are also proposing to revise 

or remove certain applicability 

thresholds (for example for local 

distribution companies subject to 

subpart NN (Suppliers of Natural Gas 

and Natural Gas Liquids)) and 

monitoring thresholds and reporting 

requirements (for example for municipal 

solid waste combusters subject to 

subpart C (General Stationary Fuel 

Combustion) and for certain small 

sources subject to subpart X 

(Petrochemicals) or subpart Y 

(Petroleum Refineries)). The 

amendments we are now proposing 

include the following types of changes: 

• Changes to correct cross references 

within and between subparts. 

• Additional information to better or 

more fully understand compliance 

obligations in a specific provision, such 

as the reference to a standardized 

method that must be followed. 

• Amendments to certain equations to 

better reflect actual operating 

conditions. 

• Corrections to terms and definitions 

in certain equations. 

• Corrections to data reporting 

requirements so that they more closely 

conform to the information used to 

perform emission calculations. 

• Other amendments related to 

certain issues identified as a result of 

working with the affected sources 

during rule implementation and 

outreach. 

As mentioned above in section I of 

this preamble, we published an earlier 

proposed rulemaking proposing 

technical corrections and other 

amendments to Part 98 on June 15, 2010 

(75 FR 33950). This proposal 

complements the notice published on 

June 15, 2010 and is not intended to 

duplicate or replace the proposed 

amendments published on June 15, 

2010. We are seeking public comment 

only on the issues specifically identified 

in this notice for the identified subparts. 

We will not respond to any comments 

addressing other aspects of Part 98 or 

any other related rulemakings. 

A. Subpart A (General Provisions): Best 

Available Monitoring Methods 

Certain owners and operators in the 

more complex hydrogen, petrochemical, 

and petroleum refinery industries have 

expressed concerns regarding the timing 

of the requirements to install meters and 

other measurement devices to comply 

with Part 98. Specifically, they were 

concerned that the safe installation of 

required measurement devices requires 

detailed engineering and planning and, 

therefore, stated that EPA should 

provide sufficient time for designing 

and safely engineering instrumentation 

installations or upgrades. Further, they 

claimed that in continuously operated 

plants there is typically not a scheduled 

shutdown for an entire facility and unit 

maintenance and turnarounds are not an 

annual occurrence for all units. 

Reporters in these industries have 

asserted that EPA has properly 

recognized this operational reality in the 

context of instrument calibration by 

allowing calibration to be delayed until 

the next scheduled shutdown. The 

reporters have noted, however, that 

parallel requirements have not been 

developed for installation of monitoring 

devices. Specifically, they requested 

that EPA should provide approval 

criteria for extending the use of ‘‘best 

available monitoring methods’’ (BAMM) 

beyond December 31, 2010 for 

equipment installation. 

These types of concerns were the 

reason owners and operators were given 

the opportunity in Part 98 to request an 

extension from EPA to use BAMM 

beyond March 31, 2010 in situations 

where it was not reasonably feasible to 

acquire, install and operate the required 

monitoring equipment by that date. We 

recognize, however, that instances may 

occur where facilities subject to Part 98 

may not have been scheduled to 

shutdown during 2010, and requiring 

the facility to shutdown solely to install 

the required measurement devices 

during 2010 could impose an 

unnecessary burden. 

Therefore, we are proposing that a 

new petition process be established in a 

new paragraph 40 CFR 98.3(j) that 

would allow use of BAMM past 

December 31, 2010 for owners and 

operators required to report under 

subpart P (Hydrogen Production), 

subpart X (Petrochemicals Production), 

or subpart Y (Petroleum Refineries), 

under limited circumstances. We are 

proposing that owners or operators 

subject to these subparts could petition 

EPA to extend use of BAMM past 

December 31, 2010, if compliance with 

a specific provision in the regulation 

required measurement device 

installation, and installing the device(s) 

would necessitate an unscheduled 

process equipment or unit shutdown or 

could only be installed through a hot 

tap. If the petition is approved, the 

owner or operator could postpone 

installation of the measurement device 

until the next scheduled maintenance 

outage, but initially no later than 

December 31, 2013. If, in 2013, owners 

or operators still determine and certify 

that a scheduled shutdown will not 

occur by December 31, 2013, they may 

re-apply to use best available 

monitoring methods for an additional 

two years. 

The initial process for use of best 

available monitoring methods in Part 98 

ended December 31, 2010, because we 

concluded that it is important to 

establish a date by which all equipment 

must be installed and operating in order 

to ensure that consistent data are 

collected by all reporters. We maintain 

that it is important to have consistent 

methods being used by all reporters. 

However, we also recognize that some 

complex facilities have unique 

operating circumstances that justify 

additional flexibility. Therefore, 

although we are proposing to initially 

approve extension requests no later than 

December 31, 2013, owners or operators 

subject to these subparts would have a 

one time opportunity to re-apply for the 

extension request for an additional two 

years, with approval being granted no 

later than December 31, 2015. We 

believe that a date of December 31, 

2013, four years after the effective date 

of Part 98, would accommodate the 

shutdown schedules for most, if not all 

facilities subject to subparts P, X, and/ 

or Y. Because we recognize that all such 

facilities subject to Part 98 may not have 

a planned process equipment or unit 

shutdown prior to December 31, 2013, 

we have has concluded that it is 

reasonable to propose that owners or 

operators could re-apply one time for an 

additional two years. This timeline 

balances the need to gather consistent 

data, while recognizing the operational 

reality of such facilities. 

Process for Requesting an Extension 

of Best Available Monitoring Methods. 

We are proposing to add a similar 

petition process to that recently 

concluded for the use of BAMM for 

2010 in the new paragraph 40 CFR 

98.3(j). The process would be available 

solely for facilties subject to subparts P, 

X and/or Y, and solely for the 

installation of measurement devices that 

cannot be installed safely except during 

full process equipment or unit 

shutdown or through installation via a 

hot tap. BAMM would be allowable 

initially until December 31, 2013. 

Subpart P, X, and/or Y owners or 

operators requesting to use BAMM 

beyond 2010 would be required to 

electronically notify EPA by January 1, 

2011 that they intend to apply for 

BAMM for installation of measurement 

devices and certify that such installation 

would require a hot tap or unscheduled 

shutdown. 

Owners or operators would be 

required to submit the full extension 

request for BAMM by February 15, 

2011. The full extension requests would 


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include a description of the 

measurement devices that could not be 

installed in 2010 without a process 

equipment or unit shutdown, or through 

a hot tap, a clear explanation of why 

that activity would not be accomplished 

in 2010 with supporting material, an 

estimated date for the next planned 

maintenance outage, and a discussion of 

how emissions would be calculated in 

the interim. More specifically, the full 

extension request would need to 

identify the specific monitoring 

instrumentation for which the request is 

being made, indicate the locations 

where each piece of monitoring 

instrumentation will be installed, and 

note the specific rule requirements (by 

rule subpart, section, and paragraph 

numbers) for which the instrumentation 

is needed. The extension requests 

would also be required to include 

supporting documentation 

demonstrating that it is not practicable 

to isolate the equipment and install the 

monitoring instrument without a full 

process equipment or unit shutdown, or 

through a hot tap, as well as providing 

the dates of the three most recent 

process equipment or unit shutdowns, 

the typical frequency of shutdowns for 

the respective equipment or unit, and 

the date of the next planned shutdown. 

Once subpart P, X, and/or Y owners 

or operators have notified EPA of their 

plan to apply for BAMM for 

measurement device installation, by 

January 1, 2011, and subsequently 

submitted a full extension request, by 

February 15, 2011, they would 

automatically be able to use BAMM 

through June 30, 2011. All measurement 

devices would need to be installed by 

July 1, 2011 unless EPA approves the 

BAMM request before that date. 

Approval of Extension Requests. In an 

approval of an extension request, EPA 

would approve the extension itself, 

establish a date by which all 

measurement devices must be installed, 

and indicate the approved alternate 

method for calculating GHG emissions 

in the interim. 

If EPA approves an extension request, 

the owner/operator would have until 

the date approved by EPA to install any 

remaining meters or other measurement 

devices, however initial approvals 

would not grant extensions beyond 

December 31, 2013. An owner/operator 

that already received approval from EPA 

to use BAMM during part or all of 2010 

would be required to submit a new 

request for use of BAMM beyond 2010. 

Unless EPA has approved an extension 

request, all owners or operators that 

submit a timely request under this new 

proposed process for BAMM would be 

required to install all measurement 

devices by July 1, 2011. 

We recognize that occasionally a 

facility may plan a scheduled process 

equipment or unit shutdown and the 

installation of required monitoring 

equipment, but the date of the 

scheduled shutdown is changed. We are 

proposing to include a process by which 

owners or operators who had received 

an extension would have the 

opportunity to extend the use of BAMM 

beyond the date approved by EPA if 

they can demonstrate to the 

Administrator’s satisfaction that they 

are making a good faith effort to install 

the required equipment. At a minimum, 

facilities that determine that the date of 

a scheduled shutdown will be moved 

would be required to notify EPA within 

4 weeks of such a determination, but no 

later than 4 weeks before the date of 

which the planned shutdown was 

scheduled. 

One-time request to extend best 

available monitoring methods past 

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

or Y owners or operators determine that 

a scheduled shutdown will not occur by 

December 31, 2013, they would be 

required to re-apply to use best available 

monitoring methods for one additional 

time period, not to extend beyond 

December 31, 2015. To extend use of 

best available monitoring methods past 

December 13, 2013, owners or operators 

would be required to submit a new 

extension request by June 1, 2013 that 

contains the information required in 

proposed 40 CFR 98.3(j)(4). All owners 

or operators that submit a request under 

this paragraph to extend use of best 

available monitoring methods for 

measurement device installation would 

be required to install all measurement 

devices by December 31, 2013, unless 

the extension request under this 

paragraph is approved by EPA. 

We seek comment on this approach to 

extend the deadline for installation of 

measurement devices in cases where 

such installation would require an 

unscheduled process equipment or unit 

shutdown at a subpart P, X, and/or Y 

facility. The proposed approach is 

consistent with the language and intent 

in Part 98 to defer calibration of 

required monitors in order to avoid 

unnecessary and unplanned shutdowns. 

The proposed approach is also modeled 

after the provision to request EPA to use 

BAMM during 2010. We considered, but 

did not propose, limiting this provision 

to only those subpart P, X, and/or Y 

owners and operators who submitted a 

request for use of BAMM by January 28, 

2010. This option was considered based 

on an assumption that the full universe 

of reporters that had difficulty installing 

the necessary measurement devices 

according to the schedule in the rule 

would have already submitted a request 

for the use of BAMM in 2010. We still 

believe that all owners or operators that 

required a process equipment or unit 

shutdown to install measurement 

devices should have submitted an 

extension request to EPA by January 28, 

2010. Nevertheless, we also recognize 

that this is a new regulation and 

facilities subject to Part 98 are making 

good faith efforts to understand all 

requirements. After careful 

consideration we are proposing to 

initiate a new process for BAMM, 

providing all facilties with units subject 

to subpart P, subpart X or subpart Y the 

opportunity to apply. 

We are proposing to limit the 

provision to facilities with units subject 

to one or more of these three subparts 

because, based on questions received 

during implementation, the concerns 

raised about installation of 

measurement devices necessitating 

process equipment or unit shutdown 

have been from facilities subject to these 

subparts. A clear case was not presented 

by other industries as to any unique 

circumstances in those industries (e.g., 

safety concerns associated with 

installation of measurement devices, 

frequency of shutdowns, complexities 

associated with shutting down, etc.) that 

might necessitate extending the 

deadline for BAMM for these other 

industries. We are seeking comment on 

this conclusion and whether there are 

other facilities beyond these subparts P, 

X, and Y that would need a shutdown, 

or a hot tap, in order to install the 

required measurement devices. If 

providing comments, please provide 

information on additional subparts, if 

any, that would need this flexibility, 

and include information on why 

installation could not be done in the 

absence of such a shutdown or why 

such shutdowns did not or could not 

occur in 2010 without unreasonable 

burden on the facility. 

We are generally seeking comment on 

this new petition process for BAMM. 

B. Subpart A (General Provisions): 

Calibration Requirements 

Since the rule was published on 

October 30, 2009, EPA has received 

numerous questions about the intent 

and extent of the equipment calibration 

requirements specified in 40 CFR 

98.3(i). The current rule could be 

interpreted to require all types of 

measurement equipment that provide 

data for the GHG emissions calculations, 

including flow meters and ‘‘other 

devices’’ such as belt scales, to be 


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48750 Federal Register / Vol. 75, No. 154 / Wednesday, August 11, 2010 / Proposed Rules 

calibrated to a specified accuracy (i.e., 

5.0 percent in most cases). 

The perceived universal nature of the 

calibration requirements in 40 CFR 

98.3(i) has caused a great deal of 

concern in the regulated community. 

For example, the appropriateness of a 

5.0 percent accuracy specification for a 

wide variety of measurement devices 

has been questioned. Specifically, 

reporters have recommended that the 

initial and on-going calibration 

requirements be modified to allow the 

accuracy to be determined within an 

appropriate error range for each 

measurement technology, based on an 

applicable standard. 

Also, for small combustion units 

using the Tier 1 or Tier 2 CO2

calculation methodologies in 40 CFR 

98.33(a), reporters were concerned that 

the calibration requirements and 

accuracy specifications appear to apply 

to flow meters that are used to quantify 

liquid and gaseous fuel usage. This 

contradicts the clear statements in the 

nomenclature of Equations C–1 and C– 

2a of Subpart C that company records 

can be used to measure fuel 

consumption for Tier 1 and 2 units. We 

note that the definition of ‘‘company 

records’’ in 40 CFR 98.6 is quite flexible 

and it does not require that any 

particular calibration methods be used 

or that specific accuracy percentages be 

met. 

In view of these considerations, we 

are proposing to amend 40 CFR 98.3(i) 

as follows, to more clearly define the 

scope of the calibration requirements: 

(a) We are proposing to amend 40 CFR 

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

accuracy requirements of 40 CFR 

98.3(i)(2) and (i)(3) would be required 

only for flow meters that measure liquid 

and gaseous fuel feed rates, feedstock 

flow rates, or process stream flow rates 

that are used in the GHG emissions 

calculations, and only when the 

calibration accuracy requirement is 

specified in an applicable subpart of 

Part 98. For instance, the QA/QC 

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

Subpart C require all flow meters that 

measure liquid and gaseous fuel flow 

rates for the Tier 3 CO2 calculation 

methodology to be calibrated according 

to 40 CFR 98.3(i); therefore, the 

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

and (i)(3) would continue to apply to 

these meters. EPA has many years of 

experience with fuel flow meter 

calibration, for example in the Acid 

Rain and NOX Budget Programs, and the 

Agency is confident that the accuracy 

requirements specified in 40 CFR 98.3(i) 

are both reasonable and achievable for 

such meters. For more information 

please refer to the Background 

Technical Support Document at EPA– 

HQ–OAR–2008–0508. We are also 

proposing to add statements to 40 CFR 

98.3(i) to clarify that the calibration 

accuracy specifications of 40 CFR 

98.3(i)(2) and (i)(3) do not apply where 

the use of company records or the use 

of best available information is specified 

to quantify fuel usage or other 

parameters, nor do they apply to sources 

that use Part 75 methodologies to 

calculate CO2 mass emissions because 

the Part 75 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. 

(b) We are proposing to further amend 

40 CFR 98.3(i)(1) to clarify that the 

calibration accuracy specifications in 40 

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

other measurement devices (e.g., 

weighing devices) that provide data for 

the GHG emissions calculations. Rather, 

these devices would have to be 

calibrated to meet the accuracy 

requirements of the relevant subpart(s), 

or, in the absence of such requirements, 

to meet appropriate, technology-based 

error-limits, such as industry consensus 

standards or manufacturer’s accuracy 

specifications. Consistent with 40 CFR 

98.3(g)(5)(i)(C), the procedures and 

methods used to quality-assure the data 

from the measurement devices would be 

documented in the written monitoring 

plan. 

(c) We are proposing to add a new 

paragraph 40 CFR 98.3(i)(1)(ii) to clarify 

that flow meters and other measurement 

devices need to be installed and 

calibrated by the date on which data 

collection needs to begin, if a facility or 

supplier becomes subject to Part 98 after 

April 1, 2010. 

(d) We are proposing to add a new 

paragraph 40 CFR 98.3(i)(1)(iii) to 

specify the frequency at which 

subsequent recalibrations of flow meters 

and other measurement devices need to 

be performed. Recalibration would be at 

the frequency specified in each 

applicable subpart, or at the frequency 

recommended by the manufacturer or 

by an industry consensus standard 

practice, if no recalibration frequency 

was specified in an applicable subpart. 

(e) We are proposing to specify the 

consequences of a failed flow meter 

calibration in a new paragraph 40 CFR 

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

prospectively, beginning at the hour of 

the failed calibration and continuing 

until a successful calibration is 

completed. Appropriate substitute data 

values would be used during the period 

of data invalidation. 

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

proposing to add absolute value signs to 

the numerators of Equations A–2 and 

A–3. These were inadvertently omitted 

in the October 30, 2009 Part 98. 

(g) We are proposing to amend 40 CFR 

98.3(i)(3) to increase the alternative 

accuracy specification for orifice, 

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

arithmetic sum of the three transmitter 

calibration errors (CE) at each 

calibration level) from 5.0 percent to 6.0 

percent, since each transmitter is 

individually allowed an accuracy of 2.0 

percent. We are also proposing to 

amend 40 CFR 98.3(i)(3) for orifice, 

nozzle, and venturi flow meters to 

account for cases where not all three 

transmitters for total pressure, 

differential pressure, and temperature 

are located in the vicinity of a flow 

meter’s primary element. Instead of 

being required to install additional 

transmitters, reporters would, as 

described below, conditionally be 

allowed to use assumed values for 

temperature and/or total pressure based 

on measurements of these parameters at 

remote locations. If only two of the three 

transmitters are installed and an 

assumed value is used for temperature 

or total pressure, the maximum 

allowable calibration error would be 4.0 

percent. If two assumed values are used 

and only the differential pressure 

transmitter is calibrated, the maximum 

allowable calibration error would be 2.0 

percent. We note that the use of an 

arithmetic sum of the calibration errors 

is consistent with the approach in Part 

75, and is designed to introduce 

flexibility, by allowing the results of a 

calibration to be accepted as valid when 

the calibration error of one (or in some 

cases, two) of the transmitters exceeds 

2.0 percent. We did not intend to 

introduce an uncertainty analysis, such 

as the square root of the sum of the 

squares, for quantifying uncertainty. 

We are also proposing to amend 40 

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

that must be met in order for a source 

to use assumed values for temperature 

and/or total pressure at the flow meter 

location, based on measurements of 

these parameters at a remote location (or 

locations). 

• The owner or operator would have 

to demonstrate that the remote readings, 

when corrected, are truly representative 

of the actual temperature and/or total 

pressure at the flow meter location, 

under all expected ambient conditions. 

Pressure and temperature surveys could 

be performed to determine the 

difference between the readings 

obtained with the remote transmitters 


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and the actual conditions at the flow 

meter location. 

• All temperature and/or total 

pressure measurements in the 

demonstration must be made with 

calibrated gauges, sensors, transmitters, 

or other appropriate measurement 

devices. 

• The methods used for the 

demonstration, along with the data from 

the demonstration, supporting 

engineering calculations (if any), and 

the mathematical relationship(s) 

between the remote readings and the 

actual flow meter conditions derived 

from the demonstration data would 

have to be documented in the 

monitoring plan for the unit and 

maintained in a format suitable for 

auditing and inspection. 

• The temperature and/or total 

pressure at the flow meter must be 

calculated on a daily basis from the 

remotely measured values, and the 

measured flow rates must then be 

corrected to standard conditions. 

• The mathematical correlation(s) 

between the remote readings and actual 

flow meter conditions must be checked 

at least once a year, and any necessary 

adjustments must be made to the 

correlation(s) going forward. 

(h) We are proposing to amend 40 

CFR 98.3(i)(4) to include an additional 

exemption from the calibration 

requirements of 40 CFR 98.3(i) for flow 

meters that are used exclusively to 

measure the flow rates of fuels used for 

unit startup or ignition. For instance, a 

meter that is used only to measure the 

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

gas) to a coal-fired unit would be 

exempted. This proposed revision is 

modeled after a similar calibration 

exemption in section 2.1.4.1 of 

Appendix D to 40 CFR Part 75, for fuel 

flow meters that measure startup and 

ignition fuels. The amount of fuel used 

for ignition and startup generally 

provides a very small percentage of the 

annual unit heat input (less than 1 

percent in most cases). Therefore, 

rigorous calibration of meters used 

exclusively for startup and ignition fuels 

is unnecessary. Paragraph 98.3(i)(4) 

would be further amended to clarify that 

gas billing meters are exempted from the 

monitoring plan and record keeping 

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

(g)(7), which require, respectively, that 

a description of the methods used to 

quality-assure data from instruments 

used to provide data for the GHG 

emissions calculations be included in 

the written monitoring plan, and that 

maintenance records be kept for those 

instruments. We are proposing these 

changes because operation, 

maintenance, and quality assurance of 

gas billing meters is the responsibility of 

the fuel supplier, not the consumer. 

(i) We are proposing to amend 40 CFR 

98.3(i)(5) to clarify that flow meters that 

were already calibrated according to 40 

CFR 98.3(i)(1) following a 

manufacturer’s recommended 

calibration schedule or an industry 

consensus calibration schedule do not 

need to be recalibrated by the date 

specified in 40 CFR 98.3(i)(1) as long as 

the flow meter is still within the 

recommended calibration interval. This 

paragraph would also be amended to 

clarify that the deadline for successive 

calibrations would be according to the 

a manufacturer’s recommended 

calibration schedule or an industry 

consensus calibration schedule. 

(j) We are proposing to amend 40 CFR 

98.3(i)(6) to account for units and 

processes that operate continuously 

with infrequent outages and cannot 

meet the flow meter calibration deadline 

without disrupting normal process 

operation. Part 98 currently allows the 

owner or operator to postpone the initial 

calibration until the next scheduled 

maintenance outage. The rule did not 

require shutdown for calibration of 

equipment because it was determined to 

be an unnecessary burden to require 

shutdown for calibration given that all 

measurement equipment required for 

GHG emissions would be required to be 

calibrated if they did not have an active 

calibration, necessitating a potentially 

large number of shutdowns. 

Although the rule allows 

postponement of calibration, it does not 

specify how to report fuel consumption 

for the entire time period extending 

from January 1, 2010 until the next 

maintenance outage. Section 98.3(d) of 

subpart A allows sources to use the 

‘‘best available monitoring methods’’ 

(BAMM) until April 1, 2010, and to 

petition the Administrator to continue 

using the BAMM through December 31, 

2010, but not beyond that date. 

In view of this, we are proposing to 

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

sources to use the best available data 

from company records to quantify fuel 

usage until the next scheduled 

maintenance outage. This proposed 

revision would address situations where 

the next scheduled outage is in 2011, or 

later. 

C. Subpart A (General Provisions): 

Reporting of Biogenic Emissions 

Reporters have noted that in the final 

Part 98 a new requirement was 

introduced that requires separate 

reporting of biogenic emissions from 

facilities (40 CFR 98.3(c)). They have 

noted that had EPA sought comment on 

this requirement in the proposal, they 

may have commented that units subject 

to subpart D (Electricity Generation) 

should not be required to report 

biogenic emissions separately, as this is 

not currently required under Part 75, 

which generally established the 

procedures for measuring data under 

subpart D. Or, they may have 

recommended specific methods for 

calculating biogenic emissions from Part 

75 units. Owners and operators have 

stated that it is not clear in Part 98 

which method is required for estimating 

these emissions from units subject to 

subpart D. 

EPA has subsequently provided 

guidance that separate reporting of 

biogenic emissions for units subject to 

subpart D is optional; however, in order 

to provide clarity and remove any 

potential inconsistencies, we are 

proposing revisions to subpart A and 

soliciting comment. 

We intended that units subject to 

subpart D would continue to monitor 

and report CO2 mass emissions as 

required under 40 CFR 75.13 or section 

2.3 of apppendix G to 40 CFR part 75, 

and 40 CFR 75.64. These provisions do 

not require separate accounting of 

biogenic emissions, and we did not 

intend to require additional accounting 

methods for these units under Part 98. 

We intended for the reporting of 

biogenic CO2 emissions to be optional 

for units subject to subpart D. However, 

the current rule does not consistently 

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

A requires sources to report facilitywide GHG emissions, excluding 

biogenic CO2, and to report CO2

emissions for each source category 

excluding biogenic CO2. To meet these 

reporting requirements, facilities with 

subpart D and/or other Part 75 units onsite would have to separately account 

for the biogenic CO2 emissions (if any) 

from those units. 

To address these concerns, we are 

proposing to amend the data elements 

in subparts A and C that currently 

require separate accounting and 

reporting of biogenic CO2 emissions so 

that it would be optional for Part 75 

units. All units, except Part 75 units, 

would still be required to calculate and 

report biogenic CO2 emissions 

separately under subpart C. We are 

proposing to amend the following 

sections of subparts A and C to reflect 

these changes: 

• 40 CFR 98.3(c)(4)(i) would be 

revised to no longer require facilities to 

report annual emissions, excluding 

biogenic CO2; instead, it would require 

all owners or operators to report annual 

facility-wide emissions, including 

biogenic CO2. 


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• 40 CFR 98.3(c)(4)(ii) and 

(c)(4)(iii)(A) would be amended to state 

that separate reporting of biogenic CO2

emissions is not required for units using 

part 75 methodologies to calculate CO2

mass emissions. 

• 40 CFR 98.3(c)(4)(ii)(B) would be 

revised to no longer require reporting of 

the annual CO2 emissions from subparts 

C through JJ, excluding biogenic CO2; 

instead, it would require reporting of 

the total annual CO2 emissions for each 

subpart, including biogenic CO2.

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

redesignated as 40 CFR 98.33(a)(5)(iv) 

and amended to state that separate 

reporting of biogenic CO2 emissions is 

optional for part 75 units that qualify for 

and elect to use the alternative CO2

mass emissions reporting options in 40 

CFR 98.33(a)(5). 

• A statement would be added to 40 

CFR 98.33(e) to indicate that separate 

reporting of biogenic CO2 emissions is 

not required for units subject to subpart 

D of part 98, and for part 75 units using 

the alternative CO2 mass emissions 

reporting options in 40 CFR 98.33(a)(5). 

However, if the owner or operator elects 

to report biogenic CO2 emissions, the 

methods in § 98.33(e) would be used. 

• Three paragraphs of the data 

reporting section of subpart C, 

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

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

amended to reinforce that separate 

reporting of biogenic CO2 emissions is 

optional for part 75 units. 

The proposed amendments would not 

affect the burden for existing facilities, 

as existing non-Part 75 facilities were 

always required to calculate and report 

biogenic emissions separately. The 

amendments would simply require 

them to include those biogenic 

emissions in facility-wide and source 

category (subpart) totals, as opposed to 

subtracting them out. The proposed 

amendments would also address the 

inconsistency that appeared in Part 98 

regarding separate reporting of biogenic 

emissions for electric generating units 

subject to subpart D or other units 

subject to Part 75, as these facilities 

would no longer be required to report 

facility emissions excluding biogenic 

CO2, although they retain the option to 

report biogenic CO2 separately. 

D. Subpart A (General Provisions): 

Requirements for Correction and 

Resubmission of Annual Reports 

Subpart A requires that an ‘‘owner or 

operator shall submit a revised report 

within 45 days of discovering or being 

notified by EPA of errors in an annual 

GHG report. The revised report must 

correct all identified errors. The owner 

or operator shall retain documentation 

for 3 years to support any revisions 

made to an annual GHG report.’’ 

Some owners and operators have 

asserted that the requirements for 

resubmission of annual reports within 

45 days of discovering an error or being 

notified by EPA of an error, and the 

requirement to correct all errors, is 

overly broad and could trigger a 

resubmission for virtually any error. 

They were also concerned that these 

requirements are made more 

burdensome by the fact that the data 

system is not yet developed, and some 

identified ‘‘errors’’ may not in fact be 

errors, but rather software bugs that are 

most likely to happen in the first year 

of operation of the data system. They 

have also observed that the regulatory 

requirement is more burdensome than 

the Acid Rain Program (ARP), which 

has operated for more than 15 years 

without such a requirement in the 

regulation. 

We included this correction 

requirement in Part 98 because we 

determined that it is important to ensure 

that the most accurate data are available, 

in a timely fashion, for developing 

future GHG policies and programs. 

Generally, adding a requirement to 

resubmit data is also consistent with 

other EPA reporting programs, such as 

the ARP and the Toxic Release 

Inventory, as well as State and other 

GHG programs. While it is true that the 

ARP does not have a specific time 

requirement for resubmission in the 

regulation, in practice revised data have 

been submitted in less than 45 days 

after notification or identification of an 

error. While we maintain that it is 

important to retain a deadline for 

resubmission of the report after an error 

is identified in order to ensure EPA 

receives timely submission of data, we 

also recognize that certain 

circumstances may exist in which 

owners or operators cannot correct the 

identified errors within the 45 days. 

Therefore, we are proposing to amend 

40 CFR 98.3(h) to clarify how a 

resubmission is triggered and the 

process for resubmitting annual GHG 

reports. 

First, reports would only have to be 

resubmitted when the owner or operator 

or the Administrator determines that a 

substantive error exists. A substantive 

error would be defined as one that 

impacts the quantity of GHG emissions 

reported or otherwise prevents the 

reported data from being validated or 

verified. This clarification is important 

because some errors are not significant 

(e.g., an error in the zip code) and do 

not impact emissions. Such ‘‘errors’’ 

would not obligate the owner or 

operator to resubmit the annual report. 

The owner or operator would be 

required to resubmit the report within 

45 days of identifying the substantive 

error, or the Administrator notifying 

them of a substantive error, unless the 

owner or operator provides information 

demonstrating that the previously 

submitted report does not contain the 

identified substantive error or that the 

identified error is not a substantive 

error. This proposed change would 

provide owners or operators the 

opportunity to demonstrate that what 

the Administrator has deemed to be 

substantive errors are not, in fact, 

substantive errors. 

Finally, we are also proposing to 

introduce the opportunity for owners or 

operators to request an extension on the 

45-day resubmission deadline to 

address 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 or operators would be 

required to notify EPA by e-mail at least 

two business days prior to the end of the 

45-day resubmission deadline if they 

seek an extension. An automatic 30-day 

extension would be granted if EPA does 

not respond to the extension request by 

the end of the 45-day period. 

We are proposing the opportunity to 

extend the period for resubmission in 

recognition that the data system is still 

under development and we do not yet 

fully know the full range of errors that 

will be identified, and therefore the time 

required to address such errors. 

Verification and quality assurance and 

quality control checks are currently 

under development in the data system. 

Some flags that the data system might 

generate will not necessarily reflect 

substantive errors, but rather would be 

flags to alert the owner or operator to 

review the submission carefully to make 

sure the information provided is correct. 

On the other hand, some flags could 

identify substantive errors that affect the 

overall GHG emissions reported to EPA. 

Although we have concluded that it is 

important to provide facilities the 

opportunity to extend this deadline, we 

believe that the 45-day time period is a 

sufficient time period for the vast 

majority of facilities. 

E. Subpart A (General Provisions): 

Information To Record for Missing Data 

Events 

Certain reporters have suggested that 

the recordkeeping requirements related 

to missing data events are overly 

burdensome. Specifically, 40 CFR 

98.3(g)(4) of Part 98 specifies that the 

owner or operator must keep records of 

the cause and duration of each event, 

the actions taken to restore 


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malfunctioning monitoring equipment, 

and actions taken to prevent or 

minimize future occurrences. They have 

asserted that compared to Part 98, Part 

75 requires only reporting of the cause 

of the missing data event and the 

corrective actions taken, but does not 

require separate accounting of the 

duration of the event or the actions 

taken to minimize occurrence in the 

future. They have further claimed that 

most missing data events associated 

with the use of continuous emissions 

monitors are due to routine activities or 

calibration failures for which there are 

no clear measures to avoid similar 

occurrences in the future. Therefore, 

according to the owners and operators, 

the final recordkeeping requirements are 

overly burdensome and add little value. 

After reviewing these requirements, 

we agree with the claims and we are 

proposing to amend 40 CFR 98.3(g)(4) 

by requiring that records be kept of only 

the cause of each missing data event and 

the corrective actions taken. We have 

concluded that this information is 

sufficient for operating the program and 

that making this change will reduce the 

reporting burden for all reporters. This 

proposed revision would make the Part 

98 recordkeeping provisions for missing 

data events consistent with those in 40 

CFR Part 75 (specifically 40 CFR 

75.57(h)). We further propose to clarify 

that the records retained pursuant to 40 

CFR 75.57(h) may be used to meet the 

recordkeeping requirements under Part 

98 for the same missing data events. 

F. Subpart A (General Provisions): Other 

Technical Corrections and Amendments 

We are proposing several 

amendments to subpart A, as follows. 

We are proposing to amend 40 CFR 

98.3(c)(1) by adding a requirement to 

report a facility or supplier ID number. 

We expect to receive GHG emissions 

data in electronic format from 

thousands of facilities and suppliers. 

Therefore, a unique ID number must be 

assigned to each facility or supplier, for 

administrative purposes, to facilitate 

program implementation. This approach 

has worked well in other EPA programs 

that require electronic data reporting 

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

Acid Rain and NOX Budget Programs). 

The exact mechanism for assigning the 

ID numbers has not yet been 

determined. EPA will provide the 

necessary guidance later this year. 

We are proposing to amend the 

elements required with a certificate of 

representation under 40 CFR 98.4(i)(2) 

to include organization name (company 

affiliation-employer). We are also 

proposing to add the same element to 

the delegation by designated 

representative and alternate designated 

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

This information will help EPA and 

reporting system users to correctly 

identify persons during the designated 

representative appointment or agent 

delegation process. Part 98 and the 

proposed amendments would not 

require the designated representative, 

alternate designated representative or 

agent to be an employee of the reporting 

entity. When a designated 

representative further delegates their 

authority to an agent, the agent would 

gain access to all data for that facility or 

supplier. To underline the importance 

of granting access to the correct person, 

EPA would require the designated 

representative (or alternate) to confirm 

each agent delegation. Adding 

organization name to the certificate of 

representation and notice of delegation 

will add a level of assurance to the 

confirmation process. 

We are proposing to amend 40 CFR 

98.3(c)(5)(i) to clarify that for the 

purposes of meeting the requirements of 

this paragraph, suppliers of industrial 

flourinated GHGs only need to calculate 

and report GHG emissions in mtCO2e 

for those flourinated GHGs that are 

listed in Table A–1. This amendment is 

proposed because in order to 

incorporate additional fluorinated GHGs 

not listed in Table A–1 into the 

supplier’s total GHG emissions in 

mtCO2e, the reporter would be required 

to propose a GWP for the gas or use an 

established factor developed by the 

Intergovernmental Panel on Climate 

Change or another entity. EPA does not 

believe it is necessary to require 

reporters to develop a GWP for these 

gases at this time. Further, it is 

important to note that these gases would 

still be required to be reported under 40 

CFR 98.3(c)(5)(ii) (in metric tons of 

GHG). Therefore, EPA could calculate 

mtCO2e emissions from these gases in 

the future as GWP’s become available or 

are updated. 

Finally, we are proposing to amend 40 

CFR Part 98.6 (Definitions) and 40 CFR 

Part 98.7 (What Standardized Methods 

are Incorporated by Reference into this 

Part?). We are proposing to add or 

change several definitions to Subpart A, 

which are needed to clarify terms used 

in other subparts of Part 98. Similarly, 

we are proposing to amend 40 CFR 98.7 

(incorporation by reference) to 

accommodate changes in the standard 

methods that are allowed by other 

subparts of the rule. 

We are proposing to amend 40 CFR 

98.3(d)(3) to correct the year in which 

reporters that submit an abbreviated 

report for 2010 must submit a full, 

report from 2011 to 2012. The full report 

submitted in 2012 will be for the 2011 

reporting year. 

We are proposing to amend 40 CFR 

98.3(f) to correct the cross-reference 

from ‘‘§ 98.3(c)(8)’’ to ‘‘§ 98.3(c)(9).’’ 

We are proposing to amend the 

definitions of several terms in 40 CFR 

98.6: 

• Bulk Natural Gas Liquid, 

• Distillate fuel oil, 

• Fossil fuel, 

• Mscf, 

• Municipal solid waste or MSW, and 

• Natural gas. 

Bulk Natural Gas Liquid. Owners and 

operators have objected to the definition 

of ‘‘bulk natural gas liquid or NGL.’’ 

Section 98.6 in subpart A defines ‘‘bulk 

natural gas liquid or NGL’’ as a product 

which ‘‘refers to mixtures of 

hydrocarbons that have been separated 

from natural gas as liquids through the 

process of absorption, condensation, 

adsorption, or other methods at lease 

separators and field facilities.’’ The 

owners and operators have requested we 

remove the phrase ‘‘or other methods at 

lease separators and field facilities’’ from 

the above definition. They assert that 

these processes are not simple 

separation processes, but rather, NGL 

extraction processes that are typically 

performed at ‘‘gas plants’’ and not at 

‘‘lease separators and field facilities.’’ 

We agree that the separation processes 

listed in the definition of ‘‘bulk natural 

gas liquid or NGL’’ are associated with 

gas plants, and not lease separators and 

field facilities. It was not EPA’s intent 

to require the reporting of emissions 

associated with these processes at lease 

separators and field facilities. In fact, in 

40 CFR 98.400, we specifically state that 

the supplier category consists only of 

natural gas liquids fractionators and 

local natural gas distribution 

companies. Under 40 CFR 98.400(c), we 

specify that field gathering and boosting 

stations, as well as natural gas 

processing plants that ‘‘separate NGLs 

from natural gas * * * but do not 

fractionate these NGLs into their 

constituent products’’ do not meet the 

source category’s definition. 

Therefore, we are proposing to strike 

‘‘lease separators and field facilities’’ 

from the definition of ‘‘bulk natural gas 

liquid or NGL,’’ as well as from the 

definition of ‘‘natural gas liquids (NGL)’’ 

for enhanced clarity. However, we have 

determined that the words ‘‘or other 

methods’’ should remain in the above 

definition because the list of separation 

processes listed in the definition 

(absorption, condensation, adsorption) 

is not exhaustive, and other separation/ 

extraction processes may be employed 

at some facilities. We do not wish to 

exclude the reporting of emissions 


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associated with products separated/ 

extracted by means not explicitly stated 

in the rule. 

Distillate Fuel Oil. We are proposing 

to expand the definition of ‘‘Distillate 

fuel oil’’ to include kerosene-type jet 

fuel. 

Fossil Fuel. Some reporters have 

noted that the proposed rule set forth 

the same definition of ‘‘fossil fuel’’ that 

applies in the New Source Performance 

Standards program: ‘‘Fossil fuel means 

natural gas, petroleum, coal, or any form 

of solid, liquid, or gaseous fuel derived 

from such materials for the purpose of 

creating useful heat’’ (74 FR 16621). 

However, the final Part 98 includes 

the following definition, which, 

according to certain Parties, has no 

precedent in Clean Air Act (CAA) 

regulations: ‘‘Fossil fuel means natural 

gas, petroleum, coal, or any form of 

solid, liquid, or gaseous fuel derived 

from such material, including for 

example, consumer products that are 

derived from such materials and are 

combusted.’’ 

These owners and operators have 

asserted that the public did not have 

sufficient opportunity to comment on 

these changes, which together, they 

claimed, re-classify municipal solid 

waste (MSW) and tires as fossil fuel and 

could set an unintended precedent for 

other CAA programs. Further, they 

claimed that EPA changed the 

designation of MSW and tires from 

being classified as ‘‘alternative fuels’’ in 

the proposal to being classified as ‘‘fossil 

fuel-derived fuels (solid)’’ in the final 

Part 98. 

We did not intend to ‘‘re-classify’’ 

MSW and tires between the proposal 

and final Part 98 in any meaningful 

way. Rather, any changes made were 

due to the overall restructuring of the 

General Stationary Fuel Combustion 

source category in response to 

comments and were intended to expand 

the use of Tier 1 and Tier 2, and to 

remove some requirements that would 

subject units to Tier 3. Based on the 

above concerns, however, it has become 

apparent that stakeholders believe the 

changes had unintended consequences. 

Therefore, we have reevaluated this 

issue and are proposing amendments to 

the classification of fuels in Table C–1, 

as well as the definition of fossil fuel. 

We note that overall we do not believe 

that the changes between the proposed 

and final Part 98, nor the amendments 

described below, have a substantive 

impact on the calculation requirements 

or the reporting of emissions for MSW 

or tires under this rule. 

We made several changes from 

proposal in Part 98 in response to 

comments about use of the Tiers. In 

subpart C, in order for facilities to use 

Tier 1 or Tier 2, the fuel combusted had 

to be included in Table C–1. MSW and 

tires were not included in Table C–1; 

rather they were included in the 

proposed Table C–2, which was 

generically labeled ‘‘alternative fuels.’’ 

The restructuring of the Tiers in subpart 

C necessitated moving all fuels for 

which Tier 1 and Tier 2 were allowed 

into Table C–1. Table C–1 labeled these 

fuels as ‘‘fossil fuel-derived’’ to reflect 

the methods used to calculate 

emissions, noting the related provisions 

for determining the biogenic portions of 

fuels in subpart C. 

In order to address the above concerns 

raised with subpart C, we are now 

proposing to change the heading for 

these fuels from ‘‘fossil fuel-derived’’ to 

‘‘Other fuels (solid)’’ in Table C–1. 

Further, we are proposing to amend 

the definition of fossil fuel to return to 

the initial proposed definition. After 

proposal, we altered the definition in 

subpart A intending to provide clarity to 

facilities subject to Subpart C in the 

reporting of CO2 emissions per the 

requirements of 40 CFR 98.36, 

specifically, intending to clarify what 

was meant in the proposed definition by 

‘‘ * * * solid, liquid, or gaseous fuel 

derived from such materials.’’ We also 

changed the definition in subpart A to 

better align the definition of fossil fuel 

with the definition of the general 

stationary fuel combustion sources in 40 

CFR 98.30 (i.e., ‘‘devices that combust 

solid, liquid, or gaseous fuels, generally 

for the purposes of producing 

electricity, generating steam, or 

providing useful heat or energy for 

industrial, commercial, or institutional 

use, or reducing the volume of waste by 

removing combustible materials’’). 

We believe that the definition 

included in subpart A may have not 

added the clarity expected and that the 

definition of general stationary fuel 

combustion sources provided in subpart 

C is sufficient. We are soliciting 

comment on the proposed changes in 

the definition of fossil fuel in subpart A 

in the context of the calculation 

methods provided for these fuels in 

subpart C, and ask commenters to 

provide additional information if they 

believe that emissions from combusting 

these fuels should be estimated 

differently. 

Mscf. We are proposing to amend the 

definition of ‘‘Mscf’’ in 40 CFR 98.6 to 

indicate that ‘‘Mscf’’ means thousand 

standard cubic feet, and not, as 

incorrectly noted in the final rule, a 

million standard cubic feet. 

Municipal Solid Waste. We have 

received many questions regarding the 

definition of ‘‘Municipal solid waste or 

MSW’’ in Part 98. Specifically, the 

brevity of the definition makes it 

difficult to determine whether certain 

types of waste constitute MSW. We are 

proposing to amend the definition to 

closely match the definition of 

‘‘municipal solid waste’’ in Subpart Ea of 

the NSPS regulations (40 CFR 60.51a). 

The amended definition would explain 

what is meant by ‘‘household waste,’’ 

‘‘commercial/retail waste,’’ and 

‘‘institutional waste.’’ It would also 

provide a comprehensive list of 

materials that are excluded from these 

categories (e.g., industrial process or 

manufacturing wastes and medical 

waste). 

Natural Gas. We have also received 

many questions indicating that the 

definition of ‘‘Natural gas’’ is too 

inclusive and in some respects 

counterintuitive. The current definition 

begins with a statement that natural gas 

is a naturally occurring mixture of 

hydrocarbon and non-hydrocarbon 

gases found beneath the earth’s surface. 

However, it ends by equating ‘‘process 

gas’’ and ‘‘fuel gas’’ (neither of which is 

a naturally occurring gas mixture) with 

natural gas. We are proposing to amend 

the definition of ‘‘Natural gas’’ in 40 CFR 

98.6 to be consistent with definitions 

found in 40 CFR Parts 60 and 75. The 

amended definition would remove the 

references to process gas and fuel gas, 

and would specify that natural gas must 

be at least 70 percent methane or have 

a high heat value between 910 and 1150 

Btu/scf. 

We are proposing to add definitions of 

the following terms to 40 CFR 98.6 due 

to the large number of questions 

received requesting clarification of the 

definition of these terms: 

• Agricultural byproducts, 

• Primary fuel, 

• Solid byproducts, 

• Waste oil, and 

• Wood residuals. 

The terms ‘‘Agricultural byproducts,’’ 

‘‘Solid byproducts,’’ and ‘‘Wood 

residuals’’ are used to describe three 

types of solid biomass fuels listed in 

Table C–1 of Subpart C, but they are not 

defined in 40 CFR 98.6. The proposed 

definitions are based on the results of an 

Internet search and IPCC inventory 

guidelines (see EPA–HQ–OAR–2008– 

0508). For the purposes of Part 98, 

‘‘Agricultural byproducts’’ would 

include the parts of crops that are not 

ordinarily used for food (e.g., corn 

straw, peanut shells, pomace, etc.). 

‘‘Solid byproducts’’ would include plant 

matter such as vegetable waste, animal 

materials/wastes, and other solid 

biomass, except for wood, wood waste 

and sulphite lyes (black liquor). ‘‘Wood 

residuals’’ would include waste wood 


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recovered primarily from MSW streams, 

construction and demolition debris, and 

primary timber processing. Wastewater 

process sludge generated at pulp and 

paper mills would also be included; 

however, we are soliciting comment on 

whether the default emission factors for 

wood and wood residuals are 

appropriate for paper mill wastewater 

sludge, and, if not, what those emission 

factors should be. 

‘‘Primary fuel’’ would be defined as 

the fuel that contributes the greatest 

percentage of the annual heat input to 

a combustion unit. ‘‘Waste oil,’’ which 

we are proposing to add to Table C–1 as 

a new fuel type, would be defined as oil 

whose physical properties have 

changed, either through storage, 

handling, or use, so that the oil can no 

longer be used for its original purpose. 

Waste oil would include both 

automotive and industrial oils of 

various types. 

G. Subpart C (General Stationary Fuel 

Combustion) 

Numerous issues have been raised by 

owners and operators in relation to the 

requirements in subpart C for general 

stationary fuel combustion. The issues 

being addressed by the proposed 

amendments include the following: 

• Definition of the source category. 

• GHGs to report. 

• Calculating GHG emissions. 

• Natural gas consumption expressed 

in therms. 

• Use of Equation C–2b to calculate 

weighted annual average HHV. 

• Categories of gaseous fuels. 

• Use of mass-based gas flow meters. 

• Site-specific stack gas moisture 

content values. 

• Determining emissions from an 

exhaust stream diverted from a CEMS 

monitored stack. 

• Biomass combustion in units with 

CEMS. 

• Use of Tier 3. 

• Tier 4 requirements for units that 

combust greater than 250 tons of MSW 

per day. 

• Applicability of Tier 4 to common 

stack configurations. 

• Starting dates for the use of Tier 4. 

• CH4 and N2O calculations. 

• CO2 emissions from sorbent. 

• Biogenic CO2 emissions from 

biomass combustion. 

• Fuel sampling for coal and fuel oil. 

• Tier 3 sampling frequency for 

gaseous fuels. 

• CO2 emissions from blended fuel 

combustion. 

• Use of consensus standard methods. 

• CO2 monitor span values. 

• CEMS data validation. 

• Use of ASTM Methods D7459–08 

and D6866–08. 

• Electronic data reporting and 

recordkeeping. 

• Common stack reporting option. 

• Common fuel supply pipe reporting 

option. 

• Table C–1 default HHV and CO2

emission factors. 

• Table C–2 default CH4 and N2O 

emission factors. 

Definition of the source category. We 

are proposing to add a new paragraph 

40 CFR 98.30(d), clarifying that the GHG 

emissions from a pilot light need not be 

included in the emissions totals for the 

facility. Section 98.30(a) of subpart C 

defines a stationary fuel combustion 

source as a device that combusts 

‘‘ * * * solid, liquid, or gaseous fuel, 

generally for the purposes of producing 

electricity, generating steam, or 

providing useful heat or energy for 

industrial, commercial, or institutional 

use, or reducing the volume of waste by 

removing combustible matter * * * ’’. A 

pilot light is a small permanent 

auxiliary flame that simply ignites the 

burner of a combustion process in a 

boiler, turbine, or other fuel combustion 

device, and is not used to produce 

electricity or steam, or to provide useful 

energy to an industrial process, or to 

reduce waste by removing combustible 

matter. Therefore, we are clarifying that, 

for the purposes of Part 98, a pilot light 

is not considered to be a stationary fuel 

combustion source and pilot gas 

consumption would not be required to 

be included in the GHG emissions 

calculations. 

GHGs to Report. We are proposing to 

amend 40 CFR 98.32 to clarify that CO2, 

CH4, and N2O mass emissions from a 

stationary fuel combustion unit do not 

need to be reported under subpart C if 

such an exclusion is indicated 

elsewhere in subpart C. 

Calculating GHG emissions. We are 

proposing to amend 40 CFR 98.33(a) to 

provide additional detail and clarify 

who may (or must) use the calculation 

methods in the subsequent paragraphs 

to calculate and report GHG emissions. 

Specifically, we are proposing to amend 

this paragraph to point out that certain 

sources may use the methods in 40 CFR 

part 75 to calculate CO2 emissions, if 

they are already using Part 75 to report 

heat input data year-round under 

another Clean Air Act program. 

Paragraph 98.33(a) would also be 

amended to clarify the reporting of CO2

emissions from biomass combustion 

when a unit combusts both biomass and 

fossil fuels. 

Natural gas consumption expressed in 

therms. Subpart C of Part 98 allows the 

use of fuel billing records to quantify 

natural gas consumption, for the 

purposes of calculating CO2 mass 

emissions. On the billing records 

provided by natural gas suppliers, fuel 

usage is often expressed in units of 

‘‘therms,’’ rather than standard cubic feet 

(scf). A therm is equal to 100,000 Btu, 

or 0.1 mmBtu. Therefore, the equations 

for calculating CO2 mass emissions in 

Subpart C (e.g., Equation C–1), which 

require fuel usage to be in units of scf, 

are not suitable when fuel consumption 

is expressed in therms. 

In view of this, we are proposing to 

amend 40 CFR 98.33(a)(1) by adding a 

new equation, C–1a, to Tier 1. When 

natural gas consumption is expressed in 

therms, equation C–1a would enable 

sources to calculate CO2 mass emissions 

directly from the information on the 

billing records, without having to 

request or obtain additional data from 

the fuel suppliers. 

We are proposing to allow Equation 

C–1a to be used for units of any size 

when the fuel usage information on 

natural gas billing records is expressed 

in units of therms. A new paragraph, 

(b)(1)(v), would be added to 40 CFR 

98.33 to reflect this. Section 

98.36(e)(2)(i) would also be amended to 

allow gaseous fuel consumption to be 

reported in units of therms. 

Use of Equation C–2b. Whenever HHV 

data are received on a monthly or more 

frequent basis, the Tier 2 CO2 emissions 

calculation methodology requires the 

owner or operator to use Equation C–2b 

to calculate the annual average HHV, 

weighted according to monthly fuel 

usage. The fuel-weighted annual average 

HHV is then substituted into Equation 

C–2a. If HHV data are received less 

frequently than monthly, an arithmetic 

average HHV is used in the emissions 

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

However, we have learned that in 

cases where a facility includes part 75 

units (i.e., boilers and/or combustion 

turbines) and small combustion sources 

such as space heaters that share a 

common natural gas or oil supply, the 

use of Tier 2 may be triggered for the 

small combustion sources when the part 

75 units use the appendix D 

methodology to quantify heat input. 

This is because appendix D of Part 75 

requires periodic sampling of the 

heating value of fuel oil and natural gas. 

Tier 2 will be triggered for the small 

combustion units if the Part 75 fuel 

sampling frequency is equal to or greater 

than the minimum frequency specified 

in § 98.34(a). Further, if the part 75 fuel 

sampling frequency is monthly or 

greater, Equation C–2b would have to be 

used to calculate fuel-weighted annual 

average HHVs for the small combustion 

sources. 

Requiring small, low-emitting 

combustion sources to calculate CO2


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48756 Federal Register / Vol. 75, No. 154 / Wednesday, August 11, 2010 / Proposed Rules 

mass emissions using fuel-weighted 

annual average HHVs instead of 

arithmetic average values will not 

significantly enhance data quality. In 

view of this, we are proposing to amend 

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

calculation of a weighted HHV only for 

individual Tier 2 units with a maximum 

rated heat input capacity greater than or 

equal to 100 mmBtu/hr, and for groups 

of units that contain at least one unit of 

that size. For Tier 2 units smaller than 

100 mmBtu/hr and for aggregated 

groups of Tier 2 units under 

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

group are smaller than 100 mmBtu/hr, 

the annual arithmetic average HHV, 

rather than the annual fuel-weighted 

average HHV, would be used in 

Equation C–2a. 

Categories of Gaseous Fuels. Section 

98.34(a)(2)(iii) of subpart C requires 

quarterly HHV sampling for liquid fuels 

other than fuel oil, for fossil fuelderived gaseous fuels, and for biogas, 

when the Tier 2 methodology is used to 

calculate CO2 mass emissions. The term 

‘‘fossil fuel-derived gaseous fuels’’ has 

caused considerable confusion among 

regulated sources. The nomenclature 

and organization of Table C–1 of 

Subpart C makes it hard to determine 

which fuels are included in this 

category. Currently, only two fuels are 

listed in Table C–1 under the heading of 

fossil fuel-derived gaseous fuels: blast 

furnace gas and coke oven gas. 

However, a number of other gaseous 

fuels that are derived from petroleum, 

such as butane, are not listed there, but 

are listed under a different heading for 

‘‘petroleum products.’’ 

We are proposing to revise 40 CFR 

98.33(a)(2)(iii) by replacing the term 

‘‘fossil fuel-derived gaseous fuels’’ with 

a more inclusive term, i.e., ‘‘gaseous 

fuels other than natural gas.’’ 

Corresponding changes would also be 

made to Table C–1 for consistency, 

placing blast furnace gas, coke oven gas, 

fuel gas, and propane in a new category, 

‘‘Other fuels (gaseous).’’ 

Use of Mass-Based Gas Flow Meters. 

The Tier 3 CO2 emissions calculation 

methodology in 40 CFR 98.33(a)(3) 

currently allows flow meters that 

measure mass flow rates of liquid fuels 

to be used to quantify fuel consumption, 

provided that the density of the fuel is 

determined and the measured mass of 

fuel is converted to units of volume (i.e., 

gallons), for use in Equation C–4. In 

response to a number of requests, we are 

proposing to amend 40 CFR 

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

flow meters that measure mass flow 

rates of gaseous fuels to be used for Tier 

3 applications. To use mass flow meters, 

the density of the gaseous fuel would 

have to be measured, either with a 

calibrated density meter or by using a 

consensus standard method or standard 

industry practice, in order to convert the 

measured mass of fuel to units of 

standard cubic feet, for use in Equation 

C–5. 

Site-Specific Stack Gas Moisture 

Content Values. The Tier 4 calculation 

methodology in 40 CFR 98.33(a)(4) 

requires a CO2 CEMS to be used together 

with a stack gas flow rate monitor to 

measure CO2 mass emissions. If the CO2

monitor measures on a dry basis, 

corrections for the stack gas moisture 

content are needed, because the flow 

monitor measures on a wet basis. 

Part 98 currently requires that the 

moisture corrections be made either by 

installing a continuous moisture 

monitoring system or by using a default 

moisture value from 40 CFR Part 75 

(specifically 40 CFR 75.11(b)(1)) in the 

calculations. However, the default 

moisture constants from Part 75 only 

apply to various grades of coal, and to 

wood and natural gas. 

Recently, we have received inquiries 

from a number of sources that currently 

have dry-basis CO2 monitors in place 

and are required to use Tier 4. These 

sources have requested that EPA allow 

the use of site-specific default moisture 

values, in cases where no applicable 

default value is specified in Part 75 for 

the type(s) of fuel(s) combusted, or 

where the Part 75 moisture values are 

believed to be unrepresentative. 

EPA has approved many petitions for 

site-specific moisture content default 

values under the ARP. Therefore, we 

believe it is reasonable to allow Part 98 

sources to develop such default values, 

using an approach similar to the one 

that has been approved under the ARP. 

In view of this, we are proposing to 

amend 40 CFR 98.33(a)(4)(iii) to allow 

the use of site-specific moisture 

constants under the Tier 4 methodology. 

The site-specific moisture default 

value(s) would have to represent the 

fuel(s) or fuel blends that are combusted 

in the unit during normal, stable 

operation, and would have to account 

for any distinct difference(s) in stack gas 

moisture content associated with 

different process operating conditions. 

For each site-specific default moisture 

percentage, at least nine runs would be 

required using EPA Method 4— 

Determination Of Moisture Content In 

Stack Gases (40 CFR Part 60, Appendix 

A–3). Moisture data from the relative 

accuracy test audit (RATA) of a CEMS 

could be used for this purpose. Each 

site-specific default moisture value 

would be calculated by taking the 

arithmetic average of the Method 4 runs. 

Each site-specific moisture default 

value would be updated at least 

annually, and whenever the current 

value is believed to be nonrepresentative, due to changes in unit or 

process operation. The updated 

moisture value would be used in the 

subsequent CO2 emissions calculations. 

Determining Emissions from an 

Exhaust Stream Diverted from a CEMS 

Monitored Stack. We are proposing to 

amend 40 CFR 98.33(a)(4) by adding a 

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

the determination of CO2 mass 

emissions from a unit subject to the Tier 

4 calculation methodology when a 

portion of the flue gases generated by 

the unit exhaust through a stack that is 

not equipped with a CEMS to measure 

CO2 emissions (herein referred to as an 

‘‘unmonitored stack’’) The paragraph is 

intended to address situations where a 

portion of the stack gas generated by the 

Tier 4 unit is diverted for the purpose 

of drying fuels, recovering heat, or some 

other process-related activity. The 

provisions of the new paragraph would 

not apply when CO2 is removed or 

chemically altered in a way that 

significantly changes the CO2

concentration at the outlet of the 

unmonitored stack, compared to the 

outlet CO2 concentration at the stack 

equipped with a CEMS. The owner or 

operator would be required to use the 

best available information to estimate 

the hourly stack gas volumetric flow 

rates exhausting through the 

unmonitored stack. Best available 

information would include, but would 

not be limited to, correlation of 

operating parameters with flow rate, 

periodic flow rate measurements made 

with EPA Method 2, engineering 

analysis, etc. The estimated flow rates of 

the diverted gas stream would be made 

at the point where the diverted stream 

exits the main flue gas exhaust system. 

Each hourly volumetric flow rate value 

used in Equation C–6 of Subpart C 

would be the sum of the flow rate 

measured at the stack equipped with a 

CEMS and the estimated flow rate of the 

diverted gas stream. All procedures 

used to estimate the volumetric flow 

rate of the diverted gas stream would be 

documented in the monitoring plan 

required under 40 CFR 98.3(g)(5). 

Biomass Combustion in Units With 

CEMS. We are proposing to amend 40 

CFR 98.33(a)(5)(iii)(D) to redesignate it 

as 40 CFR 98.33(a)(5)(iv). This is to 

correct a paragraph numbering error in 

subpart C, because this paragraph 

applies to all of 40 CFR 98.33(a)(5) and 

not just to 40 CFR 98.33(a)(5)(iii). As 

discussed above in section II.C of the 

preamble, we are also proposing to 

amend 40 CFR 98.3(c) in subpart A and 


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

separate reporting of biogenic CO2 is 

optional for units that are not subject to 

the Acid Rain Program, but are using 

Part 75 methodologies to calculate CO2

mass emissions, as described in 40 CFR 

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

discussed above, separate reporting of 

biogenic CO2 emissions is also optional 

for units subject to subpart D. 

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

of subpart C currently requires the use 

of Tier 3 when a fuel that is not listed 

in Table C–1 of Subpart C is combusted 

in a unit with a maximum rated heat 

input capacity greater than 250 mmBtu/ 

hr, if two conditions are met: (a) The use 

of Tier 4 is not required; and (b) the fuel 

provides at least 10 percent of the 

annual heat input to the unit. 

However, 40 CFR 98.33(b)(3)(iii)(B) 

refers to the annual heat input to a 

group of units served by a common 

supply pipe, in addition to the heat 

input to an individual unit. The text of 

40 CFR 98.33(b)(3)(iii) is not consistent 

with 40 CFR 98.33(b)(3)(iii)(B) because 

it does not mention common pipe 

configurations. 

We are proposing to amend 40 CFR 

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

paragraph applies also to common pipe 

configurations where at least one unit 

served by the common pipe has a heat 

input capacity greater than 250 mmBtu/ 

hr. 

The Agency also proposes to add a 

new paragraph, (b)(3)(iv), to 40 CFR 

98.33, requiring Tier 3 to be used when 

specified in another subpart of Part 98, 

regardless of fuel type or unit size. For 

example, Subpart Y requires certain 

units that combust refinery fuel gas 

(RFG) to use Equation C–5 in Subpart C 

(which is the Tier 3 equation for gaseous 

fuel combustion) to calculate CO2 mass 

emissions, without regard to unit size. 

Tier 4 Requirements for Units That 

Combust Greater Than 250 Tons of 

MSW per Day. Owners and operators of 

units that combust municipal solid 

waste have contended that, because Part 

98 requires that units that combust 

MSW must follow Tier 4 if they meet 

the requirements in 40 CFR 

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

it entails a disproportionate burden for 

municipal waste combustors (MWCs). 

One element of their argument was that 

a threshold of greater than 250 tons per 

day of MSW was a more stringent 

threshold than the 250 mmbtu/hr heat 

input threshold for other stationary 

combustion units and, therefore, a 

disproportionate burden for MWCs. 

Further, they stated that the industry 

did not have the necessary emission 

monitoring equipment in place and 

would, therefore, be required to install 

new equipment in order to meet the 

requirements of the rule. 

Part 98 included a threshold of 250 

tons of MSW per day because it was 

consistent with the threshold applied in 

the EPA New Source Performance 

Standards (NSPS). Under that program, 

units combusting greater than 250 tons 

per day of MSW are considered ‘‘large’’ 

units. We did not believe that subpart C 

applied a disproportionate burden to 

municipal waste combustors because all 

‘‘large’’ units (whether 250 tons of MSW 

per day or with a heat input capacity 

greater than 250 mmBtu/hr) would only 

be subject to Tier 4 if they met the other 

conditions outlined in 40 CFR 

98.33(b)(4). We have reevaluated this 

issue based on the fact that while a 

threshold of 250 tons of MSW may be 

appropriate for the purposes of NSPS, it 

is not necessarily appropriate for a GHG 

emissions reporting program. We also 

recognize that a large majority of the 

units may have to install either a flow 

meter or a concentration monitor, and in 

some cases both, to comply with subpart 

C. 

Based on these concerns, we are 

proposing to amend 40 CFR 

98.33(b)(4)(ii)(A) to change the 250 tons 

MSW per day threshold to 600 tons 

MSW per day, based on further analysis 

that this value is approximately 

equivalent to the 250 mmBtu/hr heat 

input requirements for other large 

stationary combustion units. For more 

information, please refer to the 

Background Technical Support 

Document (EPA–HQ–OAR–2008–0508). 

Units less than 600 tons MSW per day, 

that do not meet the requirements in 40 

CFR 98.33(b)(4)(iii) could use Tier 2. We 

believe that this proposal still meets the 

desired goal to obtain high quality data 

from larger units, while not applying 

unnecessary burden. With this proposed 

amendment, MWCs would be subject to 

comparable monitoring thresholds and 

conditions as other general stationary 

combustion units. 

Applicability of Tier 4 to Common 

Stack Configurations. Section 

98.36(c)(2) of Subpart C allows the 

owner or operator of stationary 

combustion units that share a common 

stack (or duct) and use the Tier 4 

methodology to calculate CO2 mass 

emissions to continuously monitor and 

report the combined CO2 mass 

emissions at the common stack (or 

duct), in lieu of separately monitoring 

and reporting the CO2 emissions from 

the individual units. 

Several other Subparts of Part 98 

either: (1) Allow a particular process or 

manufacturing unit to use Tier 4 to 

quantify CO2 mass emissions, as an 

alternative to using a mass balance 

approach (for instance, Subpart G 

allows this option for an ammonia 

manufacturing unit—see 40 CFR 

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

be used in certain instances when a 

process unit and a stationary 

combustion unit share a common stack 

(e.g., see 40 CFR 98.63(g) and 98.73(c)). 

Subpart C sets forth the applicability 

of Tier 4 in 40 CFR 98.33(b)(4)(ii) and 

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

98.33(b)(4) focuses exclusively on 

individual stationary fuel combustion 

units; no mention is made of common 

stack configurations. 

In view of this, we are proposing to 

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

provisions to clarify how the Tier 4 

criteria apply to common stack 

configurations. Paragraph (b)(4)(i) 

would be expanded to include 

monitored common stack configurations 

that consist of stationary combustion 

units, process units, or both types of 

units. A new paragraph, (b)(4)(iv) would 

also be added, describing the following 

three distinct common stack 

configurations to which Tier 4 might 

apply. 

The first, most basic configuration is 

one in which the combined effluent gas 

streams from two or more stationary fuel 

combustion units are vented through a 

monitored common stack (or duct). In 

this case, Tier 4 would apply if: 

• There is at least one large unit in 

the configuration that has a maximum 

rated heat input capacity greater than 

250 mmBtu/hr or an input capacity 

greater than 600 tons/day of MSW (as 

applicable); 

• At least one large combustion unit 

in the configuration meets the 

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

through (b)(4)(ii)(C); and 

• The CEMS installed at the common 

stack (or duct) meets all of the 

requirements of 40 CFR 98.33 

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

Tier 4 would also apply when all of 

the combustion units in the 

configuration are small (≤ 250 mmBtu/ 

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

one of the units meets the conditions of 

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

The second configuration is one in 

which the combined effluent gas 

streams from a stationary combustion 

unit and a process or manufacturing 

unit are vented through a common stack 

or duct. Many subparts of part 98 

describe this situation (see subparts F, 

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

the use of Tier 4 would be required if 

the stationary combustion unit and the 

monitors installed at the common stack 

or duct meet the applicability criteria of 

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

If multiple stationary combustion units 


srobinson on DSKHWCL6B1PROD with PROPOSALS2
48758 Federal Register / Vol. 75, No. 154 / Wednesday, August 11, 2010 / Proposed Rules 

and a process unit (or units) are vented 

through a common stack or duct, Tier 4 

would be required if at least one of the 

combustion units and the monitors 

installed at the common stack or duct 

meet the conditions of 40 CFR 

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

The third configuration is one in 

which the combined effluent streams 

from two or more process or 

manufacturing units are vented through 

a common stack or duct. In this case, if 

any of these units is required to use Tier 

4 under an applicable subpart of Part 98, 

the owner or operator could either 

monitor the CO2 mass emissions at the 

Tier 4 unit(s) before the effluent streams 

are combined together, or monitor the 

combined CO2 mass emissions from all 

units at the common stack or duct. 

However, if it is not feasible to monitor 

the individual units, the combined CO2

mass emissions would have to be 

monitored at the common stack or duct, 

using Tier 4. 

Starting Dates for the Use of Tier 4. 

Section 98.33(b)(5) of subpart C 

currently states that units that are 

required to use the Tier 4 methodology 

must begin using it on January 1, 2010 

if all required CEMS are in place. 

Otherwise, use of Tier 4 begins on 

January 1, 2011, and Tier 2 or Tier 3 

may be used to report CO2 mass 

emissions in 2010. Recently, a number 

of sources have asked EPA whether Tier 

4 may be used prior to January 1, 2011 

if the required CEMS are certified some 

time in 2010, or whether Tier 2 or Tier 

3 must be used for the entire year. 

We believe that it is reasonable for 

sources to begin reporting CO2

emissions data prior to 2011 from CEMS 

that successfully complete certification 

testing in 2010. Therefore, we are 

proposing to amend 40 CFR 98.33(b)(5) 

accordingly. Note that changes in 

methodology during a reporting year are 

allowed by Part 98, and must be 

documented in the annual GHG 

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

The proposed revisions would allow 

sources to discontinue using Tier 2 or 3 

and begin reporting their 2010 

emissions under Tier 4 as of the date on 

which all required certification tests are 

passed. CEMS data recorded during the 

certification test period could also be 

used for Part 98 reporting, provided 

that: (a) All required certification tests 

are passed in sequence, with no test 

failures; and (b) no unscheduled 

maintenance or repair of the CEMS is 

required during the test period. 

We are also proposing to amend 40 

CFR 98.33(b)(5) by adding a new 

paragraph, (b)(5)(iii), to address 

situations where the owner or operator 

of an affected unit that has been using 

Tier 1, 2, or 3 to calculate CO2 mass 

emissions makes a change that triggers 

Tier 4 applicability by changing: (1) The 

primary fuel, (2) the manner of unit 

operation, or (3) the installed 

continuous monitoring equipment. In 

such cases, the owner or operator would 

be required to begin using Tier 4 no 

later than 180 days from the date on 

which the change is implemented. This 

would allow adequate time for the 

owner or operator to obtain and/or 

certify any of the required Tier 4 

continuous monitors. 

Methane and Nitrous Oxide 

Calculations. The equations for 

calculating CH4 and N2O emissions from 

stationary combustion sources are found 

in 40 CFR 98.33(c). Calculation of these 

emissions is required only for fuels 

listed in Table C–2 of Subpart C. When 

either the Tier 1 or the Tier 3 

methodology is used to determine CO2

mass emissions, Equation C–8 is used to 

calculate CH4 and N2O emissions. 

Equation C–8 includes the term ‘‘HHV,’’ 

which is defined as the applicable 

default high heat value (HHV) from 

Table C–1 for a particular type of fuel. 

Owners and operators have asserted that 

they should be able to use actual HHV 

data for Tier 3 units, in lieu of using the 

Table C–1 default values, and noted that 

site-specific values would be more 

accurate. 

We agree that this would result in 

more accurate estimates of emissions 

and are proposing to revise the 

definition of the term ‘‘HHV’’ in the 

Equation C–8 nomenclature. The 

proposed amendment would allow Tier 

3 units to use actual HHV data to 

calculate CH4 and N2O emissions. If 

multiple HHV values are obtained 

during the year, the arithmetic average 

would be used in Equation C–8. 

Units that monitor heat input yearround according to 40 CFR Part 75 or 

that use the Tier 4 CO2 calculation 

methodology are required to use 

Equation C–10 in Subpart C to calculate 

CH4 and N2O emissions. When more 

than one type of fuel listed in Table C– 

2 is combusted in these units during 

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

requires Equation C–10 to be used 

separately for each fuel. 

Owners and operators have asked 

EPA to clarify what is meant by ‘‘normal 

operation,’’ and whether any fuel(s) 

should be excluded from the emissions 

calculations. Today’s proposed 

amendments would clarify the Agency’s 

intent by removing the term ‘‘normal 

operation’’ from 40 CFR 98.33(c)(4)(i) 

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

CH4 and N2O emissions would simply 

be required for each Table C–2 fuel 

combusted in the unit during the 

reporting year. 

We are also proposing to further 

amend 40 CFR 98.33(c)(4)(ii), to allow 

additional reporting flexibility for 

certain units that combust more than 

one type of fuel; specifically, for units 

that report heat input data to EPA yearround using part 75 CEMS. For all 

multi-fuel units that use CEMS to 

comply with Part 98, subpart C requires 

the ‘‘best available information’’ to be 

used to determine the percentage of the 

annual unit heat input contributed by 

each type of fuel, for the purposes of 

calculating CH4 and N2O mass 

emissions. 

For part 75 units that use CEMS to 

quantify unit heat input, the fuelspecific annual heat input values 

needed for the CH4 and N2O emissions 

calculations can, in most cases, be 

determined from information in the part 

75 electronic data reports—specifically, 

from the ‘‘F-factors’’ reported for each 

unit operating hour. These F-factors, 

which are fuel-specific, are used in the 

hourly heat input calculations. 

Therefore, it is possible to use the 

reported F-factors to group the annual 

unit operating hours according to fuel 

type, and to sum the reported hourly 

heat input values for each group. 

However, if the owner or operator elects 

to use the reporting option in section 

3.3.6.5 of part 75, appendix F, the fuelspecific heat input values cannot be 

determined from the emissions reports. 

This is because section 3.3.6.5 of 

appendix F allows the owner or 

operator to calculate all hourly heat 

input values using the ‘‘worst-case’’ 

(highest) F-factor for any fuel combusted 

in the unit. A situation where this 

reporting option is likely to be 

implemented is for a coal-fired utility 

boiler that uses small amounts of 

natural gas for unit startup. A second 

example where the worst-case F-factor 

option is sometimes used is for a unit 

that combusts a blend of bituminous 

coal and sub-bituminous coal, in 

varying proportions. The F-factors for 

these two grades of coal are nearly the 

same. For the examples cited, the 

impact on the reported annual unit heat 

input is generally very small (1 to 2 

percent at most). In view of this, we are 

proposing to allow part 75 units that use 

the worst-case F-factor reporting option 

to attribute 100 percent of the unit’s 

annual heat input to the fuel with the 

highest F-factor, as though it were the 

only fuel combusted during the report 

year. 

For Tier 4 units, the requirement to 

use the best available information to 

determine the annual heat input from 

each type of fuel is being retained in 40 


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Federal Register / Vol. 75, No. 154 / Wednesday, August 11, 2010 / Proposed Rules 48759 

CFR 98.33(c)(4)(i), and we are proposing 

to allow it under 40 CFR 

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

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

determined directly from the part 75 

electronic data reports. 

Carbon Dioxide Emissions from 

Sorbent. Section 98.33(d) of subpart C 

currently requires the following sources 

to use Equation C–11 to calculate and 

report CO2 mass emissions from sorbent, 

except where the total CO2 emissions 

are measured using CEMS: (a) Fluidized 

bed combustion units; (b) units with wet 

flue gas desulfurization (FGD) systems; 

and (c) units equipped with ‘‘other acid 

gas emission controls with sorbent 

injection.’’ Equation C–11 includes the 

term ‘‘R,’’ which is defined as ‘‘1.00, the 

calcium to sulfur stoichiometric ratio.’’ 

Industry members have noted that 

some sorbents that reduce acid gas 

emissions do not produce CO2 (for 

instance, Ca(OH)2 does not). Further, the 

1.00 value of R in Equation C–11 applies 

only to SO2 removal, indicating that one 

mole of CO2 is produced for every mole 

of SO2 removed. We have also been 

informed that CO2–producing sorbents 

such as sodium bicarbonate are 

sometimes injected to remove other acid 

gas species (e.g., HCl). 

In view of these considerations, we 

are proposing to amend 40 CFR 98.33(d) 

by making it more generally applicable 

to different types of CO2-producing 

sorbents. The term ‘‘R’’ would be 

redefined as the number of moles of CO2

released upon capture of one mole of 

acid gas. When the sorbent is CaCO3, the 

value of R would be 1.00. For other CO2- 

producing sorbents, a specific value of 

R would be determined by the reporting 

facility from the chemical formula of the 

sorbent and the chemical reaction with 

the acid gas species that is being 

removed. 

Biogenic CO2 Emissions From 

Biomass Combustion. In response to 

questions about the methodologies in 40 

CFR 98.33(e) for calculating biogenic 

CO2 mass emissions from biomass 

combustion, we are proposing a number 

of technical corrections and 

clarifications to that section of the rule. 

The title and introductory text of 40 

CFR 98.33(e) would be amended to 

more precisely define the requirements 

for reporting biogenic CO2 emissions. In 

general, biogenic CO2 emissions 

reporting would be required only for the 

combustion of the biomass fuels listed 

in Table C–1 and for municipal solid 

waste (which consists partly of biomass 

and partly of fossil fuel derivatives). 

We are also proposing to amend 40 

CFR 98.33(e) to describe three cases in 

which units that combust biomass 

would not need to report biogenic CO2

emissions separate from total CO2

emissions: 

1. If a biomass fuel is not listed in 

Table C–1, the biogenic CO2 emissions 

would need to be reported separately 

from total CO2 emissions only if: 

— The fuel is combusted in a large unit 

(greater than 250 mmBtu/hr heat 

input capacity); 

—The biomass fuel accounts for 10 

percent or more of the annual heat 

input to the unit; and 

—The unit does not use CEMS to 

quantify its annual CO2 mass 

emissions. 

In that case, according to 40 CFR 

98.33(b)(3)(iii), Tier 3 would have to be 

used to determine the carbon content of 

the biomass fuel and to calculate the 

biogenic CO2 emissions. 

2. If a unit is subject to Subpart C or 

D and uses the CO2 mass emissions 

calculation methodologies in 40 CFR 

Part 75 to satisfy the Part 98 reporting 

requirements, the reporting of biogenic 

CO2 emissions would be optional. 

3. For the combustion of tires, which 

are also partly biogenic (typically 10–20 

percent biomass, for car and truck tires), 

separate reporting of the biogenic CO2

emissions would be optional, but could 

be done following provisions in 40 CFR 

98.33(e). 

We are proposing to amend 40 CFR 

98.33(e)(1) by removing the restriction 

against using Tier 1 to calculate 

biogenic CO2 emissions on units that 

use CEMS to measure the total CO2 mass 

emissions. There is no technical basis 

for this restriction, provided that 

biomass consumption can be accurately 

quantified. However, the use of Tier 1 

would not be allowed for combustion of 

MSW, as originally specified in 40 CFR 

98.33(e)(1) of subpart C, and would also 

not be allowed for the combustion of 

tires, if biogenic CO2 emissions are 

calculated for tires. 

We are proposing to amend the 

methodology in 40 CFR 98.33(e)(2), 

which is specifically for units using a 

CEMS to measure CO2 mass emissions, 

by: 

1. Limiting it to cases where the CO2

emissions measured by the CEMS are 

solely from combustion, i.e., the stack 

gas contains no additional process CO2

or CO2 from sorbent; and 

2. Prohibiting its use if the unit 

combusts MSW or tires. 

Section 98.33(e)(2) of subpart C 

currently requires the total volume of 

CO2 produced from fossil fuel 

combustion (which is based on 

estimated fuel usage, measured HHVs 

and F-factors) to be subtracted from the 

total volume of CO2 from the 

combustion of all fuels (as determined 

from the CEMS data). The difference is 

assumed to be the volume of biogenic 

CO2. However, this approach is only 

viable if all of the CO2 emissions are 

from the combustion of fossil fuels and 

biomass, and if no fuels (such as MSW 

and tires) that are a mixture of biomass 

and fossil fuel derivatives are 

combusted in the unit. 

If there are any process CO2 emissions 

or CO2 emissions from sorbent in the 

stack effluent, the volumes of those CO2

emissions would have to be subtracted 

from the total volume of CO2 derived 

from the CEMS data in order to 

determine the biogenic CO2 volume. 

Further, if any partly biogenic fuels 

(such as MSW and tires) are combusted 

in the unit, the fossil component of each 

of these fuels would have to be 

characterized. We are not aware of any 

method that is economically feasible for 

reporting sources to determine the mass 

percentage of the fossil fuel component 

of fuels such as MSW and tires. In 

addition, we are not aware of any 

practical method for quantifying CO2

volumes from sorbent or from noncombustion industrial processes. For 

these reasons, we are proposing 

restrictions ‘‘1’’ and ‘‘2’’ above on the use 

of the methodology in 40 CFR 

98.33(e)(2). 

For sources that are combusting 

MSW, we are proposing to amend 40 

CFR 98.33(e)(3) to require the use of 

ASTM methods D7459–08 and D6866– 

08 quarterly, as described in 40 CFR 

98.34(d), when any MSW is combusted, 

either as the primary fuel or as the only 

fuel with a biogenic component. We are 

proposing to further amend 40 CFR 

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

to be used, as described in 40 CFR 

98.34(e), for any unit in which biogenic 

(or partly biogenic) fuels, and nonbiogenic fuels are combusted, in any 

proportions. 

We are also proposing to delete and 

reserve 40 CFR 98.33(e)(4) and the 

related subparagraphs. Although 40 CFR 

98.33(e)(4) allows the ASTM methods to 

be used to determine biogenic CO2

emissions for various combinations of 

biogenic and fossil fuels, we are 

proposing to delete and reserve it 

because the paragraph also includes an 

unnecessary restriction, i.e., it only 

applies to units that use CEMS to 

measure total CO2 mass emissions. The 

proposed amendments to 40 CFR 

98.33(e)(3) described above would 

achieve the same intended purpose as 

40 CFR 98.33(e)(4), without imposing 

this restriction, so 40 CFR 98.33(e)(4) is 

no longer needed. 

Finally, we are proposing to amend 40 

CFR 98.33(e)(5) so that it would also 


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apply to units that are using Tier 2 

(Equation C–2a), as well as Tier 1 

(Equation C–1), for calculating biogenic 

CO2 mass emissions. The approach in 

40 CFR 98.33(e)(5) for estimating solid 

biomass fuel consumption is equally 

applicable to units using those two 

equations to calculate biogenic CO2

emissions. Equation C–2a would apply 

when HHV data for a biomass fuel are 

available at the minimum frequency 

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

Fuel Sampling for Coal and Fuel Oil. 

We are proposing to amend 40 CFR 

98.34(a)(2), to clarify the frequency at 

which the HHV needs to be determined 

for different types of fuels. 

In subpart C, the Tier 2 calculation 

methodology in 40 CFR 98.33(a)(2) 

requires periodic fuel sampling and 

analysis to determine HHVs. Section 

98.34(a)(2) specifies the minimum 

required sampling frequency for various 

fuel types. For coal and fuel oil, at least 

one representative sample must be 

obtained and analyzed for each fuel lot. 

A ‘‘fuel lot’’ is defined as a shipment or 

delivery of a particular type of fuel, and 

may consist of a ship load, a barge load, 

a group of trucks, or a group of railroad 

cars. 

Several reporters have noted that 

some facilities receive fuel deliveries by 

truck, rail or pipeline quite frequently— 

even daily in some cases. The reporters 

have expressed the concern that, under 

subpart C, daily fuel deliveries appear to 

trigger a requirement for daily sampling 

and analysis, according to the definition 

of a fuel lot. Reporters have also noted 

that coal and petroleum derivatives 

such as coke and petroleum coke are 

often delivered in lots. Further, the 

Agency has received inquiries asking 

why a commonly-used fuel oil sampling 

strategy is not included in subpart C, 

i.e., taking a sample whenever oil is 

added to the storage tank. 

It is not our intent to require an 

excessive amount of HHV sampling for 

coal and fuel oil (or for any other solid 

or liquid fuel that is delivered in lots), 

or to prohibit the use of viable sampling 

options. Therefore, we are proposing, 

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

expand the list of fuels for which 

sampling of each fuel lot is sufficient to 

include other solid or liquid fuels that 

are delivered in lots. 

Second, we are proposing to more 

precisely define the term ‘‘fuel lot’’ in 40 

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

facilities that receive multiple deliveries 

of a particular fuel from the same 

supply source each month, either by 

truck, rail, or pipeline. The proposed 

amendment would clarify that a fuel lot 

consists of all of the deliveries for a 

given calendar month. Thus, for these 

facilities, the required HHV sampling 

frequency would be no greater than 

once per month. We are proposing to 

add parallel language to 40 CFR 

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

provisions for coal and fuel oil, for 

consistency with the proposed revisions 

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

Third, we are proposing to further 

revise 40 CFR 98.34(a)(2)(ii) and 

98.34(b)(3)(ii) to allow manual oil 

samples to be taken after each addition 

of oil to the storage tank. Daily manual 

sampling, flow-proportional sampling, 

and continuous drip sampling would 

also be allowed. 

Tier 3 Sampling Frequency for 

Gaseous Fuels. Section 98.34(b)(3)(ii) of 

subpart C specifies the minimum 

required frequency for determining the 

carbon content and molecular weight of 

various types of fuel, when using the 

Tier 3 methodology to calculate CO2

mass emissions. For gaseous fuels, daily 

sampling is required if ‘‘the necessary 

equipment is in place to make these 

measurements.’’ Otherwise, weekly 

sampling is required. 

EPA has received a number of 

questions from owners and operators 

about the meaning of ‘‘necessary 

equipment.’’ In particular, sources have 

asked whether this refers only to 

continuous, on-line equipment such as 

gas chromatographs, or whether daily, 

manual sampling is required where 

such capability exists. 

We are proposing to amend 40 CFR 

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

sampling of gaseous fuels for carbon 

content and molecular weight is only 

required where continuous, on-line 

equipment is in place; weekly sampling 

would be required in all other cases. 

This has always been the Agency’s 

intent. 

CO2 Emissions From Blended Fuel 

Combustion. One of the most frequently 

asked questions by the regulated 

community since the October 30, 2009 

publication of Part 98 is, ‘‘How does one 

calculate CO2 mass emissions from the 

combustion of blended fuels?’’ Subpart 

C provided only limited guidance on 

this issue. First, 40 CFR 98.34(a)(3) 

stated that when different types of fuel 

are blended (e.g., different ranks of coal 

or different grades of fuel oil), two 

options could be used for determining 

the HHV for Tier 2 applications: (a) Use 

a weighted HHV in the emissions 

calculations; or (b) take a representative 

sample of the blend and analyze it for 

HHV. Second, 40 CFR 98.34(b)(3)(v) 

stated that these same two options apply 

to carbon content and molecular weight 

determinations under Tier 3. Third, for 

Tier 3 common pipe applications, 40 

CFR 98.34(b)(1)(vi) required that fuels 

either be metered individually before 

blending, or that the blended fuel and 

a subset of the individual fuels be 

metered so that the volume of each fuel 

in the blend can be determined. 

Based on the number of questions 

received, we have concluded that these 

rule provisions do not adequately 

address the complexities associated 

with blended fuels. Therefore, we are 

proposing substantive amendments to 

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

(b)(3)(v). The proposed amendments 

would make a clear distinction between 

cases where the mass or volume of each 

fuel in the blend is accurately measured 

prior to mixing (e.g., using individual 

flow meters for each component) and 

cases where the exact composition of 

the blend is not known. In the former 

case, the fact that the fuels are blended 

is of no consequence; because the exact 

quantity of each fuel in the blend is 

known, the CO2 emissions from 

combustion of each component would 

be calculated separately. In the latter 

case, we are proposing that the blend be 

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

and that its mass or volume and 

essential properties (e.g., HHV, carbon 

content, etc.) be measured at a 

prescribed frequency. 

When the mass or volume of each 

individual component of a blend is not 

precisely known prior to mixing, the 

appropriate method used to calculate 

the CO2 mass emissions from 

combustion of the blend would be as 

follows. For smaller combustion units 

(heat input capacity not more than 250 

mmBtu/hr), we are proposing that Tier 

2 (or possibly Tier 1) be used when all 

components of the blend are listed in 

Table C–1 of Subpart C. In order to 

perform these CO2 emissions 

calculations for the blend, a reasonable 

estimate of the percentage composition 

of the blend would be required, using 

the best available information (e.g., from 

the typical or expected range of values 

of each component). A heat-weighted 

CO2 emission factor would be 

calculated, using proposed Equation C– 

16. For Tier 1 applications, a heatweighted default HHV would also have 

to be determined, using proposed 

Equation C–17. 

In cases where a fuel blend consists 

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

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

calculation of CO2 and other GHG 

emissions from combustion of the blend 

would be required only for the Table C– 

1 fuel(s), using the best available 

estimate of the mass or volume 

percentage(s) of the Table C–1 fuel(s) in 

the blend. In these cases, the use of Tier 

1 would be required, with modifications 

to certain terms in Equations C–17 and 


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Federal Register / Vol. 75, No. 154 / Wednesday, August 11, 2010 / Proposed Rules 48761 

C–1, to account for the fact that the 

blend is not composed entirely of Table 

C–1 fuels. An example calculation is 

provided in proposed 40 CFR 

98.34(a)(3)(iv). 

For larger combustion units (heat 

input capacity greater than 250 mmBtu/ 

hr) that do not qualify to use Tier 1 or 

2, we are proposing that the owner or 

operator would use Tier 3 to calculate 

the CO2 mass emissions from 

combustion of a blended fuel. The 

mathematics for Tier 3 would be much 

simpler than for Tiers 1 and 2, since no 

default values are used in the 

calculations, and an estimate of the 

percentage composition of the blend is 

not required. To apply Tier 3, the only 

requirements would be to accurately 

measure the annual consumption of the 

blended fuel and to determine its carbon 

content and (if necessary) molecular 

weight, at a prescribed frequency. By 

considering the blended fuel to be a 

distinct ‘‘fuel type,’’ in cases where that 

fuel is not listed in Table C–1, GHG 

emissions reporting would be required 

in accordance with 40 CFR 

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

opposed to each individual component 

of the blend) provides at least 10 

percent of the annual heat input to a 

unit or group of units, and if the use of 

Tier 4 is not required. 

To address the calculation of CH4 and 

N2O mass emissions from the 

combustion of blended fuels, we are 

proposing to add a new paragraph, 

(c)(6), to 40 CFR 98.33. Calculation of 

CH4 and N2O emissions would be 

required only for components of a blend 

that are listed in Table C–2 of Subpart 

C. 

If the mass or volume of each 

component of a blend is measured 

before the fuels are mixed and 

combusted, the existing CH4 and N2O 

mass emissions calculation procedures 

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

be followed for each component 

separately. The fact that the fuels are 

mixed prior to combustion is of no 

consequence in this case. 

If the mass or volume of each 

individual component is not measured 

prior to mixing, a reasonable estimate of 

the percentage composition of the blend 

would be required, based on the best 

available information, and the 

procedures in 40 CFR 98.33(c)(6)(ii) 

would be followed. First, the annual 

consumption of each component fuel in 

the blend would be calculated by 

multiplying the total quantity of the 

blend combusted during the reporting 

year by the estimated mass or volume 

percentage of that component. Next, the 

annual heat input from the combustion 

of each component would be calculated 

by multiplying its annual consumption 

by the appropriate HHV (either the 

default HHV from Table C–1 or, if 

available, the measured annual average 

value). The annual CH4 and N2O mass 

emissions for each component would 

then be calculated using the applicable 

equation in 40 CFR 98.33(c), i.e., 

Equation C–8, C–9a, or C–10. Finally, 

the calculated CH4 and N2O emissions 

would be summed across all 

components, and these sums would be 

reported as the annual CH4 and N2O 

mass emissions for the blend. 

Use of Consensus Standard Methods. 

Sections 98.34(a)(6), (b)(4), and (b)(5) of 

subpart C specify acceptable methods 

for determining fuel HHV, carbon 

content, and molecular weight, and 

methods for calibrating fuel flow meters. 

The methods listed in those sections are 

from consensus standards organizations 

such as ASTM, ASME, AGA, and GPA. 

Although we attempted to assemble a 

comprehensive list of methods and 

provide appropriate alternatives, it is 

possible that other valid methods from 

these organizations and practices have 

been overlooked, or that in some cases, 

industry consensus standard methods 

may be more appropriate than the 

methods listed. In view of this, we are 

proposing to remove the specific 

method lists from 40 CFR 98.34 and to 

amend 40 CFR 98.34(a)(6) and 

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

redesignate paragraph (b)(5) as (b)(4), 

and amend newly designated paragraph 

(b)(4). These proposed amendments 

would allow the owner or operator to 

either: (1) Use appropriate methods 

published by consensus standards 

organizations such as ASTM, ASME, 

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

standard practice. The methods used 

would be documented in the monitoring 

plan under 40 CFR 98.3(g)(5). 

CO2 Monitor Span Values. The Tier 4 

calculation method in 40 CFR 

98.33(a)(4) requires a CO2 concentration 

monitor and a stack gas flow rate 

monitor to measure CO2 mass 

emissions. The CO2 monitor must be 

certified and 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. For example, a 

typical span value for a CO2 monitor 

installed on a coal-fired boiler is 20 

percent CO2; therefore, the CGA 

concentrations represent 25 to 40 

percent of span and 50 to 70 percent of 

span. However, when CO2 emissions 

from an industrial process (e.g., cement 

manufacturing) are combined with 

combustion CO2 emissions, the resultant 

CO2 concentration in the stack gas can 

be substantially higher than for the 

combustion emissions alone. In such 

cases, a span value of 30 percent CO2 (or 

higher) may be required. 

When the CO2 span exceeds 20 

percent CO2, the CGA concentrations 

specified in Part 60 only evaluate the 

lower portion of the measurement scale 

and are no longer representative. 

Therefore, we are proposing to amend 

40 CFR 98.34(c) by adding a new 

paragraph (c)(6), which would allow the 

CGAs of a CO2 monitor to be performed 

using calibration gas concentrations of 

40 to 60 percent of span and 80 to 100 

percent of span, when the CO2 span 

value is set higher than 20 percent CO2. 

CEMS Data Validation. The Tier 4 

methodology in 40 CFR 98.33(a)(4) 

requires the use of CEMS to measure 

CO2 mass emissions. For each unit 

operating hour, the CO2 mass emissions 

are determined using either valid CEMS 

data or appropriate substitute data 

values when monitors malfunction. For 

a Tier 4 unit, the owner or operator has 

the option to follow the CEMS 

certification and QA provisions of 40 

CFR Part 60, 40 CFR Part 75, or an 

applicable State CEM program. This 

includes the criteria in those regulations 

pertaining to validation of the hourly 

CEMS data. 

The provisions for hourly CEMS data 

validation in Part 60 are found in 40 

CFR 60.13(h)(2)(i) through (h)(2)(vi). For 

Part 75, hourly data validation is 

addressed in 40 CFR 75.10(d)(1). The 

CEMS data validation criteria in these 

sections of Parts 60 and 75 are virtually 

identical. The basic requirement to 

validate an hour is that at least one data 

point must be obtained in each 15- 

minute quadrant of the hour in which 

the unit operates. There is one notable 

exception to this. For operating hours in 

which required maintenance or QA 

testing is performed, obtaining a valid 

data point in two of the four quadrants 

is sufficient. 

In subpart C, 40 CFR 98.34(c) 

provides the monitoring and QA 

requirements for Tier 4. However, no 

criteria for hourly CEMS data validation 

are specified. In view of this, we are 

proposing to add a new paragraph, 

(c)(7), to 40 CFR 98.34(c), which would 

require hourly CEMS data validation to 

be consistent with the sections of Part 

60 or Part 75 cited in the preceding 

paragraph. Alternatively, the hourly 


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48762 Federal Register / Vol. 75, No. 154 / Wednesday, August 11, 2010 / Proposed Rules 

data validation procedures in an 

applicable State CEM program could be 

followed. 

Use of ASTM Methods D7459–08 and 

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

subpart C, respectively, outline 

procedures for quantifying biogenic CO2

emissions for units that combust 

municipal solid waste (MSW) and other 

units that combust combinations of 

fossil fuels and biomass. As specified in 

Part 98, flue gas samples are taken 

quarterly using ASTM Method D7459– 

08 and analyzed using ASTM Method 

D6866–08. We are proposing to amend 

40 CFR 98.34(d) and (e), as discussed in 

the following paragraphs. 

The proposed amendments to 40 CFR 

98.34(d) would require the ASTM 

methods to be used when MSW is 

combusted in a unit, either as the 

primary fuel, or as the only fuel with a 

biogenic component. Quarterly 

sampling with ASTM Method D7459–08 

would still be required, for a minimum 

of 24 consecutive operating hours. 

However, we are proposing to add an 

alternative to allow the owner or 

operator to collect an integrated sample 

by extracting a small amount of flue gas 

(1 to 5 cubic centimeters (cc)) during 

every unit operating hour in the quarter, 

in order to obtain a more representative 

sample for analysis. This sampling 

approach is recommended by experts on 

the use of ASTM Methods D7459–08 

and D6866–08 when the types of fuel 

and their composition are variable over 

time, as is the case with MSW 

combustion. For more information 

please refer to the Background 

Technical Support Document (EPA– 

HQ–OAR–2008–0508). 

We are proposing to amend 40 CFR 

98.34(e) to remove the restriction 

limiting the use of ASTM Methods 

D7459–08 and D6866–08 to units with 

CEMS. Rather, any unit that combusts 

combinations of fossil and biogenic 

fuels (or partly biogenic fuels, such as 

tires), in any proportions, would be 

allowed to determine biogenic CO2

emissions using the ASTM methods on 

a quarterly basis. At least 24 consecutive 

hours of sampling is currently specified 

in 40 CFR 98.34(e). This is appropriate 

if the types of fuels and their relative 

proportions are consistent throughout 

the quarter. If the relative proportions 

are not consistent throughout the 

quarter, it may be more appropriate to 

consider collecting more frequent 

samples, however this is not required. 

Therefore, we are also amending 40 CFR 

98.34(e) to recommend that a small (1 to 

5 cc) flue gas sample be taken during 

each unit operating hour in the quarter. 

Electronic Data Reporting and 

Recordkeeping. EPA will rely on 

Agency verification of the electronic 

data provided in the annual GHG 

emission reports, in lieu of 

implementing third party verification. 

In order for Agency verification to be 

effective, sufficient information must be 

included in the electronic reports, at the 

facility, source category, and unit levels, 

to enable EPA to recalculate the 

reported GHG emissions and to qualityassure the data. 

Section 98.36 of subpart C provides 

several lists of data elements that must 

be reported for stationary combustion 

units. These lists are specific to the CO2

emissions calculation method employed 

(e.g., one of the four Tiers in 40 CFR 

98.33(a) or a method in 40 CFR Part 75), 

and to the type(s) of electronic data 

report(s) that are submitted (e.g., 

individual unit reports, aggregated 

group reports, common pipe reports, 

etc). 

EPA has begun developing software to 

check and verify the electronic data in 

the GHG emissions reports. As this 

effort has progressed, it has come to 

light that a number of important data 

elements are missing from the lists in 40 

CFR 98.36, and that some of the data 

elements on the lists are either not 

needed or require an excessive amount 

of non-essential data to be reported. 

To address these issues, we are 

proposing to amend the data element 

lists in 40 CFR 98.36 by adding a 

number of essential data elements and 

eliminating or modifying others. The 

most significant revisions to the data 

element lists are discussed in 

paragraphs (a) through (g), below. We 

are also proposing to add an additional 

alternative reporting option to 40 CFR 

98.36(c) to reduce the reporting burden 

for certain facilities. This option is 

described in paragraph (h), below. 

(a) We are proposing to add the 

reporting of methodology start and end 

dates in several places throughout 40 

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

elements are needed to accommodate 

changes in the methods used to 

calculate GHG emissions, when such 

changes occur during a reporting year or 

from one year to the next. 

(b) We are proposing to amend the 

data element lists in 40 CFR 98.36 to be 

consistent with respect to reporting of 

emissions by fuel type and reporting of 

biogenic CO2 emissions. 

(c) We are proposing to amend 40 CFR 

98.36(b)(10) to remove the requirement 

to report the customer meter number for 

units that combust natural gas. 

(d) We are proposing to amend a 

number of data elements to reduce the 

reporting burden. For example, when 

small combustion units are aggregated 

into a group, 40 CFR 98.36(c)(1)(ii) 

currently requires the ID number of each 

unit in the group to be reported. This 

requirement is unreasonable for 

facilities that have large numbers of very 

small combustion sources, many of 

which do not have unique ID numbers. 

We are, therefore, proposing to amend 

this data element to require that only 

the total number of units in the group 

be reported, instead of the ID number of 

each unit in the group. As a second 

example, for the common pipe option 

described in 40 CFR 98.36(c)(3), only 

the total number of units served by the 

common pipe would be reported, 

instead of reporting an ID number for 

each unit, and only the highest 

maximum rated heat input capacity of 

any unit served by the common pipe 

would be reported, rather than reporting 

the rated heat input capacity of each 

individual unit. 

(e) We are proposing to amend 40 CFR 

98.36 to remove the requirement to 

report the combined annual GHG 

emissions from fossil fuel combustion in 

metric tons of CO2e (i.e., the sum of the 

CO2, CH4, and N2O emissions) from 40 

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

and (c)(3)(viii). These data elements are 

duplicative of requirements in subpart 

A. 

(f) We are proposing to amend 40 CFR 

98.36(b), (c), and (d) to require reporting 

the fuel-specific annual heat input 

estimates, for the purpose of verifying 

the reported CH4 and N2O emissions. 

Also, we are proposing to amend 40 

CFR 98.36(e)(2)(iv) to require reporting 

of the annual average HHV when 

measured HHV data are used to 

calculate CH4 and N2O emissions for a 

Tier 3 unit, in lieu of using a default 

HHV from Table C–1. 

(g) We are proposing to amend 40 CFR 

98.36(b) and (d) to make the data 

elements reported under Tiers 1 through 

4 consistent for the reporting of biogenic 

CO2 emissions and CO2 from fossil fuel 

combustion. Also, as previously noted 

in section III.C of this preamble, the 

proposed amendments to 40 CFR 

98.36(d) would state that reporting of 

biogenic CO2 emissions is optional for 

units using the CO2 mass emissions 

calculation methods in 40 CFR Part 75. 

(h) For units that use the Tier 4 

methodology to calculate CO2 mass 

emissions, we are proposing to amend 

40 CFR 98.36(b)(7)(i) and (b)(7)(ii) 

(redesignated as 40 CFR 98.36(b)(9)(i) 

and (b)(9)(ii), respectively) and 40 CFR 

98.36 (c)(2)(vi) (redesignated as 40 CFR 

98.36 (c)(2)(viii)). The proposed 

amendments to these sections will 

require the annual ‘‘non-biogenic’’ CO2

mass emissions to be reported instead of 

reporting the annual CO2 mass 

emissions from fossil fuel combustion. 


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These revisions are being proposed 

because the total annual CO2 mass 

emissions measured by CEMS 

sometimes includes CO2 from sorbent or 

process CO2 emissions in addition to 

CO2 from fossil fuel combustion. The 

effect of the proposed amendments 

would be to simplify reporting for Tier 

4 units that have sorbent or process CO2

emissions in the flue gas stream. These 

units would be required only to report 

the combined annual non-biogenic CO2

mass emissions, rather than having to 

separately account for the fossil CO2

emissions. Tier 4 units that do not have 

any sorbent or process CO2 emissions in 

the flue gas would be unaffected by 

these proposed revisions, because their 

non-biogenic CO2 emissions are entirely 

from fossil fuel. 

(i) We are proposing to add a new 

alternative reporting option, under 40 

CFR 98.36(c)(4). This new option would 

apply to specific situations where a 

common liquid or gaseous fuel supply 

is shared between large combustion 

units such as boilers or combustion 

turbines (including Acid Rain Program 

units and other combustion units that 

use the methods in 40 CFR Part 75 to 

calculate CO2 mass emissions), and 

small combustion sources such as space 

heaters, hot water heaters, etc. In such 

cases, you could simplify reporting by 

attributing all of the GHG emissions 

from combustion of the shared fuel to 

the large combustion unit(s), provided 

that: 

• The total quantity of the shared fuel 

supply that is combusted during the 

report year is measured, either at the 

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

the facility, using a fuel flow meter, a 

billing meter or tank drop 

measurements; and 

• On an annual basis, at least 95 

percent of the shared fuel supply (by 

mass or volume) is burned in the large 

combustion unit(s) and the remainder of 

the fuel is fed to the small combustion 

sources. 

Use of company records would be 

allowed to determine the percentage 

distribution of the shared fuel to the 

large and small units. Facilities using 

this reporting option would be required 

to document in their monitoring plan 

which units share the common fuel 

supply and the method used to 

determine that the reporting option 

applies. For the small combustion 

sources, a description of the type(s) and 

approximate number of units involved 

would suffice. 

(j) Finally, we are proposing to 

simplify the record keeping 

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

in cases where the results of fuel 

analyses for HHV are provided by the 

fuel supplier. Parallel language would 

be added in a new paragraph, 

(e)(2)(v)(E), for the results of carbon 

content and molecular weight analyses 

received from the fuel supplier. In both 

cases, the owner or operator would be 

required to keep records of only the 

dates on which the fuel sampling results 

are received, rather than keeping 

records of the dates on which the 

supplier’s fuel samples were taken 

(which dates may not be readily 

available). 

We believe that these proposed 

amendments to the recordkeeping and 

reporting requirements of 40 CFR 98.36 

are needed for data verification 

purposes. The proposed amendments 

are not likely to increase the reporting 

burden on industry. In some cases, as 

previously noted, the proposed 

amendments would actually reduce the 

amount of information that must be 

collected or reported and the associated 

burden. 

Common Stack Reporting Option. 

Section 98.36(c)(2) of subpart C 

currently allows Subpart C stationary 

fuel combustion units that share a 

common stack or duct to use the Tier 4 

Calculation Methodology to monitor 

and report the combined CO2 mass 

emissions at the common stack or duct, 

in lieu of monitoring each unit 

individually. However, 40 CFR 

98.36(c)(2) does not address 

circumstances where at least one of the 

units sharing the common stack is not 

a Subpart C stationary fuel combustion 

unit, but is subject to another subpart of 

Part 98. For example, if a Subpart G 

ammonia manufacturing unit shares a 

common stack with a Subpart C 

stationary combustion unit, the use of 

Tier 4 may be required (see 40 CFR 

98.73(c)). 

In view of this, we are proposing to 

amend 40 CFR 98.36(c)(2) by extending 

the applicability of the common stack 

monitoring and reporting option to 

situations where off-gases from multiple 

process units or mixtures of combustion 

products and process off-gases are 

combined together and vented through 

a common stack or duct. 

The proposed amendments to 40 CFR 

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

ordinary common stack or duct 

situations where the gas streams from 

multiple units are combined together, 

but would also apply when process and 

combustion gas streams from a single 

unit (e.g., from a kiln, furnace, or 

smelter) are combined. To accommodate 

this variation on the traditional concept 

of a common stack, 40 CFR 

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

require sources to report ‘‘1’’ as the 

‘‘Number of units sharing the common 

stack or duct’’ when process and 

combustion emissions from a single unit 

are combined and vented through the 

same stack or duct. 

Finally, since the concept of 

maximum rated heat input capacity may 

not be applicable to certain types of 

process or manufacturing units, we are 

proposing to amend 40 CFR 

98.36(c)(2)(iii), to require that the 

‘‘Combined maximum rated heat input 

capacity of the units sharing the 

common stack or duct’’ only be reported 

when all of the units sharing the 

common stack or duct are stationary 

fuel combustion units. 

Common Fuel Supply Pipe Reporting 

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

currently allows units that are served by 

a common fuel supply pipe to report the 

combined CO2 emissions from all of the 

units in lieu of reporting CO2 emissions 

separately from each unit. To use this 

reporting option, the total amount of 

fuel combusted in the units must be 

accurately measured with a flow meter 

calibrated according to the requirements 

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

states that the applicable Tier to use for 

this reporting option is based on the 

maximum rated heat input of the largest 

unit in the group. 

We are proposing to amend 40 CFR 

98.36(c)(3) as follows. First, the 

erroneous citation of ‘‘§ 98.34(a)’’ would 

be corrected to read ‘‘§ 98.34(b).’’ 

Second, we are proposing to amend the 

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

calibrate the fuel flow meter to the 

accuracy required by 40 CFR 98.34(b) 

(which cross-references the accuracy 

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

this calibration requirement would 

apply only when Tier 3 is the required 

tier for calculating CO2 mass emissions. 

The Agency believes that this 

clarification is needed, since the 

common pipe option can apply to Tier 

1, 2, or 3, depending on the rated heat 

input capacities of the units served by 

the common pipe. Tiers 1 and 2 rely on 

company records to quantify fuel usage. 

Therefore, as noted in today’s proposed 

amendments to 40 CFR 98.3(i), the 

equipment used to generate company 

records under Tier 1 and 2 is not 

required to meet the calibration 

accuracy specifications of 40 CFR 

98.3(i). 

As previously noted, the applicable 

measurement Tier for the common pipe 

option, according to subpart C, is based 

on the rated heat input capacity of the 

largest unit in the group. On the surface, 

this appears to mean that the use of 

Tiers 1 and 2 is restricted to common 

pipe configurations where the highest 

rated heat input capacity of any unit is 


srobinson on DSKHWCL6B1PROD with PROPOSALS2
48764 Federal Register / Vol. 75, No. 154 / Wednesday, August 11, 2010 / Proposed Rules 

250 mmBtu/hr or less, and that Tier 3 

is required if any unit has a maximum 

rated heat input capacity greater than 

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

However, there is one exception in the 

current rule and we are proposing to 

add a second one. First, 40 CFR 

98.33(b)(2)(ii) allows the use of Tier 2 

instead of Tier 3 for the combustion of 

natural gas and/or distillate oil in a unit 

with a rated heat input capacity greater 

than 250 mmBtu/hr. Second, proposed 

40 CFR 98.33(b)(1)(v) would allow Tier 

1 to be used when natural gas 

consumption is determined from billing 

records, and fuel usage on those records 

is expressed in units of therms. 

Therefore, we are also proposing to 

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

these two exceptions for common pipe 

configurations that include a unit with 

a maximum rated heat input capacity 

greater than 250 mmBtu/hr. 

Finally, we are proposing to amend 

the provision in 40 CFR 98.36(c)(3) 

regarding the partial diversion of a fuel 

stream such as natural gas that is 

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

using a calibrated flow meter or a gas 

billing meter). Subpart C specifies that 

when part of a fuel stream is diverted to 

a chemical or industrial process where 

it is used but not combusted, and the 

remainder of the fuel is sent to a group 

of combustion units, you may subtract 

the diverted portion of the fuel stream 

from the total quantity of the fuel 

measured at the gate before applying the 

common pipe methodology to the 

combustion units. We are proposing to 

expand this provision to include cases 

where the diverted portion of the fuel 

stream is sent either to a flare or to 

another stationary combustion unit (or 

units) on-site, including units that use 

Part 75 methodologies to calculate 

annual CO2 mass emissions (e.g., Acid 

Rain Program units). Provided that the 

GHG emissions from the flare and/or 

other combustion unit(s) are properly 

accounted for according to the 

applicable subpart(s) of Part 98, you 

would be allowed to subtract the 

diverted portion of the fuel stream from 

the total quantity of the fuel measured 

at the gate, and then apply the common 

pipe reporting option to the group of 

combustion units served by the common 

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

calculation methodology (as applicable). 

Table C–1. Table C–1 of Subpart C 

provides default HHV values and 

default CO2 emission factors for various 

types of fuel. These default values are 

needed to calculate CO2 mass emissions 

when the Tier 1 and Tier 2 

methodologies in 40 CFR 98.33(a) are 

used. The fuels listed in Table C–1 are 

grouped into general categories (e.g., 

coal and coke, petroleum products, 

biomass fuels). Some distinctions are 

made within these categories, based on 

the state of matter (e.g., biomass fuels— 

liquid, fossil fuel-derived fuels (solid), 

etc.). 

Since publication of the final Part 98, 

EPA has received many questions about 

the content and structure of Table C–1. 

Owners and operators in various 

industries have raised a number of 

issues concerning the way that fuels are 

categorized, the description of certain 

fuels, the units of measure of some of 

the default HHV values, and the absence 

of some fuels that were listed in Table 

C–2 of the April 10, 2009 proposed rule. 

In particular: 

(a) The categories ‘‘fossil fuel-derived 

fuels (solid)’’ and ‘‘fossil fuel-derived 

fuels (gaseous)’’ did not appear in the 

April 10, 2009 proposed rule and have 

been the source of some confusion. For 

instance, only two fuels, MSW and tires, 

are listed under ‘‘fossil fuel-derived 

fuels (solid),’’ and neither of these is 

derived entirely from fossil fuels. Both 

of these fuels have a biogenic 

component. There are also only two 

fuels, blast furnace gas and coke oven 

gas, listed in the ‘‘fossil fuel-derived 

fuels (gaseous)’’ category. Several other 

fuels that are derived from petroleum 

and qualify as fossil fuel-derived 

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

a different category, ‘‘petroleum 

products.’’ 

(b) Questions have arisen about the 

revised description of ‘‘natural gas’’ in 

Table C–1. The word ‘‘pipeline,’’ which 

was not in the April 10, 2009 proposed 

rule, was added in the final subpart C. 

(c) The Agency has received questions 

about the meaning of the terms ‘‘wood 

residuals,’’ ‘‘solid byproducts,’’ and 

‘‘agricultural byproducts,’’ none of 

which appeared in the April 10, 2009 

proposed rule. 

(d) Questions have been asked why 

certain fuels that were listed in Table 

C–2 of the April 10, 2009 proposed rule 

do not appear in Table C–1. These 

include waste oil and plastics. 

(e) Owners and operators have 

questioned the appropriateness of the 

units of measure for still gas listed 

under ‘‘petroleum products.’’ The HHV 

for still gas, which is in the gaseous 

state at ambient temperatures, is given 

in mmBtu per gallon, as though it were 

in the liquid state. 

(f) Some industry questions indicate 

that reporters believe that the footnote 

beneath Table C–1 appears to prohibit 

MWC units that produce steam from 

using the default CO2 emission factor in 

the Table. This emission factor is 

needed to apply the Tier 2 CO2

emissions calculation methodology 

(specifically, Equation C–2c) to those 

units. 

(g) EPA has received questions 

regarding the significance of indicating 

one hundred percent for ethanol and 

biodiesel, as well as questions regarding 

which emission factors to use for 

petroleum-derived ethanol. 

In view of these considerations, we 

are proposing the following revisions to 

Table C–1: 

• The categories ‘‘fossil fuel-derived 

fuels (solid)’’ and ‘‘fossil fuel-derived 

fuels (gaseous)’’ would be replaced with 

more inclusive terms, i.e., ‘‘other fuels 

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

‘‘other fuels (solid)’’ category would 

include four fuels: Plastics, municipal 

solid waste, tires, and petroleum coke. 

The ‘‘other fuels (gaseous)’’ category 

would include blast furnace gas, coke 

oven gas, propane gas, and fuel gas. 

• The word ‘‘pipeline’’ would be 

removed from the description of natural 

gas. 

• The following fuels: ‘‘wood 

residuals,’’ ‘‘agricultural byproducts,’’ 

and ‘‘solid byproducts’’ would be 

retained, but definitions of these terms 

would be added to 40 CFR 98.6. 

• ‘‘Waste oil’’ would be added to the 

list of petroleum products, and a 

definition would be added to 40 CFR 

98.6. 

• Still gas would be removed from the 

list of petroleum products. 

• The footnote regarding MWC units 

would be revised to make it clear that 

MWC units that produce steam are only 

prohibited from using the default HHV 

for MSW in Table C–1; MWC units that 

produce steam can still use the default 

CO2 emission factor for MSW. 

• The qualifier of one hundred 

percent for ethanol and biodiesel would 

be removed since these fuel types 

should be treated in the same way as 

other fuel types included in Table C–1. 

Removing this qualifier would clarify 

this without affecting any other 

provisions the rule. 

• A default CO2 emission factor and 

a default high heat value would be 

added to the Table for petroleumderived ethanol. These would be the 

same as the default values for biomassderived ethanol. 

We are soliciting comment on these 

proposed amendments to Table C–1. 

Specifically, we request comment on: 

(1) The new and revised fuel categories; 

(2) the appropriateness of the HHVs and 

CO2 emission factors for the fuels listed 

in these categories; and (3) whether 

additional fuels should be included in 

Table C–1, and if so, what the HHVs and 

CO2 emission factors for those fuels 

should be. 


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Federal Register / Vol. 75, No. 154 / Wednesday, August 11, 2010 / Proposed Rules 48765 

Table C–2. In the October 30, 2009 

publication of Part 98, two essentially 

identical iterations of Table C–2 of 

Subpart C were printed. The first 

iteration of Table C–2 was a printing 

error. We are proposing to remove the 

first iteration of the Table and to make 

minor corrections to the second one. 

The proposed amendments consist of 

correcting the exponents of the emission 

factors. The powers of ten in the righthand column of the Table currently 

have an ‘‘underscore’’ character where 

there should be a minus sign, and one 

of the exponents is missing a zero. 

Miscellaneous Proposed Revisions. In 

addition to the more substantive 

proposed amendments to Subpart C, we 

are proposing to correct a number of 

typographical errors, and to re-word the 

rule text in a few places for added 

clarity. We are also proposing to amend 

40 CFR 98.34(c) by adding the citations 

from 40 CFR Part 75 that pertain to the 

initial certification of Tier 4 moisture 

monitoring systems. Although these rule 

citations were inadvertently omitted 

from the October 30, 2009 publication of 

Part 98, we believe that Tier 4 sources 

understand that all required CEMS, 

including moisture monitoring systems, 

must be initially certified. 

How Would These Amendments to 

Subpart C Apply to the 2011 GHG 

Emissions Reports? EPA plans to 

address the comments on the proposed 

amendments to Subpart C and to 

publish the final amendments before the 

end of 2010. Therefore, reporters would 

be expected to use provisions of Part 98, 

as amended, to collect the relevant data 

and to calculate GHG emissions for the 

reports that are submitted in 2011. We 

believe it is feasible for the sources to 

use the proposed changes to Subpart C 

for the 2010 reporting year, because the 

proposed revisions, to a great extent, 

simply clarify existing regulatory 

requirements. Further, the proposed 

amendments do not substantially affect 

the type of information that must be 

collected or how emissions are 

calculated. 

The following are examples of how 

the proposed amendments to Subpart C 

would clarify existing regulatory 

requirements. The amendments would 

clarify: 

• That reporting of biogenic CO2

emissions is optional for units using the 

CO2 mass emissions calculation 

methodologies in 40 CFR Part 75. 

• How CH4 and N2O emissions are 

calculated for multi-fuel units that use 

the Tier 4 CO2 mass emissions 

calculation methodology. 

• How to determine whether Tier 4 

applies to various common stack 

configurations. 

• How to determine which Tier (i.e., 

1, 2, or 3) applies to common pipe 

configurations. 

• How to calculate biogenic 

emissions for various types of units and 

fuels. Unnecessary restrictions on the 

use of certain calculation methods 

would be removed. 

• How to apply the definition of a 

‘‘fuel lot’’ at facilities that receive 

frequent deliveries of coal or fuel oil. 

• How to calculate CO2, CH4, and 

N2O emissions for blended fuels. 

The proposed amendments to 40 CFR 

98.36, the data reporting section of 

Subpart C, would achieve two main 

purposes: (1) To ensure that enough 

data are provided to enable the Agency 

to recalculate and verify the emissions 

data; and (2) to reduce burden, by 

removing the requirement to report 

certain non-essential data elements and 

by modifying other data elements. 

For example, the proposed 

amendments would: 

• Require methodology start and end 

dates to be reported. This will enable us 

to track changes in emissions 

calculation methodologies (e.g., 

switching from a lower Tier to a higher 

Tier). 

• Generally require reporting of fuelspecific CH4 and N2O emissions. This 

requirement was inconsistently applied 

in Part 98. 

• Eliminate the need to report 

individual unit ID numbers and unit 

heat input capacities for groups of 

aggregated units, common pipe 

configurations, and common stack 

configurations. 

• Remove the unnecessary 

requirement to report unit-level 

combined CO2, CH4, and N2O emissions 

from fossil fuel combustion. 

• Remove the requirement for natural 

gas users to report their customer meter 

ID numbers. 

• Emphasize that biogenic CO2

emissions reporting is optional for Part 

75 units. 

EPA believes that amendments such 

as these can be implemented for the 

reports submitted to EPA in 2011 

because the proposed changes are either 

consistent with or have no significant 

effect upon the calculation 

methodologies in Part 98. Since owners 

or operators are not required to report 

until March 2011, which is several 

months after we expect this proposal to 

be finalized, sources should have 

sufficient time to adjust to the revisions. 

Several other proposed amendments 

to Subpart C address issues identified as 

a result of working with the affected 

sources during rule implementation. 

These proposed amendments would add 

flexibility to the rule. Owners or 

operators would be free to implement 

these new rule provisions once they are 

finalized. The following are examples of 

how today’s proposed Subpart C 

amendments would make the rule more 

flexible. The proposed amendments 

would: 

• Allow fuel flow meters that 

measure on a mass basis to be used for 

gaseous fuels as well as liquid fuels, 

provided that the flow rate 

measurements are corrected for density. 

• Allow the span of CO2 monitors to 

be set higher than 20 percent CO2 if 

necessary, when process CO2 and 

combustion CO2 emissions exit to the 

atmosphere through a common stack. 

• Allow the use of site-specific 

default moisture values for Tier 4 units 

that measure CO2 concentration on a dry 

basis. 

• Provide a new Tier 1 equation for 

calculating CO2 mass emissions when 

fuel usage data obtained from gas billing 

records is expressed in units of therms. 

• Allow smaller Tier 2 units (less 

than 100 mmBtu/hr) that receive 

monthly (or more frequent) HHV data to 

use an arithmetic average annual HHV 

in the emissions calculations instead of 

a fuel-weighted average HHV. 

• Allow Tier 4 units to use an 

alternative (non-CEMS) method to 

account for the volumetric flow rate of 

a slip stream, when a portion of the flue 

gas is diverted and exhausts through a 

separate stack. 

• Allow fuel oil sampling to be 

performed upon each addition of oil to 

the storage tank, as an alternative to 

sampling each fuel lot. 

• Remove the lists of specific 

methods for determining HHV and 

carbon content and for fuel flow meter 

calibration, and specify instead that 

sources must either use appropriate 

methods from consensus standards 

organizations if such methods exist, or 

standard industry practice. 

• Add a new reporting option for 

configurations in which a common 

supply of gaseous or liquid fuel is 

shared between large combustion units 

and a group of smaller units such as 

space heaters, hot water heaters, etc. If 

at least 95 percent of the shared fuel is 

used by the large units, 100 percent of 

the GHG emissions from combustion of 

that fuel may be attributed to the large 

units. 

In some cases, facilities may have 

been following their current data 

collection practices during 2010, as well 

as using the methods required by Part 

98. If a facility’s current practice 

provides the necessary data to 

implement the new options described 

immediately above, or if such data 

could be obtained and processed prior 


srobinson on DSKHWCL6B1PROD with PROPOSALS2
48766 Federal Register / Vol. 75, No. 154 / Wednesday, August 11, 2010 / Proposed Rules 

to the March 31, 2011 reporting 

deadline, the new options could be used 

for the reports submitted to EPA in 

2011. 

Finally, the proposed amendments 

would make minor corrections to terms 

and definitions in certain Subpart C 

equations, and other technical 

corrections that would have no impact 

on facility’s data collection efforts in 

2010. 

In summary, EPA believes that, in 

general, the proposed amendments to 

Subpart C would not require monitoring 

or information collection above what is 

already required by Part 98. Therefore, 

we expect that sources will be able to 

use the same information that they have 

been collecting under Part 98 to 

calculate and report GHG emissions for 

2010. 

EPA seeks comment on its conclusion 

that the amendments to Subpart C can 

be implemented and incorporated into 

the initial GHG emissions reports by the 

due date of March 31, 2011. 

Specifically, we seek comment on 

whether this timeline is feasible or 

appropriate, considering the nature of 

the proposed changes and the way in 

which data have been collected thus far 

in 2010. We request that commenters 

provide specific reasons why they 

believe that the proposed 

implementation schedule would or 

would not be feasible. 

H. Subpart D (Electricity Generation) 

We are proposing to amend 40 CFR 

98.40(a) by adding the word ‘‘mass’’ 

between the words ‘‘CO2’’ and 

‘‘emissions’’ to make it clear that Subpart 

D applies only to units in two 

categories: (a) ARP units; and (b) nonARP electricity generating units (EGUs) 

that are required to report CO2 mass 

emissions data to EPA year-round. At 

present, category ‘‘(b)’’ includes only 

non-ARP units that are subject to the 

Regional Greenhouse Gas Initiative 

(RGGI) in the northeastern United 

States. 

Many non-ARP EGUs that are not in 

the RGGI are subject to the Clean Air 

Interstate Rule (CAIR). Some of these 

CAIR units report CO2 concentration 

data to EPA year-round, for the 

purposes of calculating NOX emission 

rates in lb/mmBtu and/or heat input 

rates in mmBtu/hr. However, they do 

not report CO2 mass emissions data to 

the Agency. Therefore, they are subject 

to Subpart C of Part 98, not Subpart D. 

Data Reporting Requirements. Section 

98.46 of subpart D currently specifies 

that the owner or operator of a Subpart 

D unit must comply with the data 

reporting requirements of 40 CFR 

98.36(b) and, if applicable, 40 CFR 

98.36(c)(2) or (c)(3). These section 

citations are incorrect. Subpart D units 

all use the CO2 mass emissions 

calculation methodologies in 40 CFR 

Part 75. Therefore, the applicable data 

reporting section for these units is 40 

CFR 98.36(d), not 40 CFR 98.36(b), 40 

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

We are proposing to amend 40 CFR 

98.46 to correct this error. 

Recordkeeping. We are proposing to 

amend 40 CFR 98.47 to state that the 

records kept under 40 CFR 75.57(h) for 

missing data events satisfy the 

recordkeeping requirements of 40 CFR 

98.3(g)(4) for those same events. We 

believe that, as a practical matter, the 

missing data records required to be kept 

under 40 CFR 75.57(h) are substantially 

equivalent to the records required under 

40 CFR 98.3(g)(4). 

I. Subpart F (Aluminum Production) 

Throughout Subpart F we are 

proposing corrections as needed for 

typographical errors and alphanumeric 

sequencing. We are proposing to amend 

40 CFR 98.63, Calculating GHG 

Emissions, to clarify that each 

perfluorocarbon (PFC) compound (CF4, 

C2F6) must be quantified and reported 

and to clarify in 40 CFR 98.63(c) that 

reporters must use CEMS if the process 

CO2 emissions from anode consumption 

during electrolysis or anode baking of 

prebake cells are vented through the 

same stack as a combustion unit 

required to use CEMS. This requirement 

existed in the final rule, however, the 

cross-reference was omitted from the 

introductory language of 40 CFR 

98.63(c). 

We are proposing to amend 40 CFR 

98.64, Monitoring and QA/QC, to clarify 

the type of parameters that must be 

measured in accordance with the 

recommendations of the EPA/IAI 

Protocol for Measurement of 

Tetrafluoromethane (CF4) and 

Hexafluoroethane (C2F6) Emissions from 

Primary Aluminum Production (2008), 

and the frequency of monitoring for 

those parameters which are not 

measured annually, but are instead 

measured on a more or less frequent 

basis. We are proposing a modification 

to Table F–2 to clarify that default CO2

emissions from pitch volatiles 

combustion are relevant only for center 

work pre-bake (CWPB) and side work 

pre-bake (SWPB) technologies. 

We are also proposing to amend Table 

F–1 to spell out the acronyms for the 

technologies covered by that table; i.e., 

CWPB, side worked prebake (SWPB), 

vertical stud S<derberg (VSS), and 

horizontal stud S<derberg (HSS). 

J. Subpart G (Ammonia Manufacturing) 

We are proposing to amend subpart G 

to remove reporting of the waste recycle 

stream or purge, and to make subpart G 

conform to the proposed amendments to 

the calibration requirements in Subpart 

A. With respect to the waste recycle 

stream, we are proposing to eliminate 

the calculation, monitoring and 

reporting of the emissions associated 

with the waste recycle stream or purge 

currently required by Equation G–6 

from 40 CFR 98.73, 98.74, 98.75, and 

98.76. Carbon dioxide emissions from 

waste recycle stream or purge gas used 

as fuel will still be accounted for 

accurately using Equation G–5 in 

Subpart G. Because total process 

emissions, calculated using Equation G– 

5, will also account for emissions 

associated with use of the purge gas as 

a fuel, we are proposing to amend 40 

CFR 98.72(b) so that subpart C does not 

apply to CO2 emissions resulting from 

the use of purge gas as a fuel. 

With respect to calibration 

requirements, we are proposing to 

clarify the calibration requirements for 

gas and oil flow meters used in the 

ammonia manufacturing process. 

Section 98.74(d) of subpart G currently 

states that all oil and gas flow meters 

except for gas billing meters must be 

calibrated according to the requirements 

for the Tier 3 methodology in 40 CFR 

98.34(b). The Agency believes that the 

words ‘‘all oil and gas flow meters’’ in 

this subpart G provision are too 

inclusive and subject to 

misinterpretation. Therefore, we are 

proposing to amend 40 CFR 98.74(d) to 

limit the flow meter calibration 

accuracy requirements of 40 CFR 

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

are used to measure liquid and gaseous 

feedstock volumes. In accordance with 

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

device that is not used to measure liquid 

and gaseous feedstock volumes, but is 

used to provide data for the GHG 

emissions calculations would have to be 

calibrated to an accuracy within the 

appropriate error range for the specific 

measurement technology, based on an 

applicable operating standard, such as 

the manufacturer’s specifications. 

We are proposing to note through 

parentheticals in a number of places 

that the CO2 emissions estimates may 

include CO2 that is later consumed onsite for urea production and therefore 

not released to the atmosphere from the 

ammonia manufacturing process unit. 

This proposed change does not impact 

the total CO2 emissions that are 

quantified and reported to EPA under 

the calculation equations in 40 CFR 

98.73. The clarification is proposed so 


srobinson on DSKHWCL6B1PROD with PROPOSALS2
Federal Register / Vol. 75, No. 154 / Wednesday, August 11, 2010 / Proposed Rules 48767 

3 D. Terry, 2006. ‘‘Fertilizer Tonnage Reporting in 

the U.S.—Basis and Current Need.’’ Better Crops. 

90(4). pp 14–17. 

that it is transparent for stakeholders 

who ultimately use these data that some 

CO2 process emissions reported by the 

ammonia manufacturing process unit 

under this subpart may not be released 

from ammonia manufacturing, but at the 

point of urea application. To further 

enhance this transparency, EPA is also 

proposing to require reporting under 40 

CFR 98.76 of the CO2 from the ammonia 

manufacturing process unit that is then 

used to produce urea and the method 

used to determine that quantity of CO2

consumed. 

In addition, we are proposing to 

amend Subpart G to correct several 

typographical errors and an incorrect 

cross-reference to another subpart in 

Part 98. We are proposing to correct the 

terms and definitions for annual CO2

emissions arising from gaseous, liquid, 

and solid fuel feedstock consumption in 

Equations G–1, G–2, and G–3, 

respectively, in 40 CFR 98.73. We are 

proposing to correct 40 CFR 98.76(a) by 

changing the cross-reference from 

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

We are proposing to amend the data 

reporting requirements in 40 CFR 

98.76(b)(6) and (15) for consistency with 

the calculation procedures in 40 CFR 

98.73(b)(6). We are proposing to amend 

40 CFR 98.76(b)(6) to change ‘‘petroleum 

coke’’ to ‘‘feedstock’’ because petroleum 

coke is the incorrect term, and to amend 

40 CFR 98.76(b)(15) to specify that the 

carbon content analysis method being 

reported is for each month. 

We are proposing to remove 40 CFR 

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

produced, if known. EPA finalized 

reporting of this information to help 

improve methodologies for calculating 

emissions from ammonia 

manufacturing, urea production and 

urea consumption. Reporters stated that 

these data are already reported 

periodically to EPA under the Toxic 

Substances Control Act (TSCA) 

Inventory Update Rule (IUR). Although 

the TSCA IUR does not provide the full 

range of information that may ultimately 

be useful for informing future policy, 

EPA believes that the TSCA IUR 

provides adequate information at this 

time and, therefore, we are proposing to 

delete that requirement. 

Finally, 40 CFR part 98, subpart G 

(Ammonia Manufacturing) and subpart 

V (Nitric Acid Production) require that 

facilities report total pounds of 

synthetic fertilizer and total nitrogen 

contained in that fertilizer. After 

considering additional information 

provided by stakeholders, as well as 

other available information, we are 

proposing to remove the requirement 

from both subparts. EPA’s rationale for 

removing the requirement is as follows 

(i) The data that would be reported 

under these subparts do not provide 

directly applicable information with 

which to determine N2O emissions from 

application of fertilizer because the data 

are incomplete. Domestic producers of 

synthetic nitrogen-based fertilizer make 

up less than one-half of the total amount 

of synthetic nitrogen-based fertilizer 

used in the United States. The 

remaining share is made up by synthetic 

nitrogen-based fertilizer imports, as well 

as fertilizer produced domestically 

outside of the Nitric Acid and Ammonia 

production industries using imported 

ammonia and nitric acid. 

(ii) EPA has information on the total 

supply and use of synthetic nitrogenbased fertilizer from other data sources 

that addresses near-term analytical 

needs, particularly for calculating 

national emissions of N2O. We obtain 

current sales data from Association of 

American Plant Food Control Officials 

(AAPFCO). The sales data is equivalent 

to fertilizer application since the sales 

are from the last licensed dealer. 

EPA remains very interested in 

obtaining better data on N2O emissions. 

Nitrous oxide emissions from 

agricultural soils are an important 

source of greenhouse gas emissions in 

the United States (approximately 3 

percent in 2008), and the application to 

soils of synthetic nitrogen-based 

fertilizer represents 26 percent of total 

N2O emissions from this source. 

EPA will continue to assess the need 

for a fertilizer reporting requirement 

from domestic producers in the future 

in light of new information or 

identification of policy or program 

needs. Further, EPA recognizes that 

States play an important role in 

collecting the data EPA currently uses, 

and the AAPFCO has indicated in a 

published article that recent stresses on 

state budgets potentially threaten the 

continued availability of these data.3 If 

data collection is compromised further 

due to reduced state funding or other 

circumstances, EPA will need to initiate 

a fertilizer reporting requirement. 

EPA will also assess the need for 

information on the total supply of 

synthetic nitrogen-based fertilizer, 

including imports, production of 

fertilizer using imported feedstock, 

domestically-produced fertilizer that is 

not in the agriculture sector, and 

fertilizer exports. 

Additionally, EPA will also assess the 

need for other types of information (i.e., 

not related to fertilizer supply) relevant 

to determining emissions and assessing 

mitigation opportunities for N2O 

emissions from agricultural soils, 

consistent with the Clean Air Act. 

Examples of other types of information 

that is relevant to N2O oxide emissions 

from agricultural soils can be found in 

the ‘‘Technical Support Document for 

Biologic Process Sources Excluded from 

this Rule,’’ and include elements such as 

fertilizer application rates, timing of 

application, and the use of slow-release 

fertilizers and nitrification/urease 

inhibitors (Docket ID No. EPA–HQ– 

OAR–2008–0508). 

If EPA were to decide in the future to 

add a requirement to report fertilizer 

production under the Mandatory GHG 

Reporting Rule, or any other new 

requirement related to N2O emissions 

from agricultural soils, it would initiate 

a new rulemaking process. 

K. Subpart P (Hydrogen Production) 

We are proposing several conforming 

amendments to be consistent with the 

proposed amendments to the calibration 

requirements of 40 CFR 98.3(i). Section 

98.164(b)(1) of subpart P currently 

specifies that all oil and gas flow meters 

(except for gas billing meters), solids 

weighing equipment, and oil tank drop 

measurements must be calibrated 

according to 40 CFR 98.3(i). We are 

proposing to amend 40 CFR 98.164(b)(1) 

to make it consistent with today’s 

proposed amendments to 40 CFR 

98.3(i). First, we would limit the flow 

meter calibration accuracy requirements 

of 40 CFR 98.3(i)(2) and (i)(3) to meters 

that are used to measure liquid and 

gaseous feedstock volumes. In 

accordance with 40 CFR 98.3(i)(1), all 

other measurement device that are used 

to provide data for the GHG emissions 

calculations would have to be calibrated 

to an accuracy within the appropriate 

error range for the specific measurement 

technology, based on an applicable 

operating standard, such as the 

manufacturer’s specifications. Second, 

we would remove the requirements for 

solids weighing equipment and oil tank 

drop measurements to be calibrated 

according to 40 CFR 98.3(i), because the 

provisions of 40 CFR 98.3(i) would 

apply only to gas and liquid flow 

meters. For oil tank drop measurements, 

the QA requirements of 40 CFR 

98.34(b)(2) would apply. 

L. Subpart V (Nitric Acid Production) 

We are proposing to amend 40 CFR 

98.226 to remove the synthetic fertilizer 

and total nitrogen reporting requirement 

in 40 CFR 98.226(o). The detailed 

rationale for this proposed amendment 

is provided in section II.K of this 

preamble. 


srobinson on DSKHWCL6B1PROD with PROPOSALS2
48768 Federal Register / Vol. 75, No. 154 / Wednesday, August 11, 2010 / Proposed Rules 

M. Subpart X (Petrochemical 

Production) 

Numerous issues have been raised by 

owners and operators in relation to the 

requirements in subpart X for 

petrochemical production facilities. The 

issues being addressed by the proposed 

amendments include the following: 

• Distillation and recycling of waste 

solvent. 

• Process vent emissions monitored 

by CEMS. 

• Process off-gas combustion in flares. 

• CH4 and N2O emissions from 

combustion of process 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. 

• Reporting requirements for the 

ethylene-specific option. 

• Reporting measurement device 

calibrations. 

Distillation and Recycling of Waste 

Solvent. We are proposing to add a new 

paragraph 40 CFR 98.240(g) to specify 

that a process that distills or recycles 

waste solvent that contains a 

petrochemical is not part of the 

petrochemical production source 

category. Some processes that distill or 

recycle waste solvents may produce 

products that contain methanol or 

another petrochemical. Under the 

current subpart X, such processes might 

be considered part of the petrochemical 

source category because 40 CFR 

98.240(a) specifies that all processes 

that produce a petrochemical are part of 

the source category unless specifically 

excluded. Although not specifically 

excluded in subpart X, we did not 

intend to include waste solvent 

purification processes in the 

petrochemical source category for the 

following reasons. First, in processes 

subject to subpart X, the petrochemical 

is formed from other chemicals, whereas 

in waste solvent purification processes 

the petrochemical is not formed because 

it is present in the feedstock. Second, 

processes that are in the source category 

generate significant amounts of processbased GHG emissions as byproducts of 

reaction and/or from the combustion of 

process off-gas for energy recovery. In 

contrast, the only process-based GHG 

emissions, if any, from waste solvent 

purification processes are from 

combustion of organic compounds in 

process vent emissions that are routed 

to a combustion-based air pollution 

control device. 

Process vent emissions monitored by 

CEMS. We are proposing to add a 

sentence to 40 CFR 98.242(a)(1) that 

specifies CO2 emissions from process 

vents routed to stacks that are not 

associated with stationary combustion 

units must be reported under subpart X 

when you comply with the CEMS 

option in 40 CFR 98.243(b). Section 

98.242(a)(1) in the current subpart X 

specified that GHG emissions from 

stationary combustion sources and 

flares that burn any amount of 

petrochemical off-gas are to be reported 

under subpart X. However, we neglected 

to specify reporting requirements under 

the CEMS option for process emissions 

that are not associated with combustion 

units. The proposed amendment would 

correct this oversight. 

Process off-gas combustion in flares. 

We are proposing to amend 40 CFR 

98.242(b) by removing the reference to 

flares. Section 98.242(b) in subpart X 

specifies that CO2, CH4, and N2O 

combustion emissions from stationary 

combustion units and flares must be 

reported. However, the intent of 40 CFR 

98.242(b) is to identify only the GHGs 

from the combustion of supplemental 

fuels that are to be reported under 

subpart C. Emissions from the 

combustion of petrochemical process 

off-gas in a flare are process-based 

emissions that are to be reported under 

subpart X as specified in 40 CFR 

98.242(a). Therefore, the reference to 

flares in 40 CFR 98.242(b) is incorrect 

and should be removed. 

CH4 and N2O Emissions From 

Combustion Of Process Off-Gas. We are 

proposing to amend 40 CFR 98.243(b) to 

clarify procedures for calculating CH4

and N2O emissions from combustion 

units that burn petrochemical process 

off-gas and are monitored with a CO2

CEMS. Section 98.243(b) in subpart X 

specifies that CH4 and N2O emissions 

from the non-flare combustion of 

petrochemical process off-gas are to be 

calculated using the Tier 3 procedures 

in subpart C, with the default emission 

factors for ‘‘Petroleum’’ in Table C–2 of 

subpart C. This procedure requires the 

use of equation C–8 to calculate the 

emissions. One of the inputs for this 

equation is the default HHV of the fuel, 

and default values for various fuels are 

listed in Table C–1 of subpart C. As 

discussed in section II.H of this 

preamble, we have added a default HHV 

for fuel gas in Table C–1, and we have 

revised the definition of HHV for 

equation C–8 to allow the use of a sitespecific calculated HHV as an 

alternative to using a default value from 

Table C–1. Using either a default HHV 

or a site-specific calculated value is also 

acceptable when calculating CH4 and 

N2O emissions from the combustion of 

fuel gas that contains petrochemical 

process off-gas. Therefore, to clarify this 

point, we are proposing to add language 

to 40 CFR 98.243(b) specifying that 

either the default HHV for fuel gas in 

Table C–1 or a site-specific calculated 

HHV is to be used in equation C–8 when 

calculating CH4 and N2O emissions. 

For the ethylene-specific option, 40 

CFR 98.243(d) in subpart X specifies the 

same procedures for calculating CH4

and N2O emissions from non-flare 

combustion of process off-gas as in 40 

CFR 98.243(b). Therefore, we are 

proposing the same change to 40 CFR 

98.243(d) as noted above for 40 CFR 

98.243(b) to clarify that either the 

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

for Tier 3 calculations. 

Molar volume conversion (MVC) 

factors. Owners and operators have 

requested that allowance be made for 

alternative standard conditions within 

the molar volume conversion factor 

(MVC) used in Equation X–1 in 40 CFR 

98.243(c). Equation X–1 of subpart X 

specified using an MVC of 849.5 scf/ 

kgmole, which converts the volumetric 

flow from standard cubic feet to 

kgmoles assuming the standard volume 

was determined at 68 °F. Exhaust stack 

volumes are generally corrected using 

68 °F as the standard temperature, and 

some petrochemical producers may also 

use 68 °F when expressing process 

volumes at standard conditions. 

However, we recognize that the oil and 

gas industry and other hydrocarbon 

processing facilities commonly express 

gaseous volumes using 60 °F as the 

standard temperature. Thus, many 

existing flow monitors for gaseous 

feedstocks and products at 

petrochemical facilities may be 

programmed to output volumes at 

standard conditions of 60 °F. It is 

impractical and unnecessary to either 

reprogram these monitors to provide 

volumes corrected to standard 

conditions at 68 °F or to require 

reporters to convert the output volumes 

from one set of standard conditions to 

another before using Equation X–1 

because an alternative MVC can be 

provided to yield the identical mass 

emissions from the calculation. 

Consequently, we are proposing to 

amend Equation X–1 to provide two 

alternative values of MVC that 

correspond to the two most common 

standard conditions output by the flow 

monitors. Additionally, the reporting 

requirements related to this equation 

would be amended to include reporting 

of the standard temperature at which 

the gaseous feedstock and product 

volumes were determined (either 60 °F 

or 68 °F) and to afford verification of the 

reported emissions. 


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Federal Register / Vol. 75, No. 154 / Wednesday, August 11, 2010 / Proposed Rules 48769 

Methodology for small ethylene offgas streams. Owners and operators have 

suggested that EPA should allow the use 

of alternative calculation methods for 

small emission sources. Specifically, 

they have asserted that units subject to 

only subpart C are allowed to use Tier 

1 or Tier 2 for units less than or equal 

to 250 mmbtu/hr heat input. However, 

if those same units are at a 

petrochemical production facility and 

combusting ethylene process off-gas, 

they are required to use Tier 3 or Tier 

4. 

We still believe that it is important to 

use Tier 3 or Tier 4 for most units that 

burn ethylene process off-gas because 

combustion of process off-gas is the 

primary source of GHG process 

emissions for ethylene processes, the 

carbon content may vary among 

facilities depending on the type of 

feedstock to the ethylene process units, 

and the ratio of ethylene process off-gas 

to other fuels may vary in each fuel gas 

system. 

However, we recognize that some 

ethylene process off gas that is burned 

in process heaters or boilers may not 

enter the fuel gas system and that the 

lines conveying these off-gas streams 

may not have flow monitors. For 

example, 40 CFR part 63, subpart YY, 

requires control of process vent 

emissions from ethylene production 

process units; these streams may be 

controlled by venting to a process heater 

or boiler, but subpart YY does not 

require monitoring of the vent stream 

flow rate. It was not our intent to require 

the installation of flow meters on these 

ancillary gas streams that do not 

significantly contribute to the overall 

heat input of the stationary combustion 

unit. In addition, we recognize that 

facilities may only meter the primary 

fuel flow at relatively large combustion 

units that are subject to emission 

limitations that are related to the heat 

input rate. About one-third of the 

ethylene production capacity is at 

petroleum refineries, and much of the 

rest is at large integrated chemical 

manufacturing facilities. Based on an 

analysis of process heaters at petroleum 

refineries (see section II.O of this 

preamble), it appears that process 

heaters less than 30 mmBtu/hr are often 

not subject to emission limitations and, 

therefore, may not have metered flow. 

Furthermore, such combustion units 

appear to represent only a small 

percentage of the total fuel use at 

refineries. Given the large size of most 

other chemical manufacturing facilities 

that make ethylene, it is likely that such 

combustion units represent only a small 

percentage of total fuel use at these 

facilities as well. Thus, easing the Tier 

3 monitoring requirements for these 

small combustion units would reduce 

the compliance burden without 

significantly impacting the accuracy of 

the nationwide GHG emission 

inventories for ethylene production. 

Notwithstanding the above 

discussion, if a flow meter is installed 

in the fuel gas line, including any 

common pipe, then we consider that the 

Tier 3 monitoring requirements are 

reasonable and justified. In such cases 

there will not be a significant burden to 

use the Tier 3 method, and the reported 

GHG emissions will be more accurate. 

Therefore, we are proposing to amend 

40 CFR 98.243(d) to allow the use of 

Tier 1 or Tier 2 methods for small flows 

(in cases where a flow meter is not 

already installed). Specifically, we are 

proposing that Tier 1 or Tier 2 methods 

may be used for ethylene process off-gas 

streams that meet either of the following 

conditions: 

(1) The annual average flow rate of 

fuel gas (that contains ethylene process 

off-gas) in the fuel gas line to the 

combustion unit, prior to any split to 

individual burners or ports, does not 

exceed 345 scfm at 60 °F and 14.7 

pounds per square inch absolute, psia, 

and a flow meter is not installed at any 

point in the line supplying fuel gas or 

an upstream common pipe; or 

(2) The combustion unit has a 

maximum rated heat input capacity of 

less than 30 mmBtu/hr, and a flow 

meter is not installed at any point in the 

line supplying fuel gas (that contains 

ethylene process off-gas) or an upstream 

common pipe. 

This amendment would also specify 

how to calculate the annual average 

flow rate under the first condition. 

Specifically, the total flow obtained 

from company records is to be evenly 

distributed over 525,600 minutes per 

year. We are also proposing a number of 

editorial changes to 40 CFR 98.243(d) to 

clearly integrate the proposed option 

with the existing requirements. Finally, 

we are proposing to amend 40 CFR 

98.246(c)(2) and 98.247(c) to add 

reporting and recordkeeping 

requirements that are related to the 

proposed amendments in 40 CFR 

98.243(d)(2). 

Monitoring Methods for Determining 

Carbon Content and Composition. 

Owners and operators have suggested 

that EPA should not limit the use of gas 

chromatograph methods for determining 

the carbon content, composition, and 

the average molecular weight of 

feedstocks and products to those 

methods listed in 40 CFR 98.244(b)(4). 

We are proposing to add the method, 

‘‘ASTM D2593–93 (Reapproved 2009) 

Standard Test Method for Butadiene 

Purity and Hydrocarbon Impurities by 

Gas Chromatography,’’ to 40 CFR 

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

of the ethylene production process, and 

after reviewing the method, we have 

determined that it is an acceptable 

method for determining the carbon 

content of that stream. We will consider 

including additional methods in the 

final amendments after reviewing 

comments on this issue. In order to 

evaluate this issue, we seek comments 

providing copies of calibration 

procedures that gas chromatograph 

manufacturers supply with their 

equipment, calibration procedures in 

any published or unpublished industry 

consensus (or site-specific) methods not 

currently listed in 40 CFR 98.244(b)(4), 

and an assessment of how such 

procedures compare to the currently 

specified methods and why they are 

applicable for instruments used to 

measure petrochemical feedstocks and 

products. 

We are proposing to further amend 40 

CFR 98.244(b)(4) by adding a new 

paragraph that would allow the use of 

industry consensus standard methods to 

determine the carbon content or 

composition of carbon black feedstock 

oils and carbon black products. Carbon 

black manufacturers have reported that 

none of the listed methods are specific 

to carbon black materials, and they have 

stated that such methods will provide 

less accurate results than modified 

versions of some of the methods. For 

example, the industry has reported that 

when they need to determine the carbon 

content of their feedstocks or products 

they often use modified versions of 

ASTM D5291–02. One difference is that 

the modified methods use carbon or 

carbon/sulfur analyzers instead of the 

carbon, hydrogen, and nitrogen analyzer 

that is specified in ASTM D5291–02. 

These modified methods have been 

submitted to ASTM for review. If ASTM 

publishes methods before the proposed 

amendments are finalized, we will 

consider including them in the final 

amendments. The industry has also 

reported that they often use other 

published methods to determine the 

sulfur, ash, and water content of the 

material and then calculate the carbon 

content as the difference between the 

mass of these compounds and the total 

mass of the sample. This approach 

would also be allowed under the 

proposed change to 40 CFR 98.244(b)(4). 

We seek comment on the need for the 

proposed option. In particular, we are 

interested in data that compare 

specified methods such as ASTM 

D5291–02 with industry consensus 

methods. We are also interested in 


srobinson on DSKHWCL6B1PROD with PROPOSALS2
48770 Federal Register / Vol. 75, No. 154 / Wednesday, August 11, 2010 / Proposed Rules 

obtaining copies of industry consensus 

standard methods. 

We are also proposing to amend 40 

CFR 98.244(b)(4) to provide facilities the 

option of, under certain circumstances, 

the use of alternative analytical methods 

in addition to the methods listed in 40 

CFR 98.244(b)(4)(i) through (b)(4)(xi) for 

determining the carbon content or 

composition of feedstocks or products. 

We recognize that the applicability of 

the methods listed in 40 CFR 

98.244(b)(4)(i) through (b)(4)(xi) may be 

restricted for certain process streams 

due to the analytical limitations of those 

methods and/or the instrumentation. As 

a result, we are proposing to allow a 

facility to use an alternative analytical 

method in cases where the methods 

listed in 40 CFR 98.244(b)(4)(i) through 

(b)(4)(xi) are not appropriate because the 

relevant compounds cannot be detected, 

the quality control requirements are not 

technically feasible, or use of the 

method would be unsafe. 

We are proposing to amend the 

reporting requirements in 40 CFR 

98.246(a)(11) so that if an alternative 

method is used, facilities would include 

in the annual report the name or title of 

the method used, and the first time it is 

used, a copy of the method and an 

explanation of why the use of the 

alternative method is necessary. 

We solicit comment on whether the 

flexibility provided by this option is 

needed. If commenters believe that to be 

the case, please provide information on 

the specific need for flexibility, why the 

existing listed analytical methods are 

not sufficient, and whether the 

proposed flexibility meets the needs 

identified. 

We are proposing to make the 

amendments to 40 CFR 98.244(b)(4) as 

described above retroactive to January 1, 

2010. We have received feedback that 

some reporters are using a method 

currently allowed in Part 98 while 

concurrently also using a method that 

would be allowed by today’s action. 

Should these amendments be finalized, 

making these amendments effective 

January 1, 2010 would allow reporters 

to use the results from the methods 

included in today’s amendments for the 

entire year of 2010. 

QA/QC Requirements. As mentioned 

in Section II.B of this preamble, owners 

and operators have raised several issues 

regarding the calibration requirements 

in Part 98, and we are proposing a 

number of changes to 40 CFR 98.3(i) of 

subpart A to address those issues. To 

maintain consistency with the proposed 

amendments to 40 CFR 98.3(i), we are 

also proposing amendments to the QA/ 

QC provisions for weighing devices, 

flow meters, and tank level 

measurement devices in paragraphs 

(b)(1), (b)(2), and (b)(3) of 40 CFR 

98.244. Other proposed amendments to 

these paragraphs are editorial in nature 

and intended to clarify the 

requirements. Specific changes are as 

follows: 

In 40 CFR 98.244(b), each of the three 

subparagraphs incorrectly required 

compliance with calibration 

requirements in 40 CFR 98.3(i), or with 

any of the following: procedures 

specified by equipment manufacturers, 

industry consensus standard 

procedures, or procedures in listed 

methods. We are proposing to amend 

these subparagraphs such that the 

procedures in 40 CFR 98.3(i) would 

apply in addition to the other required 

procedures. 

We are proposing to amend 40 CFR 

98.244(b)(1) to allow recalibration at the 

interval specified by the industry 

consensus standard practice used in 

addition to either biennially or at the 

minimum frequency specified by the 

manufacturer. Note that the 

requirements of 40 CFR 98.3(i) for other 

measurement devices would apply as 

well. 

Section 98.244(b)(2) in subpart X 

specifies that flow meters are to be 

operated and maintained using the 

procedures in 40 CFR 98.3(i) and either 

any one of several listed methods, a 

method published by a consensus-based 

standards organization, or procedures 

specified by the flow meter 

manufacturer. Although 40 CFR 

98.244(b)(2) references 40 CFR 98.3(i), it 

does not explicitly specify calibration 

requirements, and this reference 

incorrectly implies that 40 CFR 98.3(i) 

specifies procedures other than 

calibration requirements. In addition, 

the option to follow procedures in any 

of the listed methods is redundant 

because it overlaps with the option to 

use a method published by a consensus 

standards-based organization. To clarify 

these requirements we are proposing 

several amendments to 40 CFR 

98.244(b)(2). One would specify that 

flow meters are to be operated and 

maintained according to manufacturer’s 

recommended procedures. A second 

would specify that flow meters are to be 

calibrated following either an industry 

consensus standard practice or 

procedures specified by the flow meter 

manufacturer, and must meet the 

accuracy specification in 40 CFR 98.3(i). 

Finally, the list of specified methods 

would be deleted. 

Section 98.244(b)(2) in subpart X 

specifies that flow meters are to be 

recalibrated either biennially or at the 

minimum frequency specified by the 

flow meter manufacturer. Since 40 CFR 

98.244(b)(2) specifies that flow meters 

may be calibrated following procedures 

in industry consensus standard 

practices, we are proposing to also allow 

recalibration at the frequency specified 

in such methods. This would also make 

the recalibration requirements in 40 

CFR 98.244(b)(2) consistent with the 

proposed amendment in 40 CFR 

98.3(i)(1)(iii)(B). 

Section 98.244(b)(3) in subpart X 

specifies that tank level measurement 

devices are to be calibrated prior to the 

effective date of the rule. We are 

proposing to delete this statement 

because 40 CFR 98.3(i) specifies the date 

by which initial calibration must be 

completed. Note that the requirements 

for other measurement devices in 40 

CFR 98.3(i) apply as well. 

Reporting Requirements Under The 

CEMS Compliance Option. We are 

proposing a number of changes in 40 

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

clarify the reporting requirements under 

the CEMS compliance option. 

First, we are proposing to move the 

requirement for reporting of the 

petrochemical process ID from 40 CFR 

98.246(b)(3) to 40 CFR 98.246(b)(1) to be 

consistent with the structure in other 

reporting sections, and we are 

renumbering the existing paragraphs 

(b)(1) and (b)(2). 

Second, we are proposing to add a 

statement in the renumbered paragraph 

40 CFR 98.246(b)(2) to specify that the 

reporting requirements in 40 CFR 

98.36(b)(9)(iii) (as numbered in today’s 

proposed action) for CH4 and N2O do 

not apply under subpart X. This 

reporting requirement in subpart C is 

not relevant in subpart X because 40 

CFR 98.246(b)(5) specifies the reporting 

requirements for CH4 and N2O under 

subpart X. 

Third, in the renumbered 40 CFR 

98.246(b)(3), we are proposing to delete 

the requirement to report information 

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

because the referenced section specifies 

recordkeeping requirements, not 

reporting requirements; note that you 

still must keep the applicable records 

because 40 CFR 98.247(a) references 40 

CFR 98.37, which in turn requires you 

to keep all of the applicable records in 

40 CFR 98.36(e). We are also proposing 

to amend the reference to 40 CFR 

98.36(e)(2)(vii) to a more general 

reference of 40 CFR 98.36. This makes 

the reporting requirements consistent 

with the methodology for calculating 

emissions in 40 CFR 98.243(b). 

Fourth, we are proposing changes to 

40 CFR 98.246(b)(4) to clarify our intent. 

The first sentence in 40 CFR 

98.246(b)(4) requires reporting of the 

total CO2 emissions from each stack that 


srobinson on DSKHWCL6B1PROD with PROPOSALS2
Federal Register / Vol. 75, No. 154 / Wednesday, August 11, 2010 / Proposed Rules 48771 

is monitored with CO2 CEMS; this 

requirement would be unchanged. We 

are proposing changes to the second 

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

clarify that for each CEMS that monitors 

a combustion unit stack you must 

estimate the fraction of the total CO2

emissions that is from combustion of the 

petrochemical process off-gas in the fuel 

gas. This estimate will give an 

indication of the total petrochemical 

process emissions, whereas the CEMS 

data alone would also include emissions 

from combustion of supplemental fuel 

(if any). 

Finally, we are proposing several 

amendments to 40 CFR 98.246(b)(5). In 

general, as noted above, the 

requirements in this paragraph are 

consistent with the requirements in 40 

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

proposed action). Most of the proposed 

amendments to 40 CFR 98.246(b)(5) 

restate requirements from 40 CFR 

98.36(b)(9)(iii); for example, the 

proposed amendments clarify that 

emissions are to be reported in metric 

tons of each gas and in metric tons of 

CO2e. However, because 40 CFR 

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

petrochemical process off-gas as a part 

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

fuel, 40 CFR 98.246(b)(5) also would 

require you to estimate the fraction of 

total CH4 and 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 N2O emissions using Equation 

C–8 in subpart C (rather than Equation 

C–10), the amendments to 40 CFR 

98.246(b)(5) would require reporting of 

the HHV that you use in Equation C–8. 

This change also would delete the 

erroneous reference to Equation C–10 

that was included in 40 CFR 

98.246(b)(5). 

Reporting Requirements for the 

Ethylene-Specific Option. We are 

proposing several changes to clarify the 

reporting requirements in 40 CFR 

98.246(c) for the ethylene-specific 

option. First, we are proposing to add a 

requirement to report each ethylene 

process ID to allow identification of the 

applicable process units at facilities 

with more than one ethylene process 

unit. Second, we are proposing editorial 

changes to clarify that you must 

estimate the fraction of total combustion 

emissions that is due to combustion of 

ethylene process off-gas, consistent with 

the requirements described above for 

combustion units that are monitored 

with CEMS. Third, because ethylene is 

the only petrochemical product for 

process units that can comply with the 

ethylene-specific option, we are 

proposing to replace the requirement to 

report the ‘‘annual quantity of each type 

of petrochemical produced from each 

process unit’’ with a requirement to 

report the ‘‘annual quantity of ethylene 

produced from each process unit.’’ 

Reporting Measurement Device 

Calibrations. In 40 CFR 98.246(a)(7) we 

are proposing to delete the requirement 

for reporting of the dates and 

summarized results of calibrations of 

each measurement device under the 

mass balance option. We have 

determined that maintaining records of 

this information will be sufficient. Thus, 

we are also proposing to add 40 CFR 

98.247(b)(4) to require retention of these 

records. 

N. Subpart Y (Petroleum Refineries) 

Numerous issues have been raised by 

owners and operators in relation to the 

requirements in subpart Y for petroleum 

refineries. The issues being addressed 

by the proposed amendments include 

the following: 

• GHG emissions from flares. 

• GHG emissions to report from 

combustion of fuel gas. 

• GHG emissions to report from nonmerchant hydrogen production process 

units. 

• Calculating GHG emissions from 

fuel gas combustion. 

• Calculating combustion GHG 

emissions from flares and thermal 

oxidizers. 

• Molar volume conversion factors. 

• Combined stacks monitored by 

CEMS. 

• Nitrogen concentration monitoring 

to determine exhaust gas flow rate. 

• Calculating CO2 emissions from 

catalytic reforming units. 

• Calculating GHG emissions from 

sulfur recovery plants. 

• Calculating CO2 emissions from 

coke calcining units. 

• Calculating CO2 emissions from 

process vents. 

• Reactor vessels using methane as a 

blanket or purge gas. 

• Monitoring and QA/QC 

requirements. 

• Reporting requirements. 

GHG Emissions From Flares. We are 

proposing several corrections to 40 CFR 

98.252(a) (GHGs to report) to clarify the 

required emissions methods for flares. 

From the first sentence in 40 CFR 

98.252(a), it is clear that CO2, CH4, and 

N2O combustion emissions are to be 

calculated for stationary combustion 

units and for each flare. However, the 

second sentence suggests that petroleum 

refinery owners or operators are to 

‘‘[c]alculate and report these emissions 

under subpart C * * *’’ (emphasis 

added). After the first sentence, the 

remainder of 40 CFR 98.252(a) 

specifically addresses how petroleum 

refinery owners or operators are to 

calculate and report stationary 

combustion unit emissions. Flare 

emissions are to be calculated using the 

methods provided in subpart Y, not the 

methods provided in subpart C. 

Consequently, we are proposing to 

amend the second sentence in 40 CFR 

98.252(a) to correctly require reporters 

to ‘‘Calculate and report the emissions 

from stationary combustion units under 

subpart C * * *’’ and we are proposing 

to add an additional sentence at the end 

of this section to clarify that reports 

must ‘‘Calculate and report the 

emissions from flares under this 

subpart.’’ 

GHG Emissions to Report From 

Combustion of Fuel Gas. We are 

proposing to amend 40 CFR 98.252(a) to 

clarify that reporting of CH4 and N2O 

emissions is required for the stationary 

combustion units fired with fuel gas. It 

was always our intent that the emissions 

of these pollutants be reported for 

stationary combustion sources that used 

fuel gas. However, as no default factors 

for fuel gas were previously included in 

Table C–1 of subpart C, it could be 

interpreted that these emissions were 

not required to be reported, even though 

the first sentence clearly indicates that 

emissions of all three pollutants were to 

be reported for stationary combustion 

units and flares. While the proposed 

amendment to Table C–1 to include 

default factors for ‘‘fuel gas’’ is expected 

to correct this misinterpretation, we are 

also proposing to add the following 

sentence to 40 CFR 98.252(a) to clarify 

these reporting requirements: ‘‘For CH4

and N2O emissions from combustion of 

fuel gas, use the applicable procedures 

in 40 CFR 98.33(c) for the same tier 

methodology that was used for 

calculating CO2 emissions (use the 

default CH4 and N2O emission factors 

for ‘‘Petroleum (All fuel types in Table 

C–1)’’ in table C–2 of subpart C of this 

part and for Tier 3, either the default 

high heat value for fuel gas in Table C– 

1 of subpart C of this part or a calculated 

HHV, as allowed in Equation C–8 of 

subpart C of this part.’’. 

GHG Emissions To Report From NonMerchant Hydrogen Production Process 

Units. We are also proposing to amend 

40 CFR 98.252(i) to clarify that reporting 

of only CO2 emissions from nonmerchant hydrogen production process 

units is required. The inclusion of ‘‘and 

CH4’’ emissions was an inadvertent 

error. We are also proposing to amend 

40 CFR 98.252(i) to clarify that catalytic 

reforming units (although they produce 

hydrogen as an important by-product) 

are not considered hydrogen production 


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48772 Federal Register / Vol. 75, No. 154 / Wednesday, August 11, 2010 / Proposed Rules 

process units that are required to report 

under 40 CFR 98.252(i). 

Calculating GHG Emissions From Fuel 

Gas Combustion. Owners and operators 

have suggested that EPA should allow 

the use of alternative calculation 

methods for small emission sources 

from the combustion of fuel gas. 

Specifically, they have asserted that 

units subject to only subpart C may use 

Tier 1 or Tier 2 if the units are less than 

or equal to 250 mmbtu/hr heat input. 

However, if those same units are at a 

petroleum refinery and combusting fuel 

gas, they are required to use Tier 3 or 

Tier 4. We still believe that it is 

important to use Tier 3 or Tier 4 for 

most units at a petroleum refinery 

because of the variability in carbon 

content in fuel gas (both between 

different refineries and at different times 

within the same refinery). However, we 

recognize that some flows of fuel gas to 

process heaters or boilers may not 

necessarily enter the refinery’s fuel gas 

system and that these fuel gas lines may 

not have flow monitors. For example, 40 

CFR part 63 subpart UUU requires the 

control of purging operations associated 

with the catalytic reforming unit. 

Among the control options for these 

emissions are provisions to vent these 

gases to a boiler or process heater. If the 

stationary combustion source has a 

design capacity of 44 MW or greater or 

if the gases are introduced into the 

flame zone of the unit, then direct 

monitoring of these gas streams is not 

required under subpart UUU. Similar 

provisions that may pertain to 

petroleum refineries are in other rules 

(e.g., 40 CFR part 60, subparts III and 

NNN; 40 CFR part 63, subparts G and 

CC). It is not our intent to require direct 

flow monitoring of these ancillary gas 

streams, particularly if they do not 

significantly contribute to the overall 

heat input of the stationary combustion 

unit. 

In addition, while we anticipate that 

most refineries can use a common-pipe 

monitoring approach for stationary 

combustion sources supplied by the 

refinery’s fuel gas system(s), we 

recognize that some refineries may 

meter fuel usage at the stationary 

combustion sources and, in some cases, 

only meter fuel usage at the larger units. 

Based on a review of consent decrees 

and permits pertaining to process 

heaters, it appears that process heaters 

less than 30 mmBtu/hr are often not 

subject to emission limitations, and 

therefore may not have metered flow. 

We performed an analysis of fuel use 

requirements by process unit. From this 

analysis, we project that more than 95 

percent of nationwide fuel gas 

consumption at petroleum refineries 

would occur in process heaters with a 

rated heat capacity of 30 mmBtu/hr or 

greater. For additional detail on the 

consent decree review as well as the 

analysis of fuel use requirements, please 

see the Background Technical Support 

Document (EPA–HQ–OAR–2008–0508). 

While these small process heaters 

represent only a small percentage of the 

fuel use on a national level, most 

process heaters at petroleum refineries 

with capacities under 25,000 barrels per 

day (which represents about 20 percent 

of the refineries, but only 2 percent of 

the refining capacity) are expected to 

have rated heat capacity of less than 30 

mmBtu/hr. Thus, easing the Tier 3 

monitoring requirements for these 

smaller process heaters would 

significantly ease the burden for small 

refineries without significantly 

impacting the accuracy of the 

nationwide GHG inventories for 

petroleum refineries. 

If flow meters are in place at the 

process heater or at a common pipe 

location, we consider that the Tier 3 

monitoring requirements are reasonable 

and justified. There will not be a 

significant burden to use the Tier 3 

method and the reported GHG 

emissions will be more accurate given 

the fluctuations expected in fuel gas 

compositions. 

Therefore, we are proposing to amend 

40 CFR 98.252(a) so that petroleum 

refineries subject to subpart Y could use 

the Tier 1 or 2 methodologies for 

combustion of fuel gas when either of 

the following conditions exists: 

(1) The annual average fuel gas flow 

rate in the fuel gas line to the 

combustion unit, prior to any split to 

individual burners or ports, does not 

exceed 345 scfm at 60°F and 14.7 psia 

and either of the following conditions 

exist: 

• A flow meter is not installed at any 

point in the line supplying fuel gas or 

an upstream common pipe; or 

• The fuel gas line contains only 

vapors from loading or unloading, waste 

or wastewater handling, and 

remediation activities that are 

combusted in a thermal oxidizer or 

thermal incinerator. 

(2) The combustion unit has a 

maximum rated heat input capacity of 

less than 30 mmBtu/hr and either of the 

following conditions exist: 

• A flow meter is not installed at any 

point in the line supplying fuel gas or 

an upstream common pipe; or 

• The fuel gas line contains only 

vapors from loading or unloading, waste 

or wastewater handling, and 

remediation activities that are 

combusted in a thermal oxidizer or 

thermal incinerator. 

These amendments, combined with 

the revisions to Table C–1 of subpart C, 

reflect our original intent to require Tier 

3 or 4 monitoring and calculation 

methods for large fuel gas streams such 

as those anticipated in the refinery’s 

fuel gas system(s), but to allow Tier 1 or 

2 monitoring methods for smaller fuel 

gas streams that are segregated from the 

fuel gas system or for small combustion 

sources at refineries where flow 

monitors are installed at the majority of 

individual combustion sources, but not 

at the smaller combustion sources or the 

common pipe (i.e., fuel gas system). 

Calculating Combustion GHG 

Emissions From Flares And Thermal 

Oxidizers. It has been brought to our 

attention that it is inappropriate to 

apply the 98 percent combustion 

efficiency to the carbon as CO2 that 

already exists in the gas stream in 

Equations Y–1 and Y–16 in 40 CFR 

98.253. While the correction is expected 

to be minor in most cases, we agree that 

all of the CO2 that already exists in the 

gas stream will be emitted as CO2 from 

these sources. However, we are 

concerned that, depending on the 

method used to determine the carbon 

content, some facilities may not have 

collected the specific CO2 data needed 

to implement the revised equations. 

Therefore, we are proposing to amend 

40 CFR 98.253 by retaining the existing 

Equations Y–1 and Y–16, re-numbering 

them as Equations Y–1a and Y–16a, and 

to add the more detailed equations that 

specifically consider the CO2 that 

already exists in the gas stream prior to 

the flare or thermal combustion device 

as Equations Y–1b and Y–16b. Facilities 

that were required to or elected to use 

Equation Y–1 to report flare emissions 

would be able to choose to report these 

emissions using either Equation Y–1a or 

Y–1b, as proposed in today’s 

amendments. Similarly, we are 

proposing to allow facilities required to 

report CO2 emissions from asphalt 

blowing operations controlled by a 

thermal oxidizer or flare to use either 

Equation Y–16a or Y–16b. We are 

proposing corresponding amendments 

in 40 CFR 98.256 to require reporting of 

which equation was used and, if the 

new equations are used, reporting of the 

additional equation parameters. 

We request comment on the need to 

retain the previously promulgated 

equations. As gas composition data are 

expected to be determined using gas 

chromatographic methods, the required 

CO2 data may already be collected. 

Thus, we are particularly interested to 

determine if there are facilities that 

cannot implement the new equations 

based on the measurement data already 


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Federal Register / Vol. 75, No. 154 / Wednesday, August 11, 2010 / Proposed Rules 48773 

collected for these sources during the 

2010 reporting year. 

Molar volume conversion factors. 

Owners and operators have suggested 

that allowance be made for alternative 

‘‘standard conditions’’ within the MVC 

factor used in several of the equations 

in 40 CFR 98.253. We recognize that 

natural gas and fuel gas volumes are 

commonly determined using 60°F as the 

standard temperature whereas exhaust 

stack volumes are commonly 

determined using 68°F as the standard 

temperature. Both of these volume 

measurements are specified in subpart 

Y. It is impractical and unnecessary for 

existing fuel gas monitors, most of 

which have been installed to correct 

volumes to standard conditions at 60°F, 

to be reprogrammed to output these 

volumes corrected to standard 

conditions at 68°F when an alternative 

MVC can be provided to yield the 

identical mass emissions from the 

calculation. Consequently, we are 

proposing to amend equations Y–1, Y– 

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

23 in subpart Y to provide two 

alternative values of MVC depending on 

the standard conditions output by the 

flow monitors. Additionally, the 

reporting requirements related to each 

of these equations would be amended to 

include reporting of the value of MVC 

used to support the calculations and to 

afford verification of the reported 

emissions. 

Combined Stacks Monitored By 

CEMS. We received several questions 

regarding whether or not discharges 

through a combined stack are allowable 

when CEMS are used, particularly for 

the catalytic cracking unit. We never 

intended to limit the use of combined 

stacks and CEMS at the refinery. In fact, 

we specifically attempted to address 

this issue in subpart Y with respect to 

the combined catalytic cracking unit 

and CO boiler emissions in 40 CFR 

98.253(c)(1)(ii). However, we have 

determined that the current language in 

40 CFR 98.253(c)(1)(ii) may 

inadvertently be interpreted to exclude 

other CO2 emission sources that may be 

mixed with the catalytic cracking unit 

process (e.g., coke burn-off) emissions. 

Consequently, we are proposing to 

amend the language in 40 CFR 

98.253(c)(1)(ii) and also the reporting 

requirements in 40 CFR 98.256(f)(6) to 

generalize the language to include other 

CO2 emission sources, not just a CO 

boiler. The proposed amendments 

would clarify that when a CEMS is used 

to measure the CO2 emissions from the 

catalytic cracking unit and these 

emissions are combined with ‘‘other CO2

emissions,’’ the owner or operator must 

calculate the ‘‘other CO2 emissions’’ 

using the applicable methods for the 

applicable subpart (e.g., subpart C of 

this part in the case of a CO boiler), and 

determine the process emissions from 

the catalytic cracking unit (or fluid 

coking unit) as the difference in the CO2

CEMS measurements and the calculated 

emissions associated with the ‘‘other 

CO2 emissions.’’ 

Nitrogen Concentration Monitoring To 

Determine Exhaust Gas Flow Rate. We 

also received questions regarding the 

use of nitrogen (N2) concentration 

monitoring for Equation Y–7 in 40 CFR 

98.253(c)(2)(ii). Equation Y–7 uses an 

inert balance to calculate the exhaust 

gas flow rate, and a similar calculation 

can be performed using a nitrogen 

balance. We agree that the nitrogen 

monitoring approach would provide an 

equivalent measure of the exhaust gas 

flow rate as Equation Y–7. We 

promulgated Equation Y–7 because we 

anticipated several facilities used this 

monitoring approach as this equation is 

provided in the 40 CFR part 63 subpart 

UUU (see Equation 2 of 40 CFR 

63.1573). However, we note that 40 CFR 

63.1573 also allows facilities to request 

alternative monitoring methods. There 

are no similar provisions in subpart A 

or subpart Y of part 98, so this 

monitoring alternative could not be 

used without amending the rule. As we 

find the N2 concentration monitoring 

approach to be equivalent to Equation 

Y–7, we are proposing to amend 40 CFR 

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

7 as Equation Y–7a and adding an 

Equation Y–7b to provide this N2

concentration monitoring approach. We 

are also proposing to add reporting 

requirements in 40 CFR 98.256(f) to 

report the input parameters for Equation 

Y–7b if it is used. 

Calculating CO2 Emissions from 

Catalytic Reforming Units. We are 

proposing to revise the definition of the 

coke burn-off quantity, CBQ, the term 

‘‘n’’ in Equation Y–11 in 40 CFR 

98.253(e)(3) to clarify the application of 

Equation Y–11 to continuously 

regenerated catalytic reforming units. 

Continuously regenerated catalytic 

reforming units do not have specific 

cycles, so the reference to ‘‘regeneration 

cycle’’ in the definition of these terms 

was ambiguous or meaningless for 

continuously regenerated catalytic 

reforming units. We are proposing to 

replace the phrase ‘‘regeneration cycle’’ 

with ‘‘regeneration cycle or 

measurement period’’ in the definition 

of the coke burn-off quantity and to 

revise the definition of ‘‘n’’ to be the 

‘‘Number of regeneration cycles or 

measurement periods in the calendar 

year.’’ A measurement period may be a 

day, week, month, or other time interval 

over which process measurements are 

made on the unit by which the coke 

burn-off rate is determined. We are 

similarly proposing to clarify 40 CFR 

98.256(f)(13) (formerly designated 40 

CFR 98.256(f)(12)) to require reporting 

of ‘‘* * * the number of regeneration 

cycles or measurement periods during 

the reporting year, the average coke 

burn-off quantity per cycle or 

measurement period, and the average 

carbon content of the coke’’ when 

Equation Y–11 is used. 

Calculating GHG Emissions From 

Sulfur Recovery Plants. With respect to 

requirements for sour gas sent off-site 

for sulfur recovery and for on-site sulfur 

recovery plants, we intended these 

requirements to be identical and that the 

petroleum refinery would report these 

emissions regardless of whether the sour 

gas feed is used at an on-site sulfur 

recovery plant within the refinery 

facility or the sour gas feed is sent to an 

off-site facility. However, we do note 

that the requirements were developed 

considering Claus sulfur recovery plants 

and that the methods in 40 CFR 

98.253(f) may not be appropriate for all 

other types of sulfur recovery plants. To 

clarify the requirements for sulfur 

recovery plants, we are proposing to 

amend 40 CFR 98.253(f) to add ‘‘and for 

sour gas sent off-site for sulfur recovery’’ 

to clarify that this calculation 

methodology applies ‘‘For on-site sulfur 

recovery plants and for sour gas sent offsite for sulfur recovery, * * *’’ and to 

allow non-Claus sulfur recovery plants 

to alternatively follow the requirements 

in 40 CFR 98.253(j) for process vents. 

We also are proposing to amend the 

reporting requirements in 40 CFR 

98.256(h) to include the type of sulfur 

recovery plant and an indication of the 

method used to calculate CO2 emissions 

as well as reporting requirements for 

non-Claus sulfur recovery plants that 

elect to follow the requirements in 40 

CFR 98.253(j) for process vents. While 

we believe the calculation methodology 

needs no further regulatory text 

amendments, we do clarify in this 

preamble that the phrase ‘‘the sulfur 

recovery plant’’ in 40 CFR 98.253(f) 

refers to either the on-site or off-site 

sulfur recovery plant, as applicable. We 

further clarify in this preamble that the 

sour gas flow and carbon content 

measurements for sour gas sent off-site 

for sulfur recovery may be made at 

either the refinery or the off-site sulfur 

recovery plant provided these 

measurements are representative of the 

flow and carbon content of the sour gas 

sent off-site for sulfur recovery. 

Calculating CO2 Emissions From Coke 

Calcining Units. We are proposing to 

amend the definition of Mdust (the mass 


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48774 Federal Register / Vol. 75, No. 154 / Wednesday, August 11, 2010 / Proposed Rules 

of dust collected in the dust collection 

system) in Equation Y–13 in 40 CFR 

98.253(g). It was brought to our 

attention that dust collected by the 

control systems may be recycled back to 

the coke calciner, raising the issue of 

how Mdust should be determined in this 

situation: Is it the mass of dust collected 

in the dust collection system or is it the 

mass of dust that is discarded from the 

system? The mass balance represented 

by Equation Y–13 should be applied 

external to this recycle loop, so that 

Mdust is the quantity of dust removed 

from the overall process, which would 

be the mass of the dust collected in the 

control system minus the mass of dust 

recycled. We are, therefore, proposing to 

amend the definition of Mdust in 

Equation Y–13 to clarify this 

interpretation of Mdust when all or a 

portion of the collected dust is recycled 

back to the coke calciner. We also are 

proposing to amend 40 CFR 98.256(i)(5) 

to require facilities that use Equation Y– 

13 to indicate whether or not the 

collected dust is recycled to the coke 

calciner. 

Calculating CO2 Emissions From 

Process Vents. We are proposing to 

amend the process vent requirements in 

40 CFR 98.253(j) due to the additional 

sources that may elect to use Equation 

Y–19, specifically non-Claus sulfur 

recovery units (as previously described) 

and uncontrolled blowdown vents 

(inadvertently not referenced). This 

amendment clarifies that the emissions 

from the sources that elect to use the 

process vent method in 40 CFR 

98.253(j), must use Equation Y–19 to 

calculate the emissions for the 

pollutants required to be reported under 

the cross-referencing section, regardless 

of whether the concentration thresholds 

in 40 CFR 98.253(j) are exceeded. We 

are also proposing to amend the 

definition of Equation Y–19’s 

parameters of VR (the volumetric flow 

rate) and MFx (the mole fraction of the 

GHG in the vent). For these parameters 

we are proposing to clarify that these 

values are to be determined ‘‘from 

measurement data, process knowledge, 

or engineering estimates.’’ We are also 

proposing to amend the reporting 

requirements for process vents to clarify 

that the requirements apply to each 

process vent as well as to provide an 

indication of the measurement of 

estimation method. 

Finally, we are proposing to amend 40 

CFR 98.253(n) to delete the words 

‘‘equilibrium’’ and ‘‘product-specific’’ to 

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. We affirm 

that process knowledge may be used to 

determine which loading operations 

have a vapor-phase concentration of 

methane of 0.5 volume percent, but this 

determination must be made 

considering both the material being 

loaded and the conditions of the loading 

operations. Equilibrium vapor-phase 

concentrations can be used as process 

knowledge to determine if the 

concentration of methane is 0.5 volume 

percent or more. 

Monitoring and QA/QC Requirements. 

In subpart Y, 40 CFR 98.254 currently 

specifies QA/QC requirements for fuel 

flow meters, gas composition monitors, 

and heating value monitors that provide 

data for the GHG emissions calculations. 

A distinction is made in paragraphs (a) 

and (b) between measurement devices 

associated with stationary combustion 

sources, which are required to follow 

the QA/QC procedures in 40 CFR 98.34, 

and devices associated with other GHG 

emissions sources at the refinery, which 

are to be quality-assured according to 40 

CFR 98.254(c) through (e). Paragraphs 

(f), (g), and (h) of 40 CFR 98.254 QA/QC 

requirements for: 

• Stack gas flow rate monitors that are 

used to comply with the requirements of 

40 CFR 98.253(c)(2)(ii); 

• CO2/CO/O2 composition monitors 

used to comply with 40 CFR 

98.253(c)(2); and 

• Weighing devices that are used to 

measure the mass of petroleum coke 

when CO2 emissions from a coke 

calcining unit are calculated using 

Equation Y–13. 

In subpart Y, 40 CFR 98.254(l) 

provides QA/QC requirements for CO2

CEMS and flow monitors used for direct 

measurement of CO2 emissions 

following the Tier 4 methodology in 

subpart C. 

We are proposing to amend 40 CFR 

98.254(a) through (h), and (l) as follows, 

to make them consistent with today’s 

proposed revisions to 40 CFR 98.3(i), 

and to make some necessary technical 

corrections and clarifications: 

Paragraph (a) of 40 CFR 98.254 would 

be amended to also include the phrase 

‘‘sources that use a CEMS to measure 

CO2 emissions according to subpart C of 

this part * * *’’ to further separate these 

sources from those that are covered by 

40 CFR 98.254(b). Although the CEMS 

monitoring requirements are specified 

in 40 CFR 98.254(l), these requirements 

are more clearly specified by the 

proposed amendments to 40 CFR 

98.254(a) so that all sources required to 

meet the methods provided in subpart C 

are identified in a single paragraph. We 

also are proposing to re-word the phrase 

‘‘follow the monitoring and QA/QC 

requirements in 40 CFR 98.34’’ with 

‘‘meet the applicable monitoring and 

QA/QC requirements in 40 CFR 98.34’’ 

to clarify that the monitors must meet 

the requirements for the specific Tier for 

which monitoring was required (Tier 3 

sources would comply with the Tier 3 

requirements; Tier 4 sources would 

comply with the Tier 4 requirements; 

etc.). 

Because the QA/QC requirements for 

CO2 CEMS that were formerly included 

in 40 CFR 98.254(l) would be included 

in the amended paragraph 40 CFR 

98.254(a), we are proposing to delete 40 

CFR 98.254(l). 

Paragraph (b) of 40 CFR 98.254 would 

be amended to clarify that these 

requirements apply to gas flow meters, 

gas composition monitors, and heating 

value monitors other than those subject 

to 40 CFR 98.254(a). We would correct 

the reference to ‘‘paragraphs (c) through 

(e)’’ to correctly reference ‘‘paragraphs 

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

requirements are specified in 40 CFR 

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

clarify that the calibration requirements 

in 40 CFR 98.3(i) only apply to gas flow 

meters and to allow recalibration of gas 

flow meters biennially (every two 

years), at the minimum frequency 

specified by the manufacturer, or at the 

interval specified by the industry 

consensus standard practice used. 

Paragraph (b) of 40 CFR 98.254 would 

also be amended to clarify that gas 

composition and heating value monitors 

must be recalibrated either annually, at 

the minimum frequency specified by the 

manufacturer, or at the interval 

specified by the industry consensus 

standard practice used. 

Paragraph (c) of 40 CFR 98.254 would 

be amended to clarify that the flare or 

sour gas flow meters must be calibrated 

(in addition to operated and 

maintained) using either a method 

published by a consensus-based 

standards organization (e.g., ASTM, 

API, etc.) or the procedures specified by 

the flow meter manufacturer. The ± 5 

percent accuracy specification would be 

removed from 40 CFR 98.254(c), 

because the accuracy requirement for 

these flow meters is stated in the general 

provisions at 40 CFR 98.3(i) and is 

referenced in 40 CFR 98.254(b). We are 

also proposing to amend 40 CFR 

98.254(c) by removing the list of 

methods as this is redundant with the 

existing phrase, ‘‘a method published by 

a consensus-based standards 

organization.’’ 

Paragraphs (d) and (e) of 40 CFR 

98.254 would be amended to allow the 

use of any chromatographic analysis to 

determine flare gas composition and 

high heat value, as an alternative to the 

methods listed in 40 CFR 98.254(d) and 


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(e) 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 GC are documented in the written 

monitoring plan for the unit under 40 

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

98.254 would also be amended to apply 

to all gas composition monitors, other 

than those included in 40 CFR 

98.254(g), and not just flare gas 

composition monitors. This is needed to 

address gas composition monitors that 

may already be in place on process 

vents subject to reporting under 40 CFR 

98.253(j), so that these monitors can use 

alternatives to the methods in 40 CFR 

98.254(d). 

We are also proposing to amend 40 

CFR 98.254(d) to specify that the 

methods in this paragraph are also to be 

used for determining average molecular 

weight of the gas, which is needed in 

Equations Y–1a and Y–3. We are also 

proposing to add an additional method 

(ASTM D2503–92) to this section for 

determining average molecular weight. 

Methods for determining average 

molecular weight were inadvertently 

omitted from this section. 

We are proposing a number of 

amendments to 40 CFR 98.254(f). First, 

the applicability of this paragraph 

would be expanded to include all gas 

flow meters on process vents subject to 

reporting under 40 CFR 98.253(j). The 

term ‘‘exhaust gas flow meter’’ would be 

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

because not all process vents that would 

report under 40 CFR 98.253(j) are 

combustion (‘‘exhaust’’) related gas 

streams. 

Subpart Y currently allows an option 

to follow 40 CFR 63.1572(c) (in the 

NESHAP for Petroleum Refineries) for 

installation, operation, and calibration 

of the stack gas flow rate monitor or the 

requirements in 40 CFR 98.254(f)(1) 

through (f)(4). In our review of these 

requirements, we found that 40 CFR 

98.254(f)(1) and (f)(3) were important 

requirements that were not delineated 

in 40 CFR 63.1572(c). However, 40 CFR 

98.254(f)(2) is not appropriate (accuracy 

requirements for these flow meters are 

already provided in the general 

provisions in 40 CFR 98.3(i) and are 

referenced in 40 CFR 98.254(b)), and 40 

CFR 98.254(f)(4) is duplicative of the 

requirements in 40 CFR 63.1572(c). 

We are proposing to retain portions of 

40 CFR 98.254(f)(1) and (3), but only as 

general, supplementary guidelines for 

flow monitor installation and operation. 

Thus, we are proposing that these stack 

flow monitors must: 

• Install, operate, calibrate, and 

maintain each stack gas flow meter 

according to the requirements in 40 CFR 

63.1572(c); 

• Locate the flow monitor at a site 

that provides representative flow rates 

(avoiding locations where there is 

swirling flow or abnormal velocity 

distributions); and 

• Use a monitoring system capable of 

correcting for the temperature, pressure, 

and moisture content to output flow in 

dry standard cubic feet (standard 

conditions as defined in 40 CFR 98.6). 

We are proposing to make a technical 

correction to 40 CFR 98.254(g). Subpart 

Y currently requires the CO2/CO/O2

composition monitors that are used to 

comply with the requirements of 40 CFR 

98.253(c)(2) be installed, operated, 

maintained, and calibrated according to 

either 40 CFR 60.105a(b)(2) (in the 

NSPS for Petroleum Refineries) or 40 

CFR 63.1572(a), or according to the 

manufacturer’s specifications and 

requirements. The reference to 40 CFR 

63.1572(a) was in error and should be 

40 CFR 63.1572(c). In the NESHAP for 

Petroleum Refineries (40 CFR part 63 

subpart UUU), these monitors are used 

to calculate coke burn-off rates, which 

are monitored to ensure the control 

device is operated within specified 

limits. Thus, these monitors are subject 

to 40 CFR 63.1572(c) within the 

NESHAP for Petroleum Refineries, and 

this is the level of QA that these 

monitoring systems are expected to be 

currently following. We note that CO2

monitors that are certified and 

calibrated as CEMS (with the 

appropriate flow monitoring system) 

would be subject to the requirements in 

40 CFR 98.253(c)(1), not 40 CFR 

98.253(c)(2). Consequently, we 

specifically refer to the monitors within 

this 40 CFR 98.254(g) as ‘‘CO2/CO/O2

composition monitors’’ rather than 

CEMS to avoid confusion that these 

monitors must be operated according to 

CEMS requirements. In developing Part 

98, we required CO2/CO/O2 composition 

monitors for catalytic cracking units and 

fluid coking units with rated capacities 

greater than 10,000 barrels per stream 

day because these monitors were 

expected to be in-place to comply with 

the NESHAP for Petroleum Refineries. 

We did not include additional costs to 

upgrade the existing CO2/CO/O2

composition monitors in our impact 

analysis because we intended to use the 

same monitoring requirements as in the 

NESHAP for Petroleum Refineries. 

Therefore, we are proposing to amend 

40 CFR 98.254(g) to refer to 40 CFR 

63.1572(c), rather than 63.1572(a), for 

these O2/CO/O2 composition monitors. 

Paragraph (h) of 40 CFR 98.254 

specifies calibration procedures for 

weighing devices that are used to 

determine the mass of petroleum coke 

fed to the coke calcining unit, as 

required by Equation Y–13. Subpart Y 

currently provides three calibration 

options: (1) Follow the procedures in 

NIST Handbook 44; (2) follow the 

manufacturer’s recommended 

procedures; or (3) follow the procedures 

in 40 CFR 98.3(i). We are proposing to 

amend 40 CFR 98.254(h) to require 

calibration according to the procedures 

specified by NIST Handbook 44 or the 

procedures specified by the 

manufacturer. Note that the 

requirements of 40 CFR 98.3(i) for other 

measurement devices would apply as 

well. 

Reporting Requirements. This section 

covers reporting requirements that have 

not been described in previous sections 

of this preamble. 

We are proposing to amend the 

reporting requirements for Equation 

Y–1 (renumbered to Y–1a) and Y–2 to 

require reporting of whether daily or 

weekly measurement periods are used, 

for verification purposes. 

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

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

we are proposing to amend the 

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

reference 40 CFR 98.36 more generally. 

This would make the references 

consistent with the associated 

requirements in 40 CFR 98.253. 

In our review of the reporting 

requirements in 40 CFR 98.256(f), we 

noted an inadvertent error in 40 CFR 

98.256(f)(10) and (11) [which would be 

redesignated 40 CFR 98.256(f)(11) and 

(12) due to the proposed reporting 

requirement associated with Equation 

Y–7b]. In subpart Y, facility owners and 

operators are required to report 

information about unit-specific 

emission factors for CH4 and N2O, but 

not necessarily report the unit-specific 

emission factor itself. We are proposing 

to correct this inadvertent error and 

require direct reporting of the unitspecific emission factor for CH4 and 

N2O, if used, in the newly designated 40 

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

We are proposing to amend 40 CFR 

98.256(i)(8) to make it consistent with 

the information collected in 40 CFR 

98.245(i)(7). 

We are also proposing to amend 40 

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

reporting requirements for asphalt 

blowing apply at the unit level. 

We are also proposing to re-organize 

the reporting requirements in 40 CFR 

98.256(o) to clarify, for example, that 

the reporting requirement in 40 CFR 

98.256(o)(7) of Part 98 pertains 

specifically to tanks processing 

unstabilized crude oil. 


srobinson on DSKHWCL6B1PROD with PROPOSALS2
48776 Federal Register / Vol. 75, No. 154 / Wednesday, August 11, 2010 / Proposed Rules 

O. Subpart AA (Pulp and Paper 

Manufacturing) 

We are proposing to amend subpart 

AA in response to questions EPA 

received since Part 98 was published on 

October 30, 2009. These amendments 

are intended to provide clarification and 

ensure consistency with other parts of 

the rule. 

EPA received questions regarding the 

methods specified in 40 CFR 98.273 to 

calculate fossil-fuel based CO2

emissions from chemical recovery 

furnaces, chemical recovery combustion 

units, and pulp mill lime kilns. 

Specifically, clarification was requested 

as to whether an owner or operator can 

choose to use a tier other than Tier 1 

from 40 CFR 98.33 to calculate fossilfuel based CO2 emissions. While it was 

our intent to provide this flexibility, the 

rule text indicated that only Tier 1 

could be used. Therefore, we are 

proposing to amend 40 CFR 

98.273(a)(1), (b)(1) and (c)(1) to clarify 

that owners and operators may use a 

higher tier. This flexibility in selecting 

tiers is consistent with 40 CFR 98.34. 

The option to use a higher tier to 

calculate fossil-fuel based emissions 

provides flexibility to reporters and it 

only affects the reporting requirements 

if an owner or operator chooses to use 

a higher tier. EPA also received 

questions regarding the prescribed 

emission factors to calculate fossil-fuel 

based CO2 emissions from lime kilns. 

Specifically, 40 CFR 98.273(c)(1) 

directed owners and operators to use 

emission factors in Table AA–2 to 

calculate CO2 emissions from lime kilns, 

but EPA has received requests to use the 

emission factors provided in Table C–1. 

The emission factors in Table AA–2 

were taken from ‘‘Calculation Tools for 

Estimating Greenhouse Gas Emissions 

from Pulp and Paper Mills’’, Version 1.1, 

July 8, 2005, which was prepared by the 

National Council for Air and Stream 

Improvement (NCASI) for the National 

Council of Forest and Paper 

Associations (ICFPA). Part 98 

incorporated these factors in Table 

AA–2 because they were developed 

specifically for pulp and paper lime 

kilns, which operate at different 

conditions than other general stationary 

combustion units. 

Upon further consideration, we have 

determined that the emission factors 

provided in Table AA–2 are uniquely 

suited for calculating CH4 and N2O 

emissions from lime kilns given these 

emissions are significantly influenced 

by the operating conditions. However, 

EPA has found that the same rationale 

does not support having unique 

emission factors to calculate CO2

emissions from lime kilns. Therefore, 

EPA has removed the CO2 emission 

factors from Table AA–2 and, in 40 CFR 

98.273(c)(1), has directed owners and 

operators to use the CO2 emission 

factors from Table C–1 of subpart C to 

calculate CO2 emissions from lime kilns. 

Modifications to Table AA–2 would 

affect the emissions reported in 2010, 

but would not affect the data that are 

collected to report emissions in 2010. 

Related to the calculation of CH4 and 

N2O emissions described above, and 

consistent with the proposal to allow 

use of higher Tiers than Tier 1 for units 

subject to subpart AA, EPA is proposing 

to allow reporters to also use sitespecific high heating values, as opposed 

to default values, when claculating CH4

and N2O emissions. 

EPA has also received questions from 

owners and operators about whether 

pulp and paper mills are required to 

calculate emissions from the 

combustion of their wastewater 

treatment sludge. Specifically, they 

asked for clarification of whether this 

type of sludge was included in Table C– 

1 and, if not, should they account for 

emissions from the combustion of this 

material. In our efforts to address this 

question, we have not been able to 

identify emission factors developed 

specifically for sludge from a pulp and 

paper mill wastewater facility. However, 

our research indicates that the content 

of this sludge falls within the definition 

of ‘‘Wood and Wood Residuals’’ 

included in Table C–1. 

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

emissions from the combustion of this 

type of sludge may be determined using 

Tier 1 in subpart C. In order to further 

clarify this, we are proposing to add the 

definition of ‘‘Wood and Wood 

Residuals’’ to 40 CFR 98.6 and to 

include wastewater process sludge from 

paper mills in this definition. Clarifying 

that emissions from the combustion of 

sludge from pulp and paper mill 

wastewater treatment facilities may be 

calculated using Tier 1 would require 

that owners and operators estimate the 

volume of sludge combusted using 

company records. Given the broad 

definition of company records, owners 

and operators should be able to develop 

estimates to report these emissions in 

2011. Presuming these changes are 

finalized as proposed, they would be 

incorporated into annual GHG reports 

due in March 2011. 

Finally, EPA received questions 

regarding which emission factors to 

apply when a pulp and paper mill 

combusts solid petroleum coke given 

this fuel type was not included in Table 

C–1 and Table AA–2. In response, we 

are proposing to add this fuel type to 

both tables. However, it is noted that 

emission factors for petroleum coke 

specific to kraft calciners were not 

available. EPA does not believe that any 

kraft calciners are combusting 

petroleum coke, so we have concluded 

that it is not necessary to have emission 

factors for this fuel in Table AA–2. EPA 

seeks comment on this conclusion. 

Further, if information is provided that 

petroleum coke is combusted at kraft 

calciners, please also include any 

information on default CH4 and N2O 

emission factors. 

P. Subpart NN (Suppliers of Natural Gas 

and Natural Gas Liquids) 

Threshold for natural gas local 

distribution companies. The 

applicability provision in subpart A at 

40 CFR 98.2(a)(4)(iii)(B) requires all 

natural gas local distribution companies 

(LDCs), regardless of size, to report the 

GHG emissions that would result from 

the complete combustion or oxidation of 

the annual volumes of natural gas 

provided to end users on their 

distribution systems. Owners and 

operators of LDCs potentially subject to 

subpart NN have asserted that this 

provision results in an unfair burden on 

many small LDCs. 

They have stated that requiring all 

LDCs to report did not adequately 

balance rule coverage of GHGs reported, 

while excluding small entities. For 

example, they highlighted data from the 

Energy Information Administration that 

indicated that 82 percent of facilities are 

estimated to deliver less than 460,000 

mscf per year of natural gas, which is 

equivalent to approximately 25,000 

mtCO2e. They further noted that EPA’s 

own estimates suggest that these 

facilities would be responsible for less 

than 1 percent of the reported GHG 

emissions associated with LDC supply. 

The owners and operators concluded 

that this is a disproportionate burden for 

LDCs, particularly if one considers that 

across the rule, applying a 25,000 

mtCO2e threshold would exclude 

approximately 10 to 15 percent of GHG 

emissions, a much larger percentage of 

emissions than would be excluded 

under LDCs by applying that same 

25,000 mtCO2e threshold. 

The owners and operators noted that 

inclusion of all LDCs in the rule would 

also impose numerous reporting and 

recordkeeping requirements, even 

though most of these facilities would 

actually be eligible to stop reporting in 

three or five years, after they could 

prove to EPA that emissions from their 

supply were less than 15,000 mtCO2e or 

25,000 mtCO2e per year, respectively. 

We note that the threshold 

requirements for LDCs did not change 


srobinson on DSKHWCL6B1PROD with PROPOSALS2
Federal Register / Vol. 75, No. 154 / Wednesday, August 11, 2010 / Proposed Rules 48777 

between the initial proposal in April 

2009 and Part 98 promulgated on 

October 30, 2009. Further, EPA did not 

receive any comments opposed to the 

‘‘all in’’ designation for LDCs during the 

public comment period on the proposed 

Part 98 and, in fact, received two 

comments supporting the lack of a 

threshold of any kind. Therefore, EPA 

retained in Part 98 the provision to 

require all LDCs to report the CO2

emissions associated with their supply. 

EPA retained the provision in order to 

maximize coverage of the GHG 

emissions from natural gas supplies, 

and also to be consistent with other 

suppliers of fossil fuels and industrial 

gases covered by Part 98. An ‘‘all in’’ 

threshold was applied to all of these 

supplier categories. 

Although we believe that the public 

had ample opportunity to comment on 

the threshold for LDCs, we have 

reevaluated this issue in light of the 

information received. We are proposing 

to amend 40 CFR 98.2(a)(4)(iii)(B) in 

subpart A to require all LDCs that 

deliver 460,000 mscf or more of natural 

gas per year to report. We are proposing 

this capacity-based threshold because a 

capacity-based threshold would be more 

familiar to LDCs. Owners and operators 

of LDCs know how much natural gas 

they deliver to their customers and it 

would, therefore, be easier for facilities 

to determine if they are subject to the 

rule than if the threshold were 

emissions-based. The proposed annual 

threshold is approximately equivalent to 

25,000 mtCO2e. 

After further consideration, we have 

concluded that although a threshold 

would result in a loss of emissions 

information to EPA, the emissions 

coverage lost is less than 1 percent. It is 

also true that most of these facilities 

460,000 mscf would be able to stop 

reporting to EPA in three or five years, 

raising the question of whether the 

burden associated with instituting a 

reporting program that includes the 

smaller facilities is necessary. We have 

determined that EPA and other 

stakeholders would be able to use data 

from external sources (e.g., the Energy 

Information Administration) to estimate 

the less than 1 percent of GHG 

emissions that would no longer be 

reported to EPA if a 460,000 mscf 

annual threshold were applied. This 

would minimize any concerns that the 

loss of emissions coverage would inhibit 

the use of the data for future policy 

making. Finally, we have concluded 

that LDCs are unique among suppliers 

in that a large majority of facilities 

would be under a 460,000 mscf 

threshold, and collectively these 

facilities are responsible for a relatively 

low percentage of emissions from the 

industry. 

Q. Subpart OO (Suppliers of Industrial 

Greenhouse Gases) 

We are proposing several changes to 

subpart OO to (1) respond to concerns 

raised by producers of fluorinated GHGs 

regarding the scope of the monitoring 

and reporting requirements, and (2) 

clarify the scope and due dates for 

certain reporting and recordkeeping 

requirements. 

Producers of fluorinated GHGs 

requested that EPA clarify that subpart 

OO does not apply to fluorinated GHGs 

that (1) are either emitted or destroyed 

at the facility before the fluorinated 

GHG product is packaged for sale or for 

shipment to another facility for 

destruction, (2) are produced and 

transformed at the same facility, or (3) 

occur as low-concentration constituents 

(impurities) in fluorinated GHG 

products. The producers also requested 

that EPA amend the rule to account for 

the fact that some fluorinated GHGs do 

not have global warming potential 

values (GWPs) listed in Table A–1 of 

subpart A. For fluorinated GHGs 

without GWPs in Table A–1, facilities 

cannot calculate CO2-equivalent 

production as required by subpart A, 

and importers and exporters cannot take 

advantage of the reporting exemptions 

for small shipments under 40 CFR 

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

in CO2-equivalents. 

Regarding fluorinated GHGs that are 

emitted or destroyed before the product 

is packaged for sale, the producers 

specifically requested that EPA amend 

subpart OO to remove the requirements 

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

monitor and report the destruction of 

fluorinated GHGs that are not included 

in the calculation of the mass produced 

in 40 CFR 98.413(a) because they are 

removed from the production process as 

byproducts or wastes. 

They noted that measuring the flow of 

such fluorinated GHGs into the 

destruction device to the precision 

required (1 percent) posed significant 

technical challenges and that such 

measurement was outside the scope of 

subpart OO. They further stated that 

subpart OO was intended to address the 

quantities of fluorinated GHGs exiting 

production units and entering 

commerce, where commerce includes 

the packaging and marketing or import 

and export of fluorinated GHGs. They 

stated that the proposed subpart L was 

the more appropriate vehicle for the 

monitoring and reporting of emissions 

and destruction of fluorinated GHGs 

still within the production process. 

However, the producers noted that it 

was practical and appropriate under 

subpart OO to measure the quantities of 

fluorinated GHGs that are returned to 

the production facility for destruction 

after entering into commerce (e.g., 

because they have become irretrievably 

contaminated). 

Regarding fluorinated GHGs that are 

produced and transformed at the same 

facility, the fluorinated GHG producers 

noted that these fluorinated GHGs never 

enter the U.S. supply of fluorinated 

GHGs because they never leave the 

facility where they are produced. Thus, 

it is not necessary to track them under 

subpart OO. 

Regarding fluorinated GHGs that 

occur as low-concentration constituents 

of fluorinated GHG products, the 

producers observed that such lowconcentration constituents generally 

consist of by-products that are packaged 

along with the main constituent of the 

product. They noted that exempting the 

production, import, and export of these 

low-concentration constituents from 

monitoring and reporting requirements 

would be consistent with the exemption 

of ‘‘trace’’ concentrations from other 

monitoring requirements in subpart OO, 

such as 40 CFR 98.414(f) and (h). 

In response to the concern regarding 

fluorinated GHGs that are emitted or 

destroyed before the product is 

packaged for sale, we are proposing (1) 

to modify the definition of ‘‘produce a 

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

explicitly exclude the ‘‘creation of 

fluorinated GHGs that are released or 

destroyed at the production facility 

before the production measurement at 

§ 98.414(a);’’ (2) to remove the 

requirements at 40 CFR 98.414(j) and 

98.416(a)(4) to monitor and report the 

destruction of fluorinated GHGs ‘‘that 

are not included in the calculation of 

the mass produced in 40 CFR 98.413(a) 

because they are removed from the 

production process as byproducts or 

wastes;’’ and (3) to modify the 

requirements at 40 CFR 98.414(h) and 

98.416(a)(3) to limit them to ‘‘the mass 

of each fluorinated GHGs that is fed into 

the destruction device and that was 

previously produced as defined at 

§ 98.410(b).’’ 

These proposed amendments would 

clarify that the scope of subpart OO is 

that which EPA has always intended, 

and they would modify the destruction 

monitoring and reporting 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 


srobinson on DSKHWCL6B1PROD with PROPOSALS2
48778 Federal Register / Vol. 75, No. 154 / Wednesday, August 11, 2010 / Proposed Rules 

4 In Part 98, EPA required the monitoring of all 

streams being destroyed because it was our 

understanding, based on conversations with 

fluorinated GHG producers, that the mass flow of 

destroyed fluorinated GHG streams was routinely 

monitored. To arrive at the quantities being 

removed from the supply, EPA required facilities to 

estimate the share of the total quantity of 

fluorinated GHGs destroyed that consisted of 

fluorinated GHGs that were not included in the 

calculation of the mass produced. This share could 

then be subtracted from the total to arrive at the 

amounts destroyed that were removed from the 

supply. In other words, monitoring and reporting of 

the destruction of fluorinated GHGs that were not 

included in the mass produced was required in 

order to estimate the destruction of fluorinated 

GHGs that had been produced. 

5These 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. 

fluorinated GHGs. Specifically, subpart 

OO is intended to address production of 

fluorinated GHGs, not emissions or 

destruction of fluorinated GHGs that 

occur during the production process. To 

clarify this in the regulatory text, we are 

proposing to amend the definition of 

‘‘produce a fluorinated GHG’’ at 40 CFR 

98.410(b) to exclude the ‘‘creation of 

fluorinated GHGS that are released or 

destroyed at the production facility 

before the production measurement at 

§ 98.414(a).’’ 

As noted in the proposed Part 98 (74 

FR 16580), the production measurement 

at 40 CFR 98.414(a) could occur 

wherever it traditionally occurs, e.g., at 

the inlet to the day tank or at the 

shipping dock, as long as the subpart 

OO monitoring requirements were met 

(e.g., one-percent precision and 

accuracy for the mass produced and for 

container heels, if applicable). As noted 

above, emissions upstream of the 

production measurement would be 

subject to proposed subpart L and are 

not part of the subpart OO source 

category. 

We are also proposing to amend 40 

CFR 98.416(a)(3) to limit the monitoring 

and reporting of destroyed fluorinated 

GHGs to those destroyed fluorinated 

GHGs that were previously ‘‘produced’’ 

under today’s revised definition.4 Such 

fluorinated GHGs include but are not 

limited to quantities that are shipped to 

the facility by another facility for 

destruction, and quantities that are 

returned to the facility for reclamation 

but are found to be irretrievably 

contaminated. While monitoring of 

some destroyed streams appears to pose 

significant technical challenges,5

monitoring of quantities of fluorinated 

GHGs that were previously produced 

does not. These quantities can be 

weighed and analyzed by the facility 

upon receipt or upon the facility’s 

conclusion that they cannot be brought 

back to the specifications for new or 

reusable product. 

In response to the concern regarding 

fluorinated GHGs that are produced and 

transformed at the same facility, we are 

proposing to (1) amend the definition of 

‘‘produce a fluorinated GHG’’ to exclude 

‘‘the creation of intermediates that are 

created and transformed in a single 

process with no storage of the 

intermediates;’’ (2) amend the definition 

of ‘‘produce a fluorinated GHG’’ to 

explicitly include ‘‘the manufacture of a 

fluorinated GHG as an isolated 

intermediate for use in a process that 

will result in its transformation either at 

or outside of the production facility;’’ (3) 

add a definition of ‘‘isolated 

intermediate;’’ and (4) add provisions to 

40 CFR 98.414, 98.416, and 98.417 to 

clarify that isolated intermediates that 

are produced and transformed at the 

same facility are exempt from subpart 

OO monitoring, reporting, and 

recordkeeping requirements 

respectively. 

As noted by the producers, 

fluorinated GHGs that are produced and 

transformed at the same facility never 

enter the U.S. supply of industrial 

greenhouse gases; thus, they do not 

need to be reported under subpart OO. 

This is true both of isolated 

intermediates and of intermediates that 

are created and transformed in a single 

process with no storage of the 

intermediate. However, while we are 

proposing to exclude the latter from the 

definition of ‘‘produce a fluorinated 

GHG,’’ we are proposing to include the 

former in that definition. This is 

because the manufacture of isolated 

intermediates, which can lead to 

emissions of those intermediates, is of 

interest under subpart L, and we would 

like to use the same definition of 

‘‘produce a fluorinated GHG’’ for subpart 

L as for subpart OO for consistency and 

clarity. Thus, instead of excluding the 

manufacture of isolated intermediates 

that are transformed at the same facility 

from the definition of ‘‘produce a 

fluorinated GHG,’’ we are proposing to 

add provisions to exclude it from the 

subpart OO monitoring, reporting, and 

recordkeeping requirements. We are 

also proposing to add a definition of 

‘‘isolated intermediate’’ that is the same 

as that proposed for subpart L (75 FR 

18652, April 12, 2010). 

In response to the concern regarding 

fluorinated GHGs that occur as lowconcentration constituents of 

fluorinated GHG products, we are 

proposing to define and exclude lowconcentration constituents from the 

monitoring, reporting, and 

recordkeeping requirements for 

fluorinated GHG production, exports, 

and imports. For purposes of production 

and export, we are proposing to define 

low-concentration constituent 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 (AHRI 700), for SF6 used as 

an insulator in electrical equipment (IEC 

60376), and for perfluorocarbons and 

other fluorinated GHGs used in 

electronics manufacturing (SEMI C3 

series). To meet these standards, which 

set limits that range from less than 0.1 

percent to 0.5 percent for all fluorinated 

GHG impurities combined, fluorinated 

GHG producers are likely to have 

identified and quantified the 

concentrations of impurities at 

concentrations at or above 0.1 percent 

for the products subject to the 

standards. Finally, below concentrations 

of 0.1 percent, fluorinated GHG 

impurities are not likely to have a 

significant impact on the GWP of the 

product. For example, if a lowconcentration constituent occurs in 

concentrations of just under 0.1 percent 

and has a GWP that is ten times as large 

as the GWP of the main constituent of 

the product, it will increase the 

weighted GWP of the product by just 

under one percent. 

To ensure that fluorinated GHG 

production facilities rely on data of 

known and acceptable quality when 

determining whether or not to report a 

minor fluorinated GHG constituent of a 

product, we are also proposing product 

sampling and analytical requirements at 

40 CFR 98.414(n) and corresponding 

calibration requirements at 40 CFR 

98.414(o). 

For purposes of fluorinated GHG 

import, we are proposing to define lowconcentration constituent as a 

fluorinated GHG constituent of a 

fluorinated GHG product that occurs in 

the product in concentrations below 0.5 

percent by mass. We are proposing a 

higher concentration for fluorinated 

GHG imports than for fluorinated GHG 

production and exports because 

importers are less likely than producers 

to have detailed information on the 

identities and concentrations of minor 

fluorinated GHG constituents in their 

products. 


srobinson on DSKHWCL6B1PROD with PROPOSALS2
Federal Register / Vol. 75, No. 154 / Wednesday, August 11, 2010 / Proposed Rules 48779 

In response to the concerns regarding 

fluorinated GHGs that do not have 

GWPs listed in Table A–1, we are 

proposing (1) to exempt such 

compounds from the general subpart A 

requirement to report supply flows in 

terms of CO2 equivalents and (2) to 

recast the reporting exemptions for 

import and export of small shipments in 

terms of kilograms of fluorinated GHGs 

or N2O rather than tons of CO2- 

equivalents. The amendment to subpart 

A is discussed in more detail in section 

II.G of this preamble. The exemptions 

for import and export would be applied 

to shipments of less than 25 kilograms 

of fluorinated GHGs or N2O rather than 

to shipments of less than 250 metric 

tons of CO2e. This would enable small 

shipments of fluorinated GHGs to be 

exempt from reporting regardless of 

whether or not the fluorinated GHG had 

a GWP listed in Table A–1. Our analysis 

of import and export data indicates that 

this change would slightly increase both 

the number and total mass of the 

imports and exports reported under the 

rule, but this analysis does not account 

for fluorinated GHGs whose GWPs are 

not listed in Table A–1. If those 

fluorinated GHGs were accounted for, 

we believe that the level of reporting 

would increase even less and might 

even decrease slightly. 

Other Corrections. We are also 

proposing to amend the reporting and 

recordkeeping provisions in subpart OO 

to correct internal inconsistencies in the 

subpart and to clarify those 

requirements. 

We are proposing to amend the 

reporting requirements in 40 CFR 

98.416(a)(15) and (c)(10) to remove N2O 

from the list of GHGs that must be 

reported when they are transferred off 

site for destruction, because N2O 

transferred off site for destruction is not 

required to be monitored. 

We are proposing to amend 40 CFR 

98.416(b) and (e) to clarify the due dates 

of the one-time reports required by 

those paragraphs. The proposed due 

date for the one-time reports is March 

31, 2011, or within 60 days of 

commencing fluorinated GHG 

destruction or production (as 

applicable). The due date in 40 CFR 

98.416(e) in subpart OO was April 1, 

2011, and there was no provision for 

commencing fluorinated GHG 

destruction or production after that 

date. The proposed amendments will 

make the due dates in 40 CFR 98.416(b) 

and (e) consistent with each other, with 

the due date for a similar report 

required in subpart O, and with the due 

date for other reporting under the rule. 

We are proposing to amend the 

recordkeeping requirements in 40 CFR 

98.417(a)(2) to correct and update an 

internal reference. The correct reference 

is to ‘‘§ 98.414(m) and (o),’’ instead of 

‘‘§ 98.417(j) and (k).’’ We are proposing 

to amend 40 CFR 98.417(b) to remove 

the reference to the ‘‘annual destruction 

device outlet reports’’ in 40 CFR 

98.416(e) since no such reporting 

requirement exists. 

Finally, we are proposing to amend 40 

CFR 98.417(d)(2) to correct a 

typographical error; that paragraph 

should refer to ‘‘the invoice for the 

export,’’ rather than for the ‘‘import.’’ 

R. Subpart PP (Suppliers of Carbon 

Dioxide) 

In subpart PP, we are proposing to 

remove the words ‘‘each’’ from the list of 

GHGs to report in 40 CFR 98.422. This 

change would align this section with the 

requirements of the rest of subpart PP, 

which allow for monitoring of an 

aggregated flow of CO2 if it is done at 

a gathering point downstream of 

individual production wells or 

production process units. 

We are proposing to allow those 

suppliers that supply CO2 in containers 

to calculate the annual mass of CO2

supplied in containers by using weigh 

bills, scales, load cells, or loaded 

container volume readings as an 

alternative to flow meters. As a result of 

many questions received during 

outreach in support of alternative 

procedures for CO2 supplied in 

containers, we have reevaluated the 

calculation procedures for CO2

suppliers. We have concluded that 

measurements made with weigh bills, 

scales, load cells, or loaded container 

volume readings will continue to meet 

the level of data quality and accuracy 

needed by EPA with respect to subpart 

PP. We have reached this conclusion 

with consideration to minimizing the 

burden on and maximizing the 

flexibility provided to industry. 

We are proposing multiple 

amendments to the regulatory text to 

accommodate this proposed provision. 

First, we are proposing that 40 CFR 

98.423(b) be renumbered to 40 CFR 

98.423(c) and that a new 40 CFR 

98.423(b) be added with calculation 

procedures for CO2 supplied in 

containers. Second, we are proposing to 

amend the first sentence of 40 CFR 

98.423(a) to allow suppliers that supply 

CO2 in containers to use the alternative 

procedures in 40 CFR 98.423(b). Third, 

we are proposing to add new QA/QC 

procedures for suppliers that supply 

CO2 in containers to 40 CFR 98.424(a). 

Fourth, we are proposing to add missing 

data procedures for suppliers that 

supply CO2 in containers to 40 CFR 

98.425(d). Finally, we are proposing to 

make multiple amendments to 

regulatory text in 40 CFR 98.426 so that 

all data collected with weigh bills, 

scales, load cells, or loaded container 

volume readings must be reported just 

as for all data collected with flow 

meters. 

We note that under the existing 

requirements, importers and exporters 

that import and export CO2 in 

containers must measure the mass of 

CO2 in containers using weigh bills, 

scales, or load cells. In this action, we 

are not proposing that the use of loaded 

container volume readings be allowed 

for such reporters as an alternative to 

weigh bills, scales, or load cells because 

we have received no questions from 

importers or exporters suggesting the 

need for such an allowance. We seek 

comment on whether such an allowance 

should be extended to importers and 

exporters of CO2 in containers, and if so 

whether the calculation procedures, 

QA/QC procedures, missing data 

procedures, and reporting requirements 

for loaded container volume readings 

proposed in this action for suppliers 

should be offered to importers and 

exporters. 

We are proposing to remove the 

requirement that CO2 measurement 

must be made prior to subsequent 

purification, processing, or compression 

at 40 CFR 98.423(a)(1), (a)(2), and (b) 

(which we are proposing to redesignate 

as 40 CFR 98.423(c)). This provision 

created confusion and conflict over 

where to place a flow meter. For 

example, at least one reporter has 

indicated that only a portion of a CO2

stream is transferred for commercial 

application while the rest is retained for 

onsite use and emission, and this 

portion of the stream is segregated only 

after processing. As a result of this and 

other concerns that the requirement to 

install flow meters prior to purification, 

processing, or compression could result 

in a requirement to install the flow 

meter at a technically infeasible point, 

we reevaluated the value of such a 

constraint on the CO2 calculations. 

Since the purpose of subpart PP is to 

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 


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for injection and where a flow meter is 

used, we are proposing to add language 

at 40 CFR 98.424(a) requiring the flow 

meter to be located after the point of 

segregation. We are also proposing to 

amend existing language in 40 CFR 

98.424(a) to reference this new 

requirement. 

Because the proposed amendments 

would allow flow meters to be located 

after purification, compression, or 

processing, we are proposing to add 

data reporting requirements in 40 CFR 

98.426 to collect additional information 

on flow meter location. Specifically, we 

are proposing that facilities would 

report information on the placement of 

each flow meter used in relation to the 

points of CO2 stream capture, 

deyhdration, compression, and other 

processing. Knowing where in the 

production process the flow meter is 

located will enable EPA to effectively 

compare data across and to learn about 

the efficacy of various CO2 stream 

capture processes. 

The current subpart PP regulatory text 

requires that a reporter using a 

volumetric flow meter to measure the 

flow of a CO2 stream measure density of 

that CO2 stream in order to calculate the 

mass of CO2 supplied. As a result of 

new analysis, we have concluded that 

the mass of CO2 in a stream can be 

adequately determined by converting 

the volumetric flow of CO2 from 

operating conditions to standard 

conditions and then applying the 

density value for CO2 at standard 

conditions and the measured 

concentration of CO2 in the flow. This 

approach may also be less burdensome 

for reporters than directly measuring 

density with equipment. Therefore, we 

are proposing to amend 40 CFR 

98.424(a)(5) by replacing the word 

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

We are also proposing to add a new 

paragraph 40 CFR 98.424(c) so that 

suppliers will be able to calculate the 

mass of CO2 in a stream from the 

measured volumetric flow (converted to 

standard conditions) and CO2

concentration, and the given density of 

CO2 at standard conditions. 

For the calculation in the proposed 

paragraph 40 CFR 98.424(c), standard 

conditions under subpart PP would be 

a temperature and an absolute pressure 

of 60°F and 1 atmosphere. Note that this 

would be different than the standard 

conditions defined in subpart A (40 CFR 

98.6), which are 68°F and 14.7 psia. It 

is our understanding that 60°F and 1 

atmosphere (which is equivalent to 14.7 

psia) are more commonly used by the 

industries covered by subpart PP, and 

we seek comment on this conclusion. 

Given these conditions, we are 

proposing that reporters must use 

0.0018704 metric tons per standard 

cubic meter as a density value for CO2

at standard conditions if this is the 

industry standard practice used to 

determine density. 

The current subpart PP regulatory text 

also requires that an appropriate method 

published by a consensus-based 

standards organization be used to 

measure density if such a method exists. 

Where no such method exists, an 

industry standard practice must be 

followed. We have been unable to 

identify any method published by a 

consensus-based standards organization 

that accounts for the approach for 

determining density described above 

and have concluded that it would be 

categorized as an industry standard 

practice. Therefore, we are proposing to 

amend language in 40 CFR 98.424(a)(5) 

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

choose equally from between a method 

published by a consensus-based 

standards organization that is 

appropriate or an industry standard 

practice to determine density. 

We are proposing to amend the 

reference to the U.S. Food and Drug 

Administration food-grade 

specifications for CO2 in 40 CFR 

98.424(b)(2) to correct a typographical 

error. The correct reference is 21 CFR 

184.1240, not 21 CFR 184.1250. 

III. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review 

This action is not a ‘‘significant 

regulatory action’’ under the terms of 

Executive Order (EO) 12866 (58 FR 

51735, October 4, 1993) and is therefore 

not subject to review under the EO. 

B. Paperwork Reduction Act 

This action does not impose any new 

information collection burden. These 

proposed amendments do not make any 

substantive changes to the reporting 

requirements in any of the subparts for 

which amendments are being proposed. 

In many cases, the proposed 

amendments to the reporting 

requirements could potentially reduce 

the reporting burden by making the 

reporting requirements conform more 

closely to current industry practices. 

The Office of Management and Budget 

(OMB) has previously approved the 

information collection requirements 

contained in the regulations 

promulgated on October 30, 2009, under 

40 CFR Part 98 under the provisions of 

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

3501 et seq. and has assigned OMB 

control number 2060–0629. The OMB 

control numbers for EPA’s regulations 

in 40 CFR are listed in 40 CFR part 9. 

Further information on EPA’s 

assessment on the impact on burden can 

be found in the Revisions Cost Memo 

(EPA–HQ–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 this proposed rule on small entities, 

small entity is defined as: (1) A small 

business as defined by the Small 

Business Administration’s regulations at 

13 CFR 121.201; (2) a small 

governmental jurisdiction that is a 

government of a city, county, town, 

school district or special district with a 

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

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

owned and operated and is not 

dominant in its field. 

After considering the economic 

impacts of these proposed rule 

amendments on small entities, I certify 

that this action will not have a 

significant economic impact on a 

substantial number of small entities. 

The proposed rule amendments will not 

impose any new requirement on small 

entities that are not currently required 

by the rules promulgated on October 30, 

2009 (i.e., calculating and reporting 

annual GHG emissions). 

EPA took several steps to reduce the 

impact of Part 98 on small entities. For 

example, EPA determined appropriate 

thresholds that reduced the number of 

small businesses reporting. In addition, 

EPA did not require facilities to install 

CEMS if they did not already have them. 

Facilities without CEMS can calculate 

emissions using readily available data or 

data that are less expensive to collect 

such as process data or material 

consumption data. For some source 

categories, EPA developed tiered 

methods that are simpler and less 

burdensome. Also, EPA required annual 

instead of more frequent reporting. 

Finally, EPA continues to conduct 

significant outreach on the mandatory 

GHG reporting rule and maintains an 

‘‘open door’’ policy for stakeholders to 

help inform EPA’s understanding of key 

issues for the industries. 


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We continue to be interested in the 

potential impacts of the proposed rule 

amendments on small entities and 

welcome comments on issues related to 

such impacts. 

D. Unfunded Mandates Reform Act 

(UMRA) 

This proposed rule does not contain 

a Federal mandate that may result in 

expenditures of $100 million or more 

for State, local, and tribal governments, 

in the aggregate, or the private sector in 

any one year. EPA has estimated that, 

overall, the proposed revisions do not 

significantly change the overall costs of 

compliance with Part 98. The proposed 

amendments include providing 

additional flexibility for reporters, 

clarifying existing reporting 

requirements, and requiring reporting of 

information already required to be 

collected under Part 98. EPA estimates 

that the cost for all reporters in 

reviewing the proposed rule and 

determining if, and if so how, it applies 

to their facility, is approximately $2.5 

million in the first year. Considering the 

additional flexibilities proposed, in 

sum, EPA has estimated that the 

proposed rule, if finalized, would 

reduce the burden to reporters as 

compared to the 2009 final rule. Thus, 

this rule is not subject to the 

requirements of sections 202 or 205 of 

UMRA. For more information on the 

cost analysis, please refer to the 

memorandum titled ‘‘Mandatory 

Greenhouse Gas Reporting: Changes in 

National Cost Estimates Associated with 

the Proposed Notice of Revisions’’ found 

in the docket at (EPA–HQ–OAR–2008– 

0508). 

This proposed rule is also not subject 

to the requirements of section 203 of 

UMRA because it contains no regulatory 

requirements that might significantly or 

uniquely affect small governments. EPA 

determined that the proposed rule 

amendments contain no regulatory 

requirements that might significantly or 

uniquely affect small governments 

because the amendments will not 

impose any new requirements that are 

not currently required by the rules 

published on October 30, 2009 (i.e., 

calculating and reporting annual GHG 

emissions). EPA concluded in the 

preamble to that final rule that the rule 

‘‘* * * contains no regulatory 

requrements that might significantly or 

uniquely affect small governments’’ (40 

CFR 56260). Because the final rule was 

not determined to significantly or 

uniquely affect small governments, and 

because this proposed rule generally 

reduces the burden associated with the 

2009 final rule, these rule amendments 

would not unfairly apply to small 

governments. 

E. Executive Order 13132: Federalism 

This action does not have federalism 

implications. It will not have substantial 

direct effects on the States, on the 

relationship between the national 

government and the States, or on the 

distribution of power and 

responsibilities among the various 

levels of government, as specified in 

Executive Order 13132. However, for a 

more detailed discussion about how 

these proposed rule amendments would 

relate to existing State programs, please 

see Section II of the proposal preamble 

for Part 98 (74 FR 16457 to 16461, April 

10, 2009). 

These amendments apply directly to 

facilities that supply fuel or chemicals 

that when used emit greenhouse gases 

or facilities that directly emit 

greenhouses gases. They do not apply to 

governmental entities unless the 

government entity owns a facility that 

directly emits greenhouse gases above 

threshold levels (such as a landfill or 

large stationary combustion source), so 

relatively few government facilities 

would be affected. This regulation also 

does not limit the power of States or 

localities to collect GHG data and/or 

regulate GHG emissions. Thus, EO 

13132 does not apply to this action. 

Although section 6 of Executive Order 

13132 does not apply to this action, EPA 

did consult with State and local officials 

or representatives of State and local 

governments in developing Part 98. A 

summary of EPA’s consultations with 

State and local governments is provided 

in Section VIII.E of the preamble to the 

final Part 98 (74 FR 56260, October 30, 

2009). 

In the spirit of Executive Order 13132, 

and consistent with EPA policy to 

promote communications between EPA 

and State and local governments, EPA 

specifically solicits comment on this 

proposed action from State and local 

officials. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

This action does not have tribal 

implications, as specified in Executive 

Order 13175 (65 FR 67249, November 9, 

2000). The proposed rule amendments 

would not result in any changes to the 

requirements of the 2009 rule. Thus, 

Executive Order 13175 does not apply 

to this action. 

Although Executive Order 13175 does 

not apply to this action, EPA sought 

opportunities to provide information to 

Tribal governments and representatives 

during the development of the rules 

promulgated on October 30, 2009. A 

summary of the EPA’s consultations 

with Tribal officials is provided 

Sections VIII.E and VIII.F of the 

preamble to the final Part 98 (74 FR 

56260, October 30, 2009). 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

EPA interprets EO 13045 (62 FR 

19885, April 23, 1997) as applying only 

to those regulatory actions that concern 

health or safety risks, such that the 

analysis required under section 5–501 of 

the EO has the potential to influence the 

regulation. This action is not subject to 

EO 13045 because it does not establish 

an environmental standard intended to 

mitigate health or safety risks. 

H. Executive Order 13211: Actions That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This action is not subject to Executive 

Order 13211 (66 FR 28355 (May 22, 

2001)), because it is not a significant 

regulatory action under Executive Order 

12866. 

I. National Technology Transfer and 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (NTTAA), Public Law No. 

104–113 (15 U.S.C. 272 note) directs 

EPA to use voluntary consensus 

standards in its regulatory activities 

unless to do so would be inconsistent 

with applicable law or otherwise 

impractical. Voluntary consensus 

standards are technical standards (e.g., 

materials specifications, test methods, 

sampling procedures, and business 

practices) that are developed or adopted 

by voluntary consensus standards 

bodies. NTTAA directs EPA to provide 

Congress, through OMB, explanations 

when the Agency decides not to use 

available and applicable voluntary 

consensus standards. 

This proposed rulemaking involves 

technical standards. No new test 

methods were developed for this 

proposed rule; rather, EPA identified 

existing means of monitoring, reporting, 

and keeping records of greenhouse gas 

emissions. EPA proposes to use two 

additional voluntary consensus 

standards from ASTM International. 

Part 98 includes the use of over 40 

voluntary consensus standards from 

various consensus standards bodies, for 

example, ASTM International, the 

American Society of Chemical 

Engineers, Gas Processors Association, 

the American Gas Association, and the 

American Petroleum Institute. The 

proposed addition of these two 


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voluntary consensus standards from 

ASTM International to Part 98 will help 

petroleum refineries and petrochemical 

facilities monitor, report, and keep 

records of greenhouse gas emissions. 

The test methods are incorporated by 

reference into the proposed rule and are 

available as specified in proposed 

amendments to 40 CFR 98.7. 

By incorporating voluntary consensus 

standards into this proposed rule, EPA 

is both meeting the requirements of the 

NTTAA and presenting multiple 

options and flexibility for measuring 

greenhouse gas emissions. 

EPA welcomes comments on this 

aspect of the proposed rulemaking and, 

specifically, invites the public to 

identify potentially-applicable 

voluntary consensus standards and to 

explain why such standards should be 

used in this regulation. 

J. Executive Order 12898: Federal 

Actions to Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order (EO) 12898 (59 FR 

7629 (Feb. 16, 1994)) establishes federal 

executive policy on environmental 

justice. Its main provision directs 

federal agencies, to the greatest extent 

practicable and permitted by law, to 

make environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority 

populations and low-income 

populations in the United States. 

EPA has determined that this 

proposed rule will not have 

disproportionately high and adverse 

human health or environmental effects 

on minority or low-income populations 

because it does not affect the level of 

protection provided to human health or 

the environment because it is a rule 

addressing information collection and 

reporting procedures. 

List of Subjects in 40 CFR Part 98 

Environmental protection, 

Administrative practice and procedure, 

Greenhouse gases, Incorporation by 

reference, Suppliers, Reporting and 

recordkeeping requirements. 

Dated: July 20, 2010. 

Lisa P. Jackson, 

Administrator. 

For the reasons stated in the 

preamble, title 40, chapter I, of the Code 

of Federal Regulations is proposed to be 

amended as follows: 

PART 98—[AMENDED] 

1. The authority citation for part 98 

continues to read as follows: 

Authority: 42 U.S.C. 7401, et seq. 

Subpart A—[Amended] 

2. Section 98.2 is amended by revising 

paragraph (a)(4)(iii)(B) to read as 

follows: 

§ 98.2 Who must report? 

(a) * * * 

(4) * * * 

(iii) * * * 

(B) Local natural gas distribution 

companies that deliver 460,000 

thousand standard cubic feet or more of 

natural gas per year. 

* * * * * 

3. Section 98.3 is amended by: 

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

(c)(4)(ii), (c)(4)(iii) introductory text, 

(c)(4)(iii)(A), (c)(4)(iii)(B), and (c)(5)(i). 

b. Revising the third sentence of 

paragraph (d)(3) introductory text. 

c. Revising the first sentence of 

paragraph (f). 

d. Revising paragraphs (g)(4), 

(g)(5)(iii). 

e. Revising paragraph (h). 

f. Revising paragraph (i). 

g. Adding paragraph (j). 

§ 98.3 What are the general monitoring, 

reporting, recordkeeping and verification 

requirements of this part? 

* * * * * 

(c) * * * 

(1) Facility name or supplier name (as 

appropriate), facility or supplier ID 

number, and physical street address of 

the facility or supplier, including the 

city, state, and zip code. 

* * * * * 

(4) * * * 

(i) Annual emissions (including 

biogenic CO2) aggregated for all GHG 

from all applicable source categories in 

subparts C through JJ of this part and 

expressed in metric tons of CO2e 

calculated using Equation A–1 of this 

subpart. 

(ii) Annual emissions of biogenic CO2

aggregated for all applicable source 

categories in subparts C through JJ of 

this part in metric tons. Units that use 

the methodologies in part 75 of this 

chapter to calculate CO2 mass emissions 

are not required to separately report 

biogenic CO2 emissions, but may do so 

as an option. 

(iii) Annual emissions from each 

applicable source category in subparts C 

through JJ of this part, expressed in 

metric tons of each applicable GHG 

listed in this paragraph (4)(iii)(A) 

through (4)(iii)(E). 

(A) Biogenic CO2. Units that use the 

methodologies in part 75 of this chapter 

to calculate CO2 mass emissions are not 

required to separately report biogenic 

CO2 emissions, but may do so as an 

option. 

(B) CO2 (including biogenic CO2). 

* * * * * 

(5) * * * 

(i) Total quantity of GHG aggregated 

for all GHG from all applicable supply 

categories in subparts KK through PP of 

this part and expressed in metric tons of 

CO2e calculated using Equation A–1 of 

this subpart. For fluorinated GHGs, 

calculate and report CO2e for only those 

fluorinated GHGs listed in Table A–1 of 

this subpart. 

* * * * * 

(d) * * * 

(3) * * * An owner or operator that 

submits an abbreviated report must 

submit a full GHG report according 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. 


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Such notification will identify each 

such substantive error. The owner or 

operator shall, within 45 days of receipt 

of the notification, either resubmit the 

report that, for each identified 

substantive error, corrects the identified 

substantive error (in accordance with 

the applicable requirements of this part) 

or provide information demonstrating 

that the previously submitted report 

does not contain the identified 

substantive error or that the identified 

error is not a substantive error. 

(3) A substantive error is an error that 

impacts the quantity of GHG emissions 

reported or otherwise prevents the 

reported data from being validated or 

verified. 

(4) Notwithstanding paragraphs (h)(1) 

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

by the owner or operator, the 

Administrator may provide reasonable 

extensions of the 45-day period for 

submission of the revised report or 

information under paragraphs (h)(1) and 

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

Administrator receives a request for 

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 and accuracy 

requirements. The owner or operator of 

a facility or supplier that is subject to 

the requirements of this part must meet 

the applicable flow meter calibration 

and accuracy requirements of this 

paragraph (i). The accuracy 

specifications in this paragraph (i) do 

not apply where either the use of 

company records (as defined in § 98.6) 

or the use of ‘‘best available 

information’’ is specified in an 

applicable subpart of this 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 industry standards and 

manufacturer’s specifications. The 

procedures and methods used to 

quality-assure the data from each 

measurement device shall be 

documented in the written Monitoring 

Plan, pursuant to paragraph (g)(5)(i)(C) 

of this section. 

(i) All flow meters and other 

measurement devices that are subject to 

the provisions of this paragraph (i) must 

be calibrated according to one of the 

following. You may use the 

manufacturer’s recommended 

procedures; an appropriate industry 

consensus standard method; or a 

method specified in a relevant subpart 

of this part. The calibration method(s) 

used shall be documented in the 

Monitoring Plan required under 

paragraph (g) of this section. 

(ii) For facilities and suppliers that 

become subject to this part after April 1, 

2010, all flow meters and other 

measurement devices (if any) that are 

required by the relevant subpart(s) of 

this part to provide data for the GHG 

emissions calculations shall be installed 

no later than the date on which data 

collection is required to begin 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. 

CE

R A

R = − ×100 Eq. A-2 ( )

Where: 

CE = Calibration error (%) 

R = Reference value 

A = Flow meter response to the reference 

value 

(3) For orifice, nozzle, and venturi 

flow meters, the initial quality 

assurance consists of in-situ calibration 

of the differential pressure (delta-P), 

total pressure, and temperature 

transmitters. 

(i) Calibrate each transmitter at a zero 

point and at least one upscale point. 

Fixed reference points, such as the 

freezing point of water, may be used for 

temperature transmitter calibrations. 

Calculate the calibration error of each 

transmitter at each measurement point, 

using Equation A–3 of this subpart. The 

terms ‘‘R’’, ‘‘A’’, and ‘‘FS’’ in Equation A– 

3 of this subpart must be in consistent 

units of measure (e.g., milliamperes, 

inches of water, psi, degrees). For each 

transmitter, the CE value at each 

measurement point shall not exceed 2.0 

percent of 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. 


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48784 Federal Register / Vol. 75, No. 154 / Wednesday, August 11, 2010 / Proposed Rules 

CE

R A

FS = − ×100 Eq. A-3 ( )

Where: 

CE = Calibration error (%) 

R = Reference value 

A = Transmitter response to the reference 

value 

FS = Full-scale value of the transmitter 

(ii) In cases where there are only two 

transmitters (i.e., differential pressure 

and either temperature or total pressure) 

in the immediate vicinity of the flow 

meter’s primary element (e.g., the orifice 

plate), or when there is only a 

differential pressure transmitter in close 

proximity to the primary element, 

calibration of these existing transmitters 

to a CE of 2.0 percent or less at each 

measurement point is still required, in 

accordance with paragraph (i)(3)(i) of 

this section; alternatively, when two 

transmitters are calibrated, the results 

are acceptable if the sum of the CE 

values for the two transmitters at each 

calibration level does not exceed 4.0 

percent. However, note that installation 

and calibration of an additional 

transmitter (or transmitters) at the flow 

monitor location to measure 

temperature or total pressure or both is 

not required in these cases. Instead, you 

may use assumed values for temperature 

and/or total pressure, based on 

measurements of these parameters at a 

remote location (or locations), provided 

that the following conditions are met: 

(A) You must demonstrate that 

measurements at the remote location(s) 

can, when appropriate correction factors 

are applied, reliably and accurately 

represent the actual temperature or total 

pressure at the flow meter under all 

expected ambient conditions. 

(B) You must make all temperature 

and/or total pressure measurements in 

the demonstration described in 

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

with calibrated gauges, sensors, 

transmitters, or other appropriate 

measurement devices. At a minimum, 

calibrate each of these devices to an 

accuracy within the appropriate error 

range for the specific measurement 

technology, according to one of the 

following. You may calibrate using an 

industry consensus standards or a 

manufacturer’s specification. 

(C) You must document the methods 

used for the demonstration described in 

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

the written Monitoring Plan under 

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

You must also include the data from the 

demonstration, the mathematical 

correlation(s) between the remote 

readings and actual flow meter 

conditions derived from the data, and 

any supporting engineering calculations 

in the Monitoring Plan. You must 

maintain all of this information in a 

format suitable for auditing and 

inspection. 

(D) You must use the mathematical 

correlation(s) derived from the 

demonstration described in paragraph 

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

remote temperature or the total pressure 

readings, or both, to the actual 

temperature or total pressure at the flow 

meter, or both, on a daily basis. You 

shall then use the actual temperature 

and total pressure values to correct the 

measured flow rates to standard 

conditions. 

(E) You shall periodically check the 

correlation(s) between the remote and 

actual readings (at least once a year), 

and make any necessary adjustments to 

the mathematical relationship(s). 

(4) Fuel billing meters are exempted 

from the calibration requirements of this 

section and from the Monitoring Plan 

and recordkeeping provisions of 

paragraphs (g)(5)(i)(C) and (g)(7) of this 

section, provided that the fuel supplier 

and any unit combusting the fuel do not 

have any common owners and are not 

owned by subsidiaries or affiliates of the 

same company. Meters used exclusively 

to measure the flow rates of fuels that 

are used for unit startup or ignition are 

also exempted from the calibration 

requirements of this section. 

(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 relavant missing data 

sections during the period of data 

invalidation. 

(j) Measurement Device Installation. 

(1) General. If an owner or operator 

required to report under subpart P, 

subpart X or subpart Y of this part has 

process equipment or units that operate 

continuously and it is not possible to 

install a required flow meter or other 

measurement device by April 1, 2010, 

(or by any later date in 2010 approved 

by the Administrator as part of an 

extension of best available monitoring 

methods per paragraph (d) of this 

section) without process equipment or 

unit shutdown, or through a hot tap, the 

owner or operator may request an 

extension from the Administrator to 

delay installing the measurement device 

until the next scheduled process 

equipment or unit shutdown. If 

approval for such an extension is 

granted by the Administrator, the owner 

or operator must use best available 

monitoring methods during the 

extension period. 

(2) Requests for extension of the use 

of best available monitoring methods for 

measurement device installation. The 

owner or operator must first provide the 

Administrator an initial notification of 

the intent to submit an extension 

request for use of best available 

monitoring methods beyond December 

31, 2010 (or an earlier date approved by 

EPA) in cases where measurement 

device installation would require a 

process equipment or unit shutdown, or 

could only be done through a hot tap. 

The owner or operator must follow-up 

this initial notification with the 

complete extension request containing 

the information specified in paragraph 

(j)(4) of this section. 

(3) Timing of request. 


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(i) The initial notice of intent must be 

submitted no later than January 1, 2011, 

or by the end of the approved use of best 

available monitoring methods extension 

in 2010, whichever is earlier. The 

completed extension request must be 

submitted to the Administrator no later 

than February 15, 2011. 

(ii) Any subsquent extensions to the 

original request must be submitted to 

the Administrator within 4 weeks of the 

owner or operator identifying the need 

to extend the request, but in any event 

no later than 4 weeks before the 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. 

4. Section 98.4 is amended by revising 

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

follows: 

§ 98.4 Authorization and responsibilities of 

the designated representative. 

* * * * * 

(i) * * * 

(2) The name, organization name 

(company 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. 

* * * * * 

5. Section 98.6 is amended by: 

a. Adding in alphabetical order 

definitions for ‘‘Agricultural 

byproducts,’’ ‘‘Primary fuel,’’ ‘‘Solid 

byproducts,’’ ‘‘Waste oil,’’ and ‘‘Wood 

residuals.’’ 

b. Revising the definitions for ‘‘Bulk 

natural gas liquid or NGL,’’ ‘‘Distillate 

Fuel Oil,’’ ‘‘Fossil fuel,’’ ‘‘Municipal solid 

waste or MSW,’’ ‘‘Natural gas,’’ and 

‘‘Natural gas liquids (NGLs).’’ 

c. Removing the definition for ‘‘Fossil 

fuel-fired.’’ 

§ 98.6 Definitions. 

* * * * * 

Agricultural byproducts means those 

parts of arable crops that are not used 

for the primary purpose of producing 

food. Agricultural byproducts include, 

but are not limited to, oat, corn and 

wheat straws, bagasse, peanut shells, 

rice and coconut husks, soybean hulls, 

palm kernel cake, cottonseed and 

sunflower seed cake, and pomace. 

* * * * * 

Bulk natural gas liquid or NGL refers 

to mixtures of hydrocarbons that have 

been separated from natural gas as 

liquids through the process of 

absorption, condensation, adsorption, or 

other methods. Generally, such liquids 

consist of ethane, propane, butanes, and 

pentanes plus. Bulk NGL is sold to 

fractionators or to refineries and 

petrochemical plants where the 

fractionation takes place. 

* * * * * 

Distillate Fuel Oil means a 

classification for one of the petroleum 

fractions produced in conventional 

distillation operations and from crackers 

and hydrotreating process units. The 

generic term distillate fuel oil includes 

kerosene, kerosene-type jet fuel, diesel 

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

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

and No. 4). 

* * * * * 

Fossil fuel means natural gas, 

petroleum, coal, or any form of solid, 

liquid, or gaseous fuel derived from 

such material, for purpose of creating 

useful heat. 

* * * * * 

Municipal solid waste or MSW means 

solid phase household, commercial/ 

retail, and/or institutional waste. 

Household waste includes material 

discarded by single and multiple 


srobinson on DSKHWCL6B1PROD with PROPOSALS2
48786 Federal Register / Vol. 75, No. 154 / Wednesday, August 11, 2010 / Proposed Rules 

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 

waste does not include used oil, wood 

pellets, construction, renovation, and 

demolition wastes (which includes, but 

is not limited to, railroad ties and 

telephone poles), clean wood, industrial 

process or manufacturing wastes, 

medical waste, or motor vehicles 

(including motor vehicle parts or 

vehicle fluff). Household, commercial/ 

retail, and institutional wastes include 

yard waste, refuse-derived fuel, and 

motor vehicle maintenance materials, 

limited to vehicle batteries and tires, 

except where a single waste stream 

consisting of tires is combusted in a 

unit. 

* * * * * 

Natural gas means a naturally 

occurring mixture of hydrocarbon and 

non-hydrocarbon gases found in 

geologic formations beneath the earth’s 

surface, of which the principal 

constituent is methane. Natural gas may 

be field quality or pipeline quality. 

Natural gas is composed of at least 70 

percent methane by volume or has a 

high heat value between 910 and 1150 

Btu per standard cubic foot. 

Natural gas liquids (NGLs) means 

those hydrocarbons in natural gas that 

are separated from the gas as liquids 

through the process of absorption, 

condensation, adsorption, or other 

methods. Generally, such liquids consist 

of ethane, propane, butanes, and 

pentanes plus. Bulk NGLs refers to 

mixtures of NGLs that are sold or 

delivered as undifferentiated product 

from natural gas processing plants. 

* * * * * 

Primary fuel means the fuel that 

provides the greatest percentage of the 

annual heat input to a stationary fuel 

combustion unit. 

* * * * * 

Solid byproducts means plant matter 

such as vegetable waste, animal 

materials/wastes, and other solid 

biomass, except for wood, wood waste, 

and sulphite lyes (black liquor). 

* * * * * 

Waste oil means a petroleum-derived 

or synthetically-derived oil whose 

physical properties have changed as a 

result of storage, handling or use, such 

that the oil cannot be used for its 

original purpose. Waste oil consists 

primarily of automotive oils (e.g., used 

motor oil, transmission oil, hydraulic 

fluids, brake fluid, etc.) and industrial 

oils (e.g., industrial engine oils, 

metalworking oils, process oils, 

industrial grease, etc). 

* * * * * 

Wood residuals means wood waste 

recovered from three principal sources: 

Municipal solid waste (MSW); 

construction and demolition debris; and 

primary timber processing. Wood 

residuals recovered from MSW include 

wooden furniture, cabinets, pallets and 

containers, scrap lumber (from sources 

other than construction and demolition 

activities), and urban tree and landscape 

residues. Wood residuals from 

construction and demolition debris 

originate from the construction, repair, 

remodeling and demolition of houses 

and non-residential structures. Wood 

residuals from primary timber 

processing include bark, sawmill slabs 

and edgings, sawdust, and peeler log 

cores. Other sources of wood residuals 

include, but are not limited to, railroad 

ties, telephone and utility poles, pier 

and dock timbers, wastewater process 

sludge from paper mills, and logging 

residues. 

* * * * * 

6. Section 98.7 is amended by: 

a. Removing and reserving paragraph 

(b). 

b. Revising paragraphs (d)(1) and 

(d)(2). 

c. Removing and reserving paragraph 

(d)(3). 

d. Revising paragraphs (d)(4) and 

(d)(5). 

e. Removing and reserving paragraph 

(d)(6). 

f. Revising paragraphs (d)(7) and 

(d)(8). 

g. Removing and reserving paragraph 

(d)(9). 

h. Revising paragraph (d)(10). 

i. Removing and reserving paragraph 

(d)(11). 

j. Revising paragraph (e)(4). 

k. Removing and reserving paragraph 

(e)(7). 

l. Revising paragraphs (e)(8), (e)(10), 

(e)(11), (e)(14), (e)(15), (e)(19), (e)(20), 

(e)(24) through (e)(27). 

m. Removing and reserving paragraph 

(e)(28). 

n. Revising paragraph (e)(30), (e)(33), 

and (e)(36). 

o. Adding paragraphs (e)(43) and 

(e)(44). 

p. Removing and reserving paragraph 

(f)(1) and (g)(3). 

q. Revising paragraph (f)(2) 

r. Removing and reserving paragraph 

(g)(3). 

s. Adding paragraph (m)(3). 

§ 98.7 What standardized methods are 

incorporated by reference into this part? 

* * * * * 

(d) * * * 

(1) ASME MFC–3M–2004 

Measurement of Fluid Flow in Pipes 

Using Orifice, Nozzle, and Venturi, 

incorporation by reference (IBR) 

approved for § 98.344(c) and § 98.364(e). 

(2) ASME MFC–4M–1986 (Reaffirmed 

1997) Measurement of Gas Flow by 

Turbine Meters, IBR approved for 

§ 98.344(c) and § 98.364(e). 

(3) [Reserved] 

(4) ASME MFC–6M–1998 

Measurement of Fluid Flow in Pipes 

Using Vortex Flowmeters, IBR approved 

for § 98.344(c) and § 98.364(e). 

(5) ASME MFC–7M–1987 (Reaffirmed 

1992) Measurement of Gas Flow by 

Means of Critical Flow Venturi Nozzles, 

IBR approved for § 98.344(c) and 

§ 98.364(e). 

(6) [Reserved] 

(7) ASME MFC–11M–2006 

Measurement of Fluid Flow by Means of 

Coriolis Mass Flowmeters, IBR 

approved for § 98.344(c). 

(8) ASME MFC–14M–2003 

Measurement of Fluid Flow Using Small 

Bore Precision Orifice Meters, IBR 

approved for § 98.344(c) and § 98.364(e). 

(9) [Reserved] 

(10) ASME MFC–18M–2001 

Measurement of Fluid Flow Using 

Variable Area Meters, IBR approved for 

§ 98.344(c), and § 98.364(e). 

(11) [Reserved] 

(e) * * * 

(4) ASTM D240–02 (Reapproved 

2007) Standard Test Method for Heat of 

Combustion of Liquid Hydrocarbon 

Fuels by Bomb Calorimeter, IBR 

approved for § 98.254(e). 

* * * * * 

(7) [Reserved] 

(8) ASTM D1826–94 (Reapproved 

2003) Standard Test Method for 

Calorific (Heating) Value of Gases in 

Natural Gas Range by Continuous 

Recording Calorimeter, IBR approved 

for § 98.254(e). 

* * * * * 

(10) ASTM D1945–03 Standard Test 

Method for Analysis of Natural Gas by 

Gas Chromatography, IBR approved for 

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

§ 98.254(d), and § 98.344(b). 

(11) ASTM D1946–90 (Reapproved 

2006) Standard Practice for Analysis of 

Reformed Gas by Gas Chromatography, 


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Federal Register / Vol. 75, No. 154 / Wednesday, August 11, 2010 / Proposed Rules 48787 

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

§ 98.254(d), § 98.344(b), and § 98.364(c). 

* * * * * 

(14) ASTM D2502–04 Standard Test 

Method for Estimation of Mean Relative 

Molecular Mass of Petroleum Oils From 

Viscosity Measurements, IBR approved 

for § 98.74(c). 

(15) ASTM D2503–92 (Reapproved 

2007) Standard Test Method for Relative 

Molecular Mass (Molecular Weight) of 

Hydrocarbons by Thermoelectric 

Measurement of Vapor Pressure, IBR 

approved for § 98.74(c). 

* * * * * 

(19) ASTM D3238–95 (Reapproved 

2005) Standard Test Method for 

Calculation of Carbon Distribution and 

Structural Group Analysis of Petroleum 

Oils by the n-d-M Method, IBR 

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

(20) ASTM D3588–98 (Reapproved 

2003) Standard Practice for Calculating 

Heat Value, Compressibility Factor, and 

Relative Density of Gaseous Fuels, IBR 

approved for § 98.254(e). 

* * * * * 

(24) ASTM D4809–06 Standard Test 

Method for Heat of Combustion of 

Liquid Hydrocarbon Fuels by Bomb 

Calorimeter (Precision Method), IBR 

approved for § 98.254(e). 

(25) ASTM D4891–89 (Reapproved 

2006) Standard Test Method for Heating 

Value of Gases in Natural Gas Range by 

Stoichiometric Combustion, IBR 

approved for § 98.254(e). 

(26) ASTM D5291–02 (Reapproved 

2007) Standard Test Methods for 

Instrumental Determination of Carbon, 

Hydrogen, and Nitrogen in Petroleum 

Products and Lubricants, IBR approved 

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

and § 98.254(i). 

(27) ASTM D5373–08 Standard Test 

Methods for Instrumental Determination 

of Carbon, Hydrogen, and Nitrogen in 

Laboratory Samples of Coal, IBR 

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

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

§ 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). 

(28) [Reserved] 

* * * * * 

(30) ASTM D6348–03 Standard Test 

Method for Determination of Gaseous 

Compounds by Extractive Direct 

Interface Fourier Transform Infrared 

(FTIR) Spectroscopy, IBR approved for 

§ 98.54(b),§ 98.224(b), and § 98.414(n). 

* * * * * 

(33) ASTM D6866–08 Standard Test 

Methods for Determining the Biobased 

Content of Solid, Liquid, and Gaseous 

Samples Using Radiocarbon Analysis, 

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

and § 98.36(e). 

* * * * * 

(36) ASTM D7459–08 Standard 

Practice for Collection of Integrated 

Samples for the Speciation of Biomass 

(Biogenic) and Fossil-Derived Carbon 

Dioxide Emitted from Stationary 

Emissions Sources, IBR approved for 

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

* * * * * 

(43) ASTM D2503–92(2007) Standard 

Test Method for Relative Molecular 

Mass (Molecular Weight) of 

Hydrocarbons by Thermoelectric 

Measurement of Vapor Pressure, IBR 

approved for § 98.254(d). 

(44) ASTM D2593–93(2009) Standard 

Test Method for Butadiene Purity and 

Hydrocarbon Impurities by Gas 

Chromatography, IBR approved for 

§ 98.244(b). 

* * * * * 

(f) * * * 

(1) [Reserved] 

(2) GPA 2261–00 Analysis for Natural 

Gas and Similar Gaseous Mixtures by 

Gas Chromatography, IBR approved for 

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

* * * * * 

(g) [Reserved] 

* * * * * 

(k) The following material is available 

from the U.S. Environmental Protection 

Agency, 1200 Pennsylvania Avenue, 

NW, Washington, D.C. 20460, (202) 

272–0167, www.epa.gov. 

(1) Protocol for Measuring Destruction 

or Removal Efficiency (DRE) of 

Fluorinated Greenhouse Gas Abatement 

Equipment in Electronics 

Manufacturing, Version 1, EPA–430–R– 

10–003. 

Subpart C—[Amended] 

7. Section 98.30 is amended by: 

a. Revising paragraph (b)(4). 

b. Revising paragraph (c) introductory 

text. 

c. Adding paragraph (d). 

§ 98.30 Definition of the source category. 

(b) * * * 

(4) Flares, unless otherwise required 

by provisions of another subpart of this 

part to use methodologies in this 

subpart. 

* * * * * 

(c) For a unit that combusts hazardous 

waste (as defined in § 261.3 of this 

chapter), reporting of GHG emissions is 

not required unless either of the 

following conditions apply: 

* * * * * 

(d) You are not required to report 

GHG emissions from pilot lights. A pilot 

light is a small permanent auxiliary 

flame that ignites the burner of a 

combustion device when the control 

valve opens. 

8. Section 98.32 is revised to read as 

follows: 

§ 98.32 GHGs to report. 

You must report CO2, CH4, and N2O 

mass emissions from each stationary 

fuel combustion unit, except as 

otherwise indicated in this subpart. 

9. Section 98.33 is amended by: 

a. Revising paragraphs (a) 

introductory text and (a)(1). 

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

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

c. Revising and the first two sentences 

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

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

the first sentence and the definitions of 

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

C–2b. 

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

f. Revising the definitions of ‘‘CC’’ and 

‘‘MW’’ in Equation C–5 of paragraph 

(a)(3)(iii). 

g. Revising paragraphs (a)(3)(iv), 

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

h. Adding a new paragraph (a)(4)(viii). 

i. Revising paragraphs (a)(5) 

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

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

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

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

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

j. Redesignating paragraph 

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

revising newly designated paragraph 

(a)(5)(iv). 

k. Revising paragraph (b)(1)(iv). 

l. Adding paragraph (b)(1)(v). 

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

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

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

n. Adding paragraph (b)(3)(iv). 

o. Adding a second sentence to 

paragraph (b)(4)(i). 

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

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

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

q. Adding a new paragraph (b)(4)(iv). 

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

third sentence of paragraph (b)(6). 

s. In paragraph (c)(1), revising the 

second sentence, and revising the 

definition of ‘‘HHV’’ in Equation C–8. 

t. Revising the second sentence of 

paragraph (c)(2). 

u. In paragraph (c)(4) introductory 

text, revising the only sentence and 

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

Equation C–10. 

v. Revising paragraphs (c)(4)(i) and 

(c)(4)(ii). 

w. Adding a new paragraph (c)(6). 

x. In paragraph (d)(1), revising the 

first sentence, adding a second sentence, 

and revising the definition of ‘‘R’’ in 

Equation C–11. 


srobinson on DSKHWCL6B1PROD with PROPOSALS2
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y. Revising paragraphs (d)(2), (e) 

introductory text, (e)(1), and (e)(2) 

introductory text. 

z. Revising the definition of ‘‘Fc’’ in 

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

aa. Revising paragraphs (e)(2)(iv), 

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

bb. Reserving paragraph (e)(4). 

cc. Revising the first sentence of 

paragraph (e)(5). 

§ 98.33 Calculating GHG emissions. 

* * * * * 

(a) CO2 emissions from fuel 

combustion. Calculate CO2 mass 

emissions by using one of the four 

calculation methodologies in paragraphs 

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

subject to the applicable conditions, 

requirements, and restrictions set forth 

in paragraph (b) of this section. 

Alternatively, for units that meet the 

conditions of paragraph (a)(5) of this 

section, you may use CO2 mass 

emissions calculation methods from 

part 75 of this chapter, as described in 

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

units that combust both biomass and 

fossil fuels, you must calculate and 

report CO2 emissions from the 

combustion of biomass separately using 

the methods in paragraph (e) of this 

section, except as otherwise provided in 

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

section and in § 98.36(d). 

(1) Tier 1 Calculation Methodology. 

Calculate the annual CO2 mass 

emissions for each type of fuel by using 

Equation C–1 or C–1a of this section (as 

applicable). 

(i) Use Equation C–1 except when 

natural gas billing records are used to 

quantify fuel usage and gas 

consumption is expressed in units of 

therms. In that case, use Equation C–1a. 

CO Fuel HHV EF 2

3 =× ∗ ∗ ∗ 1 10− ( . Eq C-1)

Where: 

CO2 = Annual CO2 mass emissions for the 

specific fuel type (metric tons). 

Fuel = Mass or volume of fuel combusted per 

year, from company records as defined 

in § 98.6 (express mass in short tons for 

solid fuel, volume in standard cubic feet 

for gaseous fuel, and volume in gallons 

for liquid fuel). 

HHV = Default high heat value of the fuel, 

from Table C–1 of this subpart (mmBtu 

per mass or mmBtu per volume, as 

applicable). 

EF = Fuel-specific default CO2 emission 

factor, from Table C–1 of this subpart (kg 

CO2/mmBtu). 

1 × 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. 

CO2 Gas EF 3 =× ∗ ∗ 1 10 [ ] ( ) 1 − 0.1 Eq C a . -

Where: 

CO2 = Annual CO2 mass emissions from 

natural gas combustion (metric tons). 

Gas = Annual natural gas consumption, from 

billing records (therms). 

EF = Fuel-specific default CO2 emission 

factor for natural gas, from Table C–1 of 

this subpart (kg CO2/mmBtu). 

0.1 = Conversion factor from therms to 

mmBtu 

1 × 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’’, 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 be computed as 

the arithmetic average HHV for all 

values for the year (including valid 

samples and substitute data values 

under § 98.35). 

* * * * * 

(3) * * * 

(iii) * * * 

CC = Annual average carbon content of the 

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

annual average carbon content shall be 

determined using the same procedures as 

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

of this section. 

MW = Annual average molecular weight of 

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

annual average molecular weight shall be 

determined using the same procedures as 

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

of this section. 

* * * * * 

(iv) Fuel flow meters that measure 

mass flow rates may be used for liquid 

or gaseous fuels, provided that the fuel 

density is used to convert the readings 

to volumetric flow rates. The density 

shall be measured at the same frequency 

as the carbon content. For liquid fuels, 

you must measure the density using one 

of the following appropriate methods. 

You may use a method published by a 

consensus standards organization, if 

such a method exists, or you may use 

industry standard practice. Consensusbased standards organizations include, 

but are not limited to, the following: 

ASTM International, the American 

National Standards Institute (ANSI), the 

American Gas Association (AGA), the 

American Society of Mechanical 

Engineers (ASME), the American 

Petroleum Institute (API), and the North 

American Energy Standards Board 

(NAESB). The method(s) used shall be 

documented in the Monitoring Plan 

required under § 98.3(g)(5). 

Alternatively, for fuel oil, you may use 


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an applicable default density value 

provided in paragraph (a)(3)(v) of this 

section. For gaseous fuels, you may 

determine the density using any of the 

following methods. You may use a 

density meter calibrated according to 

the manufacturer’s instructions, a 

method published by a consensus 

standards organization, or an industry 

standard practice. Document the 

method used to determine the fuel 

density in the Monitoring Plan under 

§ 98.3(g)(5). 

* * * * * 

(4) * * * 

(iii) If the CO2 concentration is 

measured on a dry basis, a correction for 

the stack gas moisture content is 

required. You shall either continuously 

monitor the stack gas moisture content 

as described in § 75.11(b)(2) of this 

chapter or use an appropriate default 

moisture percentage. For coal, wood, 

and natural gas combustion, you may 

use the default moisture values 

specified in § 75.11(b)(1) of this chapter. 

Alternatively, for any type of fuel, you 

may determine an appropriate 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. 

If this option is selected, 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 

the stack gas moisture content 

associated with different process 

operating conditions. For each sitespecific default moisture percentage, at 

least nine Method 4 runs are required. 

Moisture data from the relative accuracy 

test audit (RATA) of a CEMS may be 

used for this purpose. Calculate each 

site-specific default moisture value by 

taking the arithmetic average of the 

Method 4 runs. Each site-specific 

moisture default value shall be updated 

whenever the owner or operator 

believes the current value is nonrepresentative, due to changes in unit or 

process operation, but in any event no 

less frequently than annually. Use the 

updated moisture value in the 

subsequent CO2 emissions calculations. 

For each unit operating hour, a moisture 

correction must be applied to Equation 

C–6 of this section as follows: 

CO CO H O 2 2

2 100

100

* % = ⎛ −

⎝

⎜ ⎞

⎠

⎟ (Eq. C-7)

Where: 

CO2* = Hourly CO2 mass emission rate, 

corrected for moisture (metric tons/hr). 

CO2 = Hourly CO2 mass emission rate from 

Equation C–6 of this section, uncorrected 

(metric tons/hr). 

%H2O = Hourly moisture percentage in the 

stack gas (measured or default value, as 

appropriate). 

(iv) An oxygen (O2) concentration 

monitor may be used in lieu of a CO2

concentration monitor to determine the 

hourly CO2 concentrations, in 

accordance with Equation F–14a or F– 

14b (as applicable) in appendix F to part 

75 of this chapter, if the effluent gas 

stream monitored by the CEMS consists 

solely of combustion products (i.e., no 

process CO2 emissions or CO2 emissions 

from sorbent are mixed with the 

combustion products) and if only fuels 

that are listed in Table 1 in section 3.3.5 

of appendix F to part 75 of this chapter 

are combusted in the unit. If the O2

monitoring 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, provided that the CO2

concentration in the diverted stream is 

not altered in any way (e.g., by chemical 

reaction or dilution) before the diverted 

stream exits to the atmosphere, an 

estimate of the hourly average 

volumetric flow rate (scfh) of the 

diverted gas stream shall be made at the 

point where it exits the main exhaust 

system, by using the best available 

information (e.g., correlations of 

operating parameters versus flow 

measurements made with EPA Method 

2 in appendix A–2 to part 60 of this 

chapter, engineering analysis, or other 

methods). Each hourly average 

volumetric flow rate (scfh) measured at 

the main flue gas stack shall then be 

added to the corresponding estimate of 

the hourly average flow rate of the 

diverted gas stream, to determine the 

total hourly average stack gas 

volumetric flow rate ‘‘Q’’, for use in 

Equation C–6 of this section. The 

method use to estimate the hourly flow 

rate of the diverted portion of the flue 

gas exhaust stream shall be documented 

in the Monitoring Plan required under 

§ 98.3(g)(5). 

(5) Alternative methods for certain 

units subject to Part 75 of this chapter. 

Certain units that are not subject to 

subpart D of this part and that report 

data to EPA according to part 75 of this 

chapter may qualify to use the 

alternative methods in this paragraph 

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

calculation methodology tiers. 

(i) For a unit that combusts only 

natural gas and/or fuel oil, is not subject 

to subpart D of this part, monitors and 

reports heat input data year-round 

according to appendix D to part 75 of 

this chapter, but is not required by the 

applicable part 75 program to report 

CO2 mass emissions data, calculate the 

annual CO2 mass emissions for the 

purposes of this part as follows: 

(A) Use the hourly heat input data 

from appendix D to part 75 of this 

chapter, together with Equation G–4 in 

appendix G to part 75 of this chapter to 

determine the hourly CO2 mass 

emission rates, in units of tons/hr; 

(B) Use Equations F–12 and F–13 in 

appendix F to part 75 of this chapterto 

calculate the quarterly and cumulative 

annual CO2 mass emissions, 

respectively, in units of short tons; and 

* * * * * 

(ii) For a unit that combusts only 

natural gas and/or fuel oil, is not subject 

to subpart D of this part, monitors and 

reports heat input data year-round 

according to § 75.19 of this chapter but 

is not required by the applicable part 75 

program to report CO2 mass emissions 

data, calculate the annual CO2 mass 

emissions for the purposes of this part 

as follows: 

(A) Calculate the hourly CO2 mass 

emissions, in units of short tons, using 

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

this chapter. 

* * * * * 

(iii) For a unit that is not subject to 

subpart D of this part, uses flow rate and 

CO2 (or O2) CEMS to report heat input 

data year-round according to part 75 of 


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48790 Federal Register / Vol. 75, No. 154 / Wednesday, August 11, 2010 / Proposed Rules 

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. 

(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) and (b)(1)(v) of this 

section. 

(v) May be used for natural gas 

combustion in a unit of any size, in 

cases where the annual natural gas 

consumption is obtained from fuel 

billing records in units of therms. 

(2) * * * 

(ii) May be used in a unit with a 

maximum rated heat input capacity 

greater than 250 mmBtu/hr for the 

combustion of natural gas and/or 

distillate fuel oil. 

* * * * * 

(3) * * * 

(ii) * * * 

(A) The use of Tier 1 or 2 is permitted, 

as described in paragraphs (b)(1)(iii), 

(b)(1)(v), and (b)(2)(ii) of this section. 

* * * * * 

(iii) Shall be used for a fuel not listed 

in Table 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, 

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 all of 

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 

either be monitored at each individual 

unit, or the combined CO2 mass 

emissions may be monitored at the 

common stack or duct. However, if it is 

not feasible to monitor the individual 

units, the combined 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. 


srobinson on DSKHWCL6B1PROD with PROPOSALS2
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(B) No unscheduled maintenance or 

repair of the CEMS is performed during 

the certification test period. 

(iii) No later than 180 days following 

the date on which a change is made that 

triggers Tier 4 applicability under 

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

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

fuel, manner of unit operation, or 

installed continuous monitoring 

equipment). 

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

either the Tier 4 or the alternative 

calculation methodology specified in 

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

emissions from the combustion of all 

fuels shall be based solely on CEMS 

measurements. 

(c) * * * 

(1) * * * Use the same values for fuel 

consumption that you use for the Tier 

1 or Tier 3 calculation. 

* * * * * 

HHV = Default high heat value of the fuel 

from Table C–1 of this subpart; 

alternatively, for Tier 3, if actual HHV 

data are available for the reporting year, 

you may average these data using the 

procedures specified in paragraph 

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

average value in Equation C–8 (mmBtu 

per mass or volume). 

* * * * * 

(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. 

* * * * * 

(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–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 


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does not use CEMS to quantify its 

annual CO2 mass emissions, then, 

pursuant to § 98.33(b)(3)(iii), Tier 3 

must be used to determine the carbon 

content of the biomass fuel and to 

calculate the biogenic CO2 emissions 

from combustion of the fuel. 

Notwithstanding these requirements, 

separate reporting of biogenic CO2

emissions is optional for units subject to 

subpart D of this part and for units that 

use the CO2 mass emissions calculation 

methodologies in part 75 of this chapter, 

pursuant to paragraph (a)(5) of this 

section; however, if the owner or 

operator opts to report biogenic CO2

emissions separately for these units, the 

appropriate method(s) in this paragraph 

(e) shall be used. Separate reporting of 

biogenic CO2 emissions from the 

combustion of tires is also optional, but 

may be reported by following the 

provisons of paragraph (e)(3) of this 

section. 

(1) You may use Equation C–1 of this 

subpart to calculate the annual CO2

mass emissions from the combustion of 

the biomass fuels listed in Table C–1 of 

this subpart (except MSW and tires), in 

a unit of any size, including 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. These procedures 

also may be used for any unit that cofires 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. 

(4) [Reserved] 

(5) If Equation C–1 or Equation C–2a 

of this section is selected to calculate 

the annual biogenic mass emissions for 

wood, wood waste, or other solid 

biomass-derived fuel, Equation C–15 of 

this section may be used to quantify 

biogenic fuel consumption, provided 

that all of the required input parameters 

are accurately quantified. * * * 

* * * * * 

10. Section 98.34 is amended by: 

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

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

introductory text, (b)(1)(i)(A), 

(b)(1)(i)(B), (b)(1)(i)(C), (b)(1)(ii), 

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

(b)(3)(v). 

b. Removing paragraph (b)(4). 

c. Redesignating paragraph (b)(5) as 

(b)(4). 

d. Revising newly designated 

paragraph (b)(4). 

e. Revising paragraphs (c) 

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

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

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

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

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

h. Adding new paragraphs (f)(7) and 

(f)(8). 

i. Removing paragraph (g). 

§ 98.34 Monitoring and QA/QC 

requirements. 

* * * * * 

(a) * * * 

(2) The minimum required frequency 

of the HHV sampling and analysis for 

each type of fuel or fuel mixture (blend) 

is specified in this paragraph. When the 

specified frequency for a particular fuel 

or blend is based on a specified time 

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

half-year), fuel sampling and analysis is 

required only for those time periods in 

which the fuel or blend is combusted. 

The owner or operator may perform fuel 

sampling and analysis more often than 

the minimum required frequency, in 

order to obtain a more representative 

annual average HHV. 

(i) For natural gas, semiannual 

sampling and analysis is required (i.e., 

twice in a calendar year, with 

consecutive samples taken at least four 

months apart). 

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

other solid or liquid fuel that is 

delivered in lots, analysis of at least one 

representative sample from each fuel lot 

is required. For fuel oil, as an alternative 

to sampling each fuel lot, a sample may 

be taken upon each addition of oil to the 

unit’s storage tank. Flow proportional 

sampling, continuous drip sampling, or 

daily manual oil sampling may also be 

used, in lieu of sampling each fuel lot. 

For the purposes of this section, a fuel 

lot is defined as either: 

(A) A shipment or delivery of a single 

fuel (e.g., ship load, barge load, group of 

trucks, group of railroad cars, oil 

delivery via pipeline from a tank farm, 

etc.); or 

(B) If multiple deliveries of a 

particular type of fuel are received from 

the same supply source in a given 

calendar month, the deliveries for that 

month are considered, collectively, to 

comprise a fuel lot, requiring only one 

representative sample. 

(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 


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Federal Register / Vol. 75, No. 154 / Wednesday, August 11, 2010 / Proposed Rules 48793 

practicable, consecutive quarterly 

samples shall be taken at least 30 days 

apart. 

(iv) For other solid fuels (except 

MSW), weekly sampling is required to 

obtain composite samples, which are 

then analyzed monthly. 

(v) For fuel blends that are received 

already mixed, as described in 

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

determine the HHV of the blend as 

follows. For blends of solid fuels (except 

MSW), weekly sampling is required to 

obtain composite samples, which are 

analyzed monthly. For blends of liquid 

or gaseous fuels, sampling and analysis 

is required at least once per calendar 

quarter. More frequent sampling is 

recommended if the composition of the 

blend varies significantly during the 

year. 

(3) Special Considerations for 

Blending of Fuels. In situations where 

different types of fuel listed in Table 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), 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. 

EF

HHV Fuel EF

HHV B

i ii i

n

B

( ) =

⎡( )( )( ) ⎣ ⎤

⎦

( ) ( )

∑ % 

Eq. C-16 =1

Where: 

(EF)B = Heat-weighted CO2 emission factor 

for the blend (kg CO2/mmBtu) 

(HHV)I = Default high heat value for fuel ‘‘i’’ 

in the blend, from Table C–1 (mmBtu per 

mass or volume) 

(%Fuel)I = Estimated mass or volume 

percentage of fuel ‘‘i’’ (mass % or volume 

%, as applicable, expressed as a decimal 

fraction; e.g., 25% = 0.25) 

(EF)I = Default CO2 emission factor for fuel 

‘‘i’’ from Table C–1 (mmBtu per mass or 

volume) 

(HHV)B = Annual average high heat value for 

the blend, calculated according to 

§ 98.33(a)(2)(ii) (mmBtu per mass or 

volume) 

(iii) Note that for the case described 

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

measured HHV values for the 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. 

HHV HHV Fuel B i i i=

n ∗ = ⎡( )( ) ⎣ ⎤

⎦ ∑ % ( ) Eq. C-17

1

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, 


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48794 Federal Register / Vol. 75, No. 154 / Wednesday, August 11, 2010 / Proposed Rules 

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. You may use a method 

published by a consensus standards 

organization if such a method exists, or 

you may use industry consensus 

standard practice to determine the high 

heat values. Consensus-based standards 

organizations include, but are not 

limited to, the following: ASTM 

International, the American National 

Standards Institute (ANSI), the 

American Gas Association (AGA), the 

American Society of Mechanical 

Engineers (ASME), the American 

Petroleum Institute (API), and the North 

American Energy Standards Board 

(NAESB). Alternatively, for gaseous 

fuels, the HHV may be calculated using 

chromatographic analysis together with 

standard heating values of the fuel 

constituents, provided that the gas 

chromatograph is operated, maintained, 

and calibrated according to the 

manufacturer’s instructions. The 

method(s) used shall be documented in 

the Monitoring Plan required under 

§ 98.3(g)(5). 

(b) * * * 

(1) You must calibrate each oil and 

gas flow meter according to § 98.3(i) and 

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

(i) Perform calibrations using any of 

the test methods and procedures in this 

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

shall be documented in the Monitoring 

Plan required under § 98.3(g)(5). 

(A) You may use an appropriate flow 

meter calibration method published by 

a consensus standards organization, if 

such a method exists. Consensus-based 

standards organizations include, but are 

not limited to, the following: ASTM 

International, the American National 

Standards Institute (ANSI), the 

American Gas Association (AGA), the 

American Society of Mechanical 

Engineers (ASME), the American 

Petroleum Institute (API), and the North 

American Energy Standards Board 

(NAESB). 

(B) You may use the calibration 

procedures specified by the flow meter 

manufacturer. 

(C) You may use an industry-accepted 

or industry consensus standard 

calibration practice. 

(ii) In addition to the initial 

calibration required by § 98.3(i), 

recalibrate each fuel flow meter (except 

as otherwise provided in paragraph 

(b)(1)(iii) of this section) either 

annually, at the minimum frequency 

specified by the manufacturer, or at the 

interval specified by industry consensus 

standard practice. 

(iii) Fuel billing meters are exempted 

from the initial and ongoing calibration 

requirements of this paragraph and from 

the Monitoring Plan and recordkeeping 

requirements of § 98.3(g)(5)(i)(C) and 

(g)(7), provided that the fuel supplier 

and the unit combusting the fuel do not 

have any common owners and are not 

owned by subsidiaries or affiliates of the 

same company. Meters used exclusively 

to measure the flow rates of fuels that 

are only used for unit startup or ignition 

are also exempted from the initial and 

ongoing calibration requirements of this 

paragraph. 

* * * * * 

(vi) If a mixture of liquid or gaseous 

fuels is transported by a common pipe, 

you may either separately meter each of 

the fuels prior to mixing, using flow 

meters calibrated according to § 98.3(i), 

or consider the fuel mixture to be the 

‘‘fuel type’’ and meter the mixed fuel, 

using a flow meter calibrated according 

to § 98.3(i). 

* * * * * 

(3) * * * 

(ii) For each type of fuel, the 

minimum required frequency for 

collecting and analyzing samples for 

carbon content and (if applicable) 

molecular weight is specified 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. 

For the purposes of this section, a fuel 

lot is defined as either of the following: 

(1) A shipment or delivery of a single 

fuel (e.g., ship load, barge load, group of 

trucks, group of railroad cars, oil 

delivery via pipeline from a tank farm, 

etc.). 

(2) If multiple deliveries of a 

particular type of fuel are received from 

the same supply source in a given 

calendar month, the deliveries for that 

month are considered, collectively, to 

comprise a fuel lot, requiring only one 

representative sample. 

(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 


srobinson on DSKHWCL6B1PROD with PROPOSALS2
Federal Register / Vol. 75, No. 154 / Wednesday, August 11, 2010 / Proposed Rules 48795 

in paragraph (b)(3)(ii)(F) of this section, 

measure the carbon content and, if 

applicable, the molecular weight of the 

blend and calculate the annual average 

value of each parameter in the manner 

described in § 98.33(a)(2)(ii). Also 

measure the mass or volume of the 

blended fuel combusted during the 

reporting year. Substitute these 

measured values into Equation C–3, C– 

4, or C–5 of this subpart (as applicable). 

(4) You must use one of the following 

appropriate fuel sampling and analysis 

methods. You may use a method 

published by a consensus standards 

organization if such a method exists, or 

you may use industry consensus 

standard practice to determine the 

carbon content and molecular weight 

(for gaseous fuel) of the fuel. Consensusbased standards organizations include, 

but are not limited to, the following: 

ASTM International, the American 

National Standards Institute (ANSI), the 

American Gas Association (AGA), the 

American Society of Mechanical 

Engineers (ASME), the American 

Petroleum Institute (API), and the North 

American Energy Standards Board 

(NAESB). Alternatively, the results of 

chromatographic analysis of the fuel 

may be used, provided that the gas 

chromatograph is operated, maintained, 

and calibrated according to the 

manufacturer’s instructions. The 

method(s) used shall be documented in 

the Monitoring Plan required under 

§ 98.3(g)(5). 

(c) For the Tier 4 Calculation 

Methodology, the CO2, flow rate, and (if 

applicable) moisture monitors must be 

certified prior to the applicable deadline 

specified in § 98.33(b)(5). 

(1) * * * 

(i) Sections 75.20(c)(2), (c)(4), and 

(c)(5) 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) When municipal solid waste 

(MSW) is either the primary fuel 

combusted in a unit or the only fuel 

with a biogenic component combusted 

in the unit, determine the biogenic 

portion of the CO2 emissions using 

ASTM D6866–08 Standard Test 

Methods for Determining the Biobased 

Content of Solid, Liquid, and Gaseous 

Samples Using Radiocarbon Analysis 

(incorporated by reference, see § 98.7) 

and ASTM D7459–08 Standard Practice 

for Collection of Integrated Samples for 

the Speciation of Biomass (Biogenic) 

and Fossil-Derived Carbon Dioxide 

Emitted from Stationary Emissions 

Sources (incorporated by reference, see 

§ 98.7). Perform the ASTM D7459–08 

sampling and the ASTM D6866–08 

analysis at least once in every calendar 

quarter in which MSW is combusted in 

the unit. Collect each gas sample during 

normal unit operating conditions for at 

least 24 consecutive hours or for as long 

as is deemed necessary to obtain a 

representative sample. One suggested 

alternative sampling approach would be 

to collect an integrated sample by 

extracting a small amount of flue gas 

(e.g., 1 to 5 cc) in each unit operating 

hour during the quarter. Separate the 

total annual CO2 emissions into the 

biogenic and 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 and 

ASTM D7459–08 may be used to 

determine the biogenic portion of the 

CO2 emissions. Perform the ASTM 

D7459–08 sampling and the ASTM 

D6866–08 analysis in every calendar 

quarter in which biomass and nonbiogenic fuels are co-fired in the unit. 

Collect each gas sample using ASTM 

D7459–08 during normal unit operation 

for at least 24 consecutive hours or for 

as long as is necessary to obtain a 

representative sample. If the types of 

fuels combusted in the unit and their 

relative proportions are not consistent 

throughout the quarter, more frequent, 

periodic sampling of the flue gas should 

be considered. For example, an 

integrated sample could be collected by 

extracting a small amount of the flue gas 

(e.g., 1 to 5 cc) in each unit operating 

hour of the quarter. If the primary fuel 

for multiple units at the 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 


srobinson on DSKHWCL6B1PROD with PROPOSALS2
48796 Federal Register / Vol. 75, No. 154 / Wednesday, August 11, 2010 / Proposed Rules 

are used, including cases where 

§ 98.36(c)(4) applies. 

* * * * * 

(3) Fossil fuel consumption when 

§ 98.33(e)(2) applies to a unit that uses 

CEMS to quantify CO2 emissions and 

that combusts both fossil and biomass 

fuels. 

* * * * * 

(5) Quantity of steam generated by a 

unit when § 98.33(a)(2)(iii) applies. 

* * * * * 

(7) Fuel usage for CH4 and N2O 

emissions calculations under 

§ 98.33(c)(4)(ii). 

(8) Mass of biomass combusted, for 

premixed fuels that contain biomass and 

fossil fuels under § 98.33(e)(1)(iii). 

11. Section 98.35 is amended by 

revising paragraph (a) to read as follows: 

§ 98.35 Procedures for estimating missing 

data. 

* * * * * 

(a) For all units subject to the 

requirements of the Acid Rain Program, 

and all other stationary combustion 

units subject to the requirements of this 

part that monitor and report emissions 

and heat input data in accordance with 

part 75 of this chapter, the missing data 

substitution procedures in part 75 of 

this chapter shall be followed for CO2

concentration, stack gas flow rate, fuel 

flow rate, high heating value, and fuel 

carbon content. 

* * * * * 

12. Section 98.36 is amended by: 

a. Revising paragraph (b)(5). 

b. Removing paragraphs (b)(9) and 

(b)(10). 

c. Redesignating paragraphs (b)(6) 

through (b)(8) as paragraphs (b)(8) 

through (b)(10), respectively. 

d. Revising newly designated 

paragraphs (b)(8) and (b)(9). 

e. Adding new paragraphs (b)(6) and 

(b)(7). 

f. Revising paragraphs (c)(1)(ii), 

(c)(1)(vi), and (c)(1)(vii). 

g. Redesignating paragraph (c)(1)(viii) 

as paragraph (c)(1)(x), and revising 

newly designated paragraph (c)(1)(x). 

h. Removing paragraph (c)(1)(ix). 

i. Adding new paragraphs (c)(1)(viii) 

and (c)(1)(ix). 

j. Revising paragraphs (c)(2) 

introductory text, (c)(2)(ii), (c)(2)(iii), 

and (c)(2)(v). 

k. Removing paragraph (c)(2)(viii). 

l. Redesignating paragraphs (c)(2)(vi) 

and (c)(2)(vii) as paragraphs (c)(2)(viii) 

and (c)(2)(ix), and revising newly 

designated paragraphs (c)(2)(viii) and 

(c)(2)(ix). 

m. Adding new paragraphs (c)(2)(vi) 

and (c)(2)(vii). 

n. Revising paragraphs (c)(3) 

introductory text, (c)(3)(ii), (c)(3)(iii), 

and (c)(3)(vii). 

o. Removing paragraph (c)(3)(viii). 

p. Adding new paragraphs (c)(3)(viii), 

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

q. Revising paragraph (d). 

r. Revising paragraphs (e)(1)(iii), 

(e)(2)(i), (e)(2)(ii)(C), (e)(2)(ii)(D), 

(e)(2)(iii), and (e)(2)(iv)(A), (e)(2)(iv)(C). 

s. Adding new paragraphs (e)(2)(iv)(F) 

and (e)(2)(v)(E). 

t. Revising paragraphs (e)(2)(vii)(A), 

(e)(2)(ix) introductory text, and (e)(2)(x) 

introductory text. 

u. Removing paragraphs (e)(2)(x)(B) 

and (e)(2)(x)(C). 

v. Redesignating paragraph 

(e)(2)(x)(D) as (e)(2)(x)(B), and revising 

newly designated paragraph (e)(2)(x)(B). 

w. Revising paragraph (e)(2)(xi). 

§ 98.36 Data reporting requirements. 

* * * * * 

(b) * * * 

(5) The methodology (i.e., tier) used to 

calculate the CO2 emissions for each 

type of fuel combusted (i.e., Tier 1, 2, 3, 

or 4). 

(6) The methodology start date, for 

each fuel type. 

(7) The methodology end date, for 

each fuel type. 

(8) For a unit that uses Tiers 1, 2, or 

3: 

(i) The annual CO2 mass emissions 

(including biogenic CO2), and the 

annual CH4, and N2O mass emissions 

for each type of fuel combusted during 

the reporting year, expressed in metric 

tons of each gas and in metric tons of 

CO2e; and 

(ii) Metric tons of biogenic CO2

emissions (if applicable). 

(9) For a unit that uses Tier 4: 

(i) If the total annual CO2 mass 

emissions measured by the CEMS 

consists entirely of non-biogenic CO2

(i.e., CO2 from fossil fuel combustion 

plus, if applicable, CO2 from sorbent 

and/or process CO2), report the total 

annual CO2 mass emissions, expressed 

in metric tons. You are not required to 

report the combustion CO2 emissions by 

fuel type. 

(ii) If the total annual CO2 mass 

emissions measured by the CEMS 

includes both biogenic and nonbiogenic CO2, separately report the 

annual non-biogenic CO2 mass 

emissions and the annual CO2 mass 

emissions from biomass combustion, 

each expressed in metric tons. You are 

not required to report the combustion 

CO2 emissions by fuel type. 

(iii) An estimate of the heat input 

from each type of fuel listed in Table C– 

2 of this subpart that was combusted in 

the unit during the report year, and the 

annual CH4 and N2O emissions for each 

of these fuels, expressed in metric tons 

of each gas and in metric tons of CO2e. 

* * * * * 

(c) * * * 

(1) * * * 

(ii) The number of units in the group. 

* * * * * 

(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 both 

combustion products and process offgases, and all of the effluent comes from 

a single unit (e.g., a furnace, kiln, or 

smelter). 

(iii) Combined maximum rated heat 

input capacity of the units sharing the 


srobinson on DSKHWCL6B1PROD with PROPOSALS2
Federal Register / Vol. 75, No. 154 / Wednesday, August 11, 2010 / Proposed Rules 48797 

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 

this subpart that was combusted during 

the report year in the units sharing the 

common stack or duct during the report 

year, and, for each of these fuels, the 

annual CH4 and N2O mass emissions 

from the units sharing the common 

stack or duct, expressed in metric tons 

of each gas and in metric tons of CO2e. 

(3) Common pipe configurations. 

When two or more liquid-fired or 

gaseous-fired stationary combustion 

units at a facility combust the same type 

of fuel and the fuel is fed to the 

individual units through a common 

supply line or pipe, you may report the 

combined emissions from the units 

served by the common supply line, in 

lieu of separately reporting the GHG 

emissions from the individual units, 

provided that the total amount of fuel 

combusted by the units is accurately 

measured at the common pipe or supply 

line using a fuel flow meter. For Tier 3 

applications, the flow meter shall be 

calibrated in accordance with § 98.34(b). 

If a portion of the fuel measured at the 

main supply line is diverted to either: 

A flare; or another stationary fuel 

combustion unit (or units), including 

units that use a CO2 mass emissions 

calculation method in part 75 of this 

chapter; or a chemical or industrial 

process (where it is used as a raw 

material but not combusted), and the 

remainder of the fuel is distributed to a 

group of combustion units for which 

you elect to use the common pipe 

reporting option, you may use company 

records to subtract out the diverted 

portion of the fuel from the fuel 

measured at the main supply line prior 

to performing the GHG emissions 

calculations for the group of units using 

the common pipe option. If the diverted 

portion of the fuel is combusted, the 

GHG emissions from the diverted 

portion shall be accounted for in 

accordance with the applicable 

provisions of this part. When the 

common pipe option is selected, the 

applicable tier shall be used based on 

the maximum rated heat input capacity 

of the largest unit served by the 

common pipe configuration, except 

where the applicable tier is based on 

criteria other than unit size. For 

example, if the maximum rated heat 

input capacity of the largest unit is 

greater than 250 mmBtu/hr, Tier 3 will 

apply, unless the fuel transported 

through the common pipe is natural gas 

or distillate oil, in which case Tier 2 

may be used, in accordance with 

§ 98.33(b)(2)(ii). As a second example, 

in accordance with § 98.33(b)(1)(v), Tier 

1 may be used regardless of unit size 

when natural gas is transported through 

the common pipe, if the annual fuel 

consumption is obtained from gas 

billing records in units of therms. When 

the common pipe reporting option is 

selected, the following information shall 

be reported instead of the information in 

paragraph (b) of this section: 

* * * * * 

(ii) The number of units served by the 

common pipe. 

(iii) The highest maximum rated heat 

input capacity of any unit served by the 

common pipe (mmBtu/hr). 

* * * * * 

(vii) Annual CO2 mass emissions and 

annual CH4 and N2O emissions from 

each fuel type for the units served by 

the common pipe, expressed in metric 

tons of each gas and in metric tons of 

CO2e. 

(viii) Methodology start date. 

(ix) Methodology end date. 

(4) The following alternative reporting 

option applies to situations where a 

common liquid or gaseous fuel supply 

is shared between one or more large 

combustion units, such as boilers or 

combustion turbines (including units 

subject to subpart D of this part); and 

small combustion sources on-site, 

including but not limited to space 

heaters and hot water heaters. In this 

case, you may simplify reporting by 

attributing all of the GHG emissions 

from combustion of the shared fuel to 

the large combustion unit(s), provided 

that: 

(i) The total quantity of the fuel 

combusted during the report year in the 

units sharing the fuel supply is 

measured, either at the ‘‘gate’’ to the 

facility or at a point inside the facility, 

using a fuel flow meter, billing meter, or 

tank drop measurements (as applicable); 

(ii) On an annual basis, at least 95 

percent (by mass or volume) of the 

shared fuel is combusted in the large 

combustion unit(s), and the remainder 

is combusted in the small combustion 

sources. Company records may be used 

to determine the percentage distribution 

of the shared fuel to the large and small 

units; and 

(iii) The use of this reporting option 

is documented in the Monitoring Plan 

required under § 98.3(g)(5). Indicate in 

the Monitoring Plan which units share 

the common fuel supply and the 

method used to demonstrate that this 

alternative reporting option applies. For 

the small combustion sources on-site, a 

description of the types of units and the 

approximate number of units is 

sufficient. 

(d) Units subject to part 75 of this 

chapter. 

(1) For stationary combustion units 

that are subject to subpart D of this part, 

you shall report the following unit-level 

information: 

(i) Unit or stack identification 

numbers. Use exact same unit, common 

stack, common pipe, or multiple stack 

identification numbers that represent 

the monitored locations (e.g., 1, 2, 

CS001, MS1A, CP001, etc.) that are 

reported under § 75.64 of this chapter. 

(ii) Annual CO2 emissions at each 

monitored location, expressed in both 

short tons and metric tons. Reporting of 

biogenic CO2 emissions under 

§ 98.3(c)(4)(ii) and § 98.3(c)(4)(iii)(A) is 

optional. Subpart D units are not 

required to report biogenic CO2

emissions under §§ 98.3(c)(4)(ii) and 

(c)(4)(iii)(A). 

(iii) Annual CH4 and N2O emissions at 

each monitored location, for each fuel 

type listed in Table C–2 that was 

combusted during the year (except as 

otherwise provided in 

§ 98.33(c)(4)(ii)(B)), expressed in metric 

tons of CO2e. 

(iv) The total heat input from each 

fuel listed in Table C–2 that was 

combusted during the year (except as 

otherwise provided in 

§ 98.33(c)(4)(ii)(B)), expressed in 

mmBtu. 

(v) Identification of the Part 75 

methodology used to determine the CO2

mass emissions. 

(vi) Methodology start date. 

(vii) Methodology end date. 

(viii) Acid Rain Program indicator. 

(ix) Annual CO2 mass emissions from 

the combustion of biomass, expressed in 

metric tons of CO2e (optional). 

(2) For units that use the alternative 

CO2 mass emissions calculation 

methods provided in § 98.33(a)(5), you 

shall report the following unit-level 

information: 

(i) Unit, stack, or pipe ID numbers. 

Use exact same unit, common stack, 


srobinson on DSKHWCL6B1PROD with PROPOSALS2
48798 Federal Register / Vol. 75, No. 154 / Wednesday, August 11, 2010 / Proposed Rules 

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. 

(E) A code or flag to indicate whether 

heat input is calculated according to 

appendix D to part 75 of this chapter or 

§ 75.19 of this chapter. 

(F) Annual CO2 emissions at each 

monitored location, across all fuel types, 

expressed in metric tons of CO2e. 

(G) Annual heat input from each type 

of fuel listed in Table C–2 of this 

subpart that was combusted during the 

reporting year, expressed in mmBtu. 

(H) Annual CH4 and N2O emisions at 

each monitored location, from each fuel 

type listed in Table C–2 of this subpart 

that was combusted during the reporting 

year (except as otherwise provided in 

§ 98.33(c)(4)(ii)(D)), expressed in metric 

tons CO2e. 

(I) Annual CO2 mass emissions from 

the combustion of biomass, expressed in 

metric tons CO2e (optional). 

(iii) For units with continuous 

monitoring systems that use the 

alternative method for units with 

continuous monitoring systems in 

§ 98.33(a)(5)(iii) to monitor heat input 

year-round according to part 75 of this 

chapter: 

(A) Each type of fuel combusted 

during the reporting year. 

(B) Methodology used to calculate the 

CO2 mass emissions. 

(C) Methodology start date. 

(D) Methodology end date. 

(E) A code or flag to indicate that the 

heat input data is derived from CEMS 

measurements. 

(F) The total annual CO2 emissions at 

each monitored location, expressed in 

metric tons of CO2e. 

(G) Annual heat input from each type 

of fuel listed in Table C–2 of this 

subpart that was combusted during the 

reporting year, expressed in mmBtu. 

(H) Annual CH4 and N2O emisions at 

each monitored location, from each fuel 

type listed in Table C–2 of this subpart 

that was combusted during the reporting 

year (except as otherwise provided in 

§ 98.33(c)(4)(ii)(B)), expressed in metric 

tons CO2e. 

(I) Annual CO2 mass emissions from 

the combustion of biomass, expressed in 

metric tons CO2e (optional). 

(e) * * * 

(1) * * * 

(iii) Are not in the Acid Rain Program, 

but are required to monitor and report 

CO2 mass emissions and heat input data 

year-round, in accordance with part 75 

of this chapter. 

(2) * * * 

(i) For the Tier 1 Calculation 

Methodology, report the total quantity 

of each type of fuel combusted in the 

unit or group of aggregated units (as 

applicable) during the reporting year, in 

short tons for solid fuels, gallons for 

liquid fuels and standard cubic feet or, 

if applicable, therms for gaseous fuels. 

(ii) * * * 

(C) The high heat values used in the 

CO2 emissions calculations for each 

type of fuel combusted during the 

reporting year, in mmBtu per short ton 

for solid fuels, mmBtu per gallon for 

liquid fuels, and mmBtu per scf for 

gaseous fuels. Report a HHV value for 

each calendar month in which HHV 

determination is required. If multiple 

values are obtained in a given month, 

report the arithmetic average value for 

the month. Indicate whether each 

reported HHV is a measured value or a 

substitute data value. 

(D) If Equation C–2c of this subpart is 

used to calculate CO2 mass emissions, 

report the total quantity (i.e., pounds) of 

steam produced from MSW or solid fuel 

combustion during each month of the 

reporting year, and the 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). 

(v) * * * 

(E) The date on which each fuel 

sample was taken, except where fuel 

sampling data are received from the fuel 

supplier. In that case, keep records of 

the dates on which the results of the 

fuel analyses for carbon content and (if 

applicable) molecular weight are 

received. 

* * * * * 

(vii) * * * 

(A) Whether the CEMS certification 

and quality assurance procedures of part 

75 of this chapter, part 60 of this 

chapter, or an applicable State 

continuous monitoring program were 

used. 

* * * * * 

(ix) For units that combust both fossil 

fuel and biomass, when biogenic CO2 is 

determined according to § 98.33(e)(2), 

you shall report the following additional 

information, as applicable: 

* * * * * 

(x) When ASTM methods D7459–08 

and D6866–08 are used to determine the 

biogenic portion of the annual CO2

emissions from MSW combustion, as 

described in § 98.34(d), report: 

* * * * * 

(B) The annual biogenic CO2 mass 

emissions from MSW combustion, in 

metric tons. 

(xi) When ASTM methods D7459–08 

and D6866–08 are used in accordance 

with § 98.34(e) to determine the 

biogenic portion of the annual CO2

emissions from a unit that 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 of Supart C of Part 98 

is amended by: 


srobinson on DSKHWCL6B1PROD with PROPOSALS2
Federal Register / Vol. 75, No. 154 / Wednesday, August 11, 2010 / Proposed Rules 48799 

a. Revising the title to read ‘‘Table C– 

1 to Subpart C—Default CO2 Emission 

Factors and High Heat Values for 

Various Types of Fuel.’’ 

b. Revising the entry for ‘‘Pipeline 

(Weighted U.S. Average).’’ 

c. Removing the entry for ‘‘Still Gas.’’ 

d. Adding an entry for ‘‘Waste Oil’’ to 

follow the entry for ‘‘Residual Fuel Oil 

No. 6.’’ 

e. Adding an entry for ‘‘Ethanol’’ to 

follow the entry for ‘‘Ethane.’’ 

f. Revising the entry for ‘‘Fossil fuelderived fuels (solid).’’ 

g. Revising the entry for ‘‘Municipal 

Solid Waste.’’ 

h. Adding entries for ‘‘Plastics’’ and 

‘‘Petroleum Coke’’ to follow the entry for 

‘‘Tires.’’ 

i. Revising the entry for ‘‘Fossil fuelderived fuels (gaseous).’’ 

j. Adding entries for ‘‘Propane Gas’’ 

and ‘‘Fuel Gas’’ to follow the entry for 

‘‘Coke Oven Gas.’’ 

k. Revising the entry for ‘‘Biomass 

fuels—solid.’’ 

l. Revising the entry for ‘‘Biomass 

fuels—liquid’’ by centering ‘‘Biomass 

fuels—liquid.’’ 

m. Revising the entries for ‘‘Ethanol’’ 

and ‘‘Biodiesel’’ that follow the entry for 

‘‘Biomass fuels—liquid.’’ 

n. Revising footnote ‘‘1.’’ 

o. Adding a new footnote ‘‘2.’’ 

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. 

* * * * * * * 

Waste Oil .................................................................................................................... 0.135 ........................................................ 74.00. 

* * * * * * * 

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. 

Biomass fuels—solid .................................................................................................. mmBtu/short ton ...................................... kg CO2/mmBtu. 

* * * * * * * 

Ethanol ........................................................................................................................ 0.084 ........................................................ 68.44. 

Biodiesel ..................................................................................................................... 0.128 ........................................................ 73.84. 

*******

1 Use of this default HHV is allowed only for units that combust MSW, do not generate steam, and are allowed to use Tier 1. 

2 Reporters subject to subpart X of this part that are complying with § 98.243(d) or subpart Y of this part may only use the default HHV and the 

default CO2 emission factor for fuel gas combustion under the conditions prescribed in § 98.243(d)(2)(i) and (d)(2)(ii) and § 98.252(a)(1) and 

(a)(2), respectively. Otherwise, Tier 3 (Equation C–5) or Tier 4 must be used. 

14. The first Table C–2 is removed, 

and the second Table C–2 is revised to 

read as follows: 

TABLE C–2 TO SUBPART C—DEFAULT CH4 AND N2O EMISSION FACTORS FOR VARIOUS TYPES OF FUEL

Fuel type 

Default CH4 emission 

factor 

kg CH4/mmBtu) 

Default N2O emission 

factor 

kg N2O/mmBtu) 

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 PROPOSALS2
48800 Federal Register / Vol. 75, No. 154 / Wednesday, August 11, 2010 / Proposed Rules 

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 1 g of CH4/MMBtu. 

Subpart D—[Amended] 

15. Section 98.40 is amended by 

revising paragraph (a) to read as follows: 

§ 98.40 Definition of the source category. 

(a) The electricity generation source 

category comprises electricity 

generating units that are subject to the 

requirements of the Acid Rain Program 

and any other electricity generating 

units that are required to monitor and 

report to EPA CO2 mass emissions yearround according to 40 CFR part 75. 

* * * * * 

16. 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). 

17. Section 98.47 is revised to read as 

follows: 

§ 98.47 Records that must be retained. 

You shall comply with the 

recordkeeping requirements of 

§§ 98.3(g) and 98.37. Records retained 

under § 75.57(h) of this chapter for 

missing data events satisfy the 

recordkeeping requirements of 

§ 98.3(g)(4) for those same events. 

Subpart F—[Amended] 

18. Section 98.62 is amended by 

revising paragraphs (a) and (b) to read 

as follows: 

§ 98.62 GHGs to report. 

* * * * * 

(a) Perfluoromethane (CF4), and 

perfluoroethane (C2F6) emissions from 

anode effects in all prebake and 

S<derberg electrolysis cells. 

(b) CO2 emissions from anode 

consumption during electrolysis in all 

prebake and S<derberg electrolysis cells. 

* * * * * 

19. Section 98.63 is amended by: 

a. In paragraph (a), revising the only 

sentence and the definitions of ‘‘EPFC,’’ 

and ‘‘Em’’ in Equation F–1. 

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. 

* * * * * 

20. Section 98.64 is amended by 

revising the first sentence of paragraph 

(a); and by revising paragraph (b) to read 

as follows: 

§ 98.64 Monitoring and QA/QC 

requirements. 

(a) Effective one year after publication 

of the rule for smelters with no prior 

measurement or effective three years 

after publication for facilities with 

historic measurements, the smelterspecific slope coefficients, overvoltage 

emission factors, and weight fractions 

used in Equations F–2, F–3, and F–4 of 

this subpart must be measured in 

accordance with the recommendations 

of the EPA/IAI Protocol for 

Measurement of Tetrafluoromethane 

(CF4) and Hexafluoroethane (C2F6) 

Emissions from Primary Aluminum 

Production (2008), except the minimum 

frequency of measurement shall be 

every 10 years unless a change occurs in 

the control algorithm that affects the 

mix of types of anode effects or the 

nature of the anode effect termination 

routine. * * * 

(b) The minimum frequency of the 

measurement and analysis is annually 

except as follows: 

(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. 

* * * * * 

21. Section 98.65 is amended by 

revising the only sentence of paragraph 

(a) to read as follows: 

§ 98.65 Procedures for estimating missing 

data. 

* * * * * 

(a) Where anode or paste 

consumption data are missing, CO2

emissions can be estimated from 

aluminum production per Equation F–8 

of this section. 

* * * * * 

22. Section 98.66 is amended by 

revising paragraph (c)(1) to read as 

follows: 

§ 98.66 Data reporting requirements. 

* * * * * 

(c) * * * 

(1) Perfluoromethane emissions and 

perfluoroethane emissions from anode 

effects in all prebake and all S<derberg 

electrolysis cells combined. 

* * * * * 

23. In the table to Supart F of Part 98, 

revise Table F–1 to read as follows: 


srobinson on DSKHWCL6B1PROD with PROPOSALS2
Federal Register / Vol. 75, No. 154 / Wednesday, August 11, 2010 / Proposed Rules 48801 

TABLE F–1 TO SUBPART F—SLOPE AND OVERVOLTAGE COEFFICIENTS FOR THE CALCULATION OF PFC EMISSIONS FROM

ALUMINUM PRODUCTION

Technology 

CF4 slope 

coefficient 

[(kg CF4/metric ton 

Al)/(AE–Mins/cellday)] 

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 

24. Table F–2 is amended by revising 

the entry for ‘‘CO2 Emissions from Pitch 

Volatiles Combustion (VSS and HSS)’’ to 

read as follows: 

TABLE F–2 TO SUBPART F—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] 

25. 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). 

* * * * * 

26. Section 98.73 is amended by: 

a. Revising paragraph (b) introductory 

text. 

b. Revising the definition of ‘‘CO2,G’’ in 

Equation G–1 of paragraph (b)(1). 

c. Revising the definition of ‘‘CO2,L’’ in 

Equation G–2 of paragraph (b)(2). 

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)). 

* * * * * 

27. Section 98.74 is amended by 

revising paragraph (d) and by removing 

and reserving paragraph (f) to read as 

follows: 

§ 98.74 Monitoring and QA/QC 

requirements. 

* * * * * 

(d) Calibrate all oil and gas flow 

meters that are used to measure liquid 

and gaseous feedstock volumes and flow 

rates (except for gas billing meters) 

according to the monitoring and QA/QC 

requirements for the Tier 3 methodology 

in § 98.34(b)(1). Perform oil tank drop 

measurements (if used to quantify 

feedstock volumes) according to 

§ 98.34(b)(2). 

* * * * * 

28. Section 98.75 is amended by 

revising the first sentence of paragraph 

(a); and by revising paragraph (b) to read 

as follows: 

§ 98.75 Procedures for estimating missing 

data. 

* * * * * 

(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. * * * 


srobinson on DSKHWCL6B1PROD with PROPOSALS2
48802 Federal Register / Vol. 75, No. 154 / Wednesday, August 11, 2010 / Proposed Rules 

(b) For missing feedstock supply rates 

used to determine monthly feedstock 

consumption, you must determine the 

best available estimate(s) of the 

parameter(s), based on all available 

process data. 

29. Section 98.76 is amended by: 

a. Revising paragraphs (a) 

introductory text and (b)(6). 

b. Removing paragraphs (b)(12) 

through (b)(15). 

c. Redesignating paragraph (b)(16) as 

paragraph (b)(12). 

c. Adding a new paragraph (b)(13). 

d. Removing paragraphs (b)(17) and 

(c). 

§ 98.76 Data reporting requirements. 

* * * * * 

(a) If a CEMS is used to measure CO2

emissions, then you must report the 

relevant information required under 

§ 98.36 for the Tier 4 Calculation 

Methodology and the following 

information in this paragraph (a): 

* * * * * 

(b) * * * 

(6) Sampling analysis results of 

carbon content of feedstock as 

determined for QA/QC of supplier data 

under § 98.74(e). 

* * * * * 

(12) Annual urea production (metric 

tons) and method used to determine 

urea production. 

(13) CO2 from the steam reforming of 

a hydrocarbon or the gasification of 

solid and liquid raw material at the 

ammonia manufacturing process unit 

used to produce urea and the method 

used to determine the CO2 consumed in 

urea production. 

Subpart P—[Amended] 

30. Section 98.164 is amended by 

revising paragraph (b)(1) to read as 

follows: 

§ 98.164 Monitoring and QA/QC 

requirements. 

* * * * * 

(b) * * * 

(1) Calibrate all oil and gas flow 

meters that are used to measure liquid 

and gaseous feedstock volumes (except 

for gas billing meters) according to the 

monitoring and QA/QC requirements for 

the Tier 3 methodology in § 98.34(b)(1). 

Perform oil tank drop measurements (if 

used to quantify liquid fuel or feedstock 

consumption) according to § 98.34(b)(2). 

Calibrate all solids weighing equipment 

according to the procedures in § 98.3(i). 

* * * * * 

Subpart V—[Amended] 

31. Section 98.226 is amended by 

removing paragraph (o). 

Subpart X—[Amended] 

32. Section 98.240 is amended by 

revising paragraph (a); and by adding 

paragraph (g) to read as follows: 

§ 98.240 Definition of the source category. 

(a) The petrochemical production 

source category consists of all processes 

that produce acrylonitrile, carbon black, 

ethylene, ethylene dichloride, ethylene 

oxide, or methanol, except as specified 

in paragraphs (b) through (g) of this 

section. The source category includes 

processes that produce the 

petrochemical as an intermediate in the 

onsite production of other chemicals as 

well as processes that produce the 

petrochemical as an end product for sale 

or shipment offsite. 

* * * * * 

(g) A process that solely distills or 

recycles waste solvent that contains a 

petrochemical is not part of the 

petrochemical production source 

category. 

33. Section 98.242 is amended by 

revising paragraph (a)(1) and paragraph 

(b) introductory text to read as follows: 

§ 98.242 GHGs to report. 

* * * * * 

(a) * * * 

(1) If you comply with § 98.243(b) or 

(d), report under this subpart the 

calculated CO2, CH4, and N2O emissions 

for each stationary combustion source 

and flare that burns any amount of 

petrochemical process off-gas. If you 

comply with § 98.243(b), also report 

under this subpart the measured CO2

emissions from process vents routed to 

stacks that are not associated with 

stationary combustion units. 

* * * * * 

(b) CO2, CH4, and N2O combustion 

emissions from stationary combustion 

units. 

* * * * * 

34. Section 98.243 is amended by: 

a. Revising the second sentence of 

paragraph (b). 

b. Revising the definition of ‘‘MVC’’ in 

Equation X–1 in paragraph (c)(5)(i). 

c. Revising paragraph (d). 

§ 98.243 Calculating GHG emissions. 

* * * * * 

(b) * * * For each stack (except flare 

stacks) that includes emissions from 

combustion of petrochemical process 

off-gas, calculate CH4 and N2O 

emissions in accordance with subpart C 

of this part (use the Tier 3 methodology, 

emission factors for ‘‘Petroleum’’ in 

Table C–2 of subpart C of this part, and 

either the default high heat value for 

fuel gas in Table C–1 of subpart C of this 

part or a calculated HHV, as allowed in 

Equation C–8 of subpart C of this part). 

* * * 

(c) * * * 

(5) * * * 

(i) * * * 

MVC = Molar volume conversion factor 

(849.5 scf per kg-mole at 68 °F and 14.7 

pounds per square inch absolute or 836.6 

scf/kg-mole at 60 °F and 14.7 pounds per 

square inch absolute). 

* * * * * 

(d) Optional combustion methodology 

for ethylene production processes. For 

each ethylene production process, 

calculate GHG emissions from each 

combustion unit that burns fuel that 

contains any off-gas from the ethylene 

process as specified in paragraphs (d)(1) 

through (d)(5) of this section. 

(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 


srobinson on DSKHWCL6B1PROD with PROPOSALS2
Federal Register / Vol. 75, No. 154 / Wednesday, August 11, 2010 / Proposed Rules 48803 

(General Stationary Fuel Combustion 

Sources). 

(ii) For Tier 3, use either the default 

high heat value for fuel gas in Table C– 

1 of subpart C of this part or a calculated 

HHV, as allowed in Equation C–8 of 

subpart C of this part. 

(4) You are not required to use the 

same Tier for each stationary 

combustion unit that burns ethylene 

process off-gas. 

(5) For each flare, calculate CO2, CH4, 

and N2O emissions using the 

methodology specified in § 98.253(b)(1) 

through (b)(3). 

35. Section 98.244 is amended by 

revising paragraphs (b)(1) through (b)(3) 

and (b)(4) introductory text; and by 

adding paragraphs (b)(4)(xi) through 

(b)(4)(xiii) to read as follows: 

§ 98.244 Monitoring and QA/QC 

requirements. 

* * * * * 

(b) * * * 

(1) Operate, maintain, and calibrate 

belt scales or other weighing devices as 

described in Specifications, Tolerances, 

and Other Technical Requirements For 

Weighing and Measuring Devices NIST 

Handbook 44 (2009) (incorporated by 

reference, see § 98.7), or follow 

procedures specified by the 

measurement device manufacturer. You 

must recalibrate each weighing device 

according to one of the following 

frequencies. You may recalibrate either 

biennially (i.e., once every two years) or 

at the minimum frequency specified by 

the manufacturer. 

(2) Operate and maintain all flow 

meters used for gas and liquid 

feedstocks and products according to 

the manufacturer’s recommended 

procedures. You must calibrate each of 

these flow meters according to one of 

the following. You may use either an 

industry consensus standard method or 

methods specified by the flow meter 

manufacturer. Each flow meter must 

meet the applicable accuracy 

specification in § 98.3(i), except as 

otherwise specified in § 98.3(i)(4) 

through (i)(6). You must recalibrate each 

flow meter according to one of the 

following frequencies. You may 

recalibrate either biennially, at the 

minimum frequency specified by the 

manufacturer, or at the interval 

specified by the industry consensus 

standard practice used. 

(3) You must perform tank level 

measurements (if used to determine 

feedstock or product flows) according to 

one of the following methods. You may 

use any standard method published by 

a consensus-based standards 

organization (e.g., ASTM, API, etc.) or 

you may use industry standard practice. 

(4) Use any applicable methods 

specified in paragraphs (b)(4)(i) through 

(b)(4)(xiii) of this section to determine 

the carbon content or composition of 

feedstocks and products and the average 

molecular weight of gaseous feedstocks 

and products. Calibrate instruments in 

accordance with paragraphs (b)(4)(i) 

through (b)(4)(xiii), as applicable. For 

coal used as a feedstock, the samples for 

carbon content determinations shall be 

taken at a location that is representative 

of the coal feedstock used during the 

corresponding monthly period. For 

carbon black products, samples shall be 

taken of each grade or type of product 

produced during the monthly period. 

Samples of coal feedstock or carbon 

black product for carbon content 

determinations may be either grab 

samples collected and analyzed 

monthly or a composite of samples 

collected more frequently and analyzed 

monthly. Analyses conducted in 

accordance with methods specified in 

paragraphs (b)(4)(i) through (b)(4)(xiii) 

of this section may be performed by the 

owner or operator, by an independent 

laboratory, or by the supplier of a 

feedstock. 

* * * * * 

(xi) ASTM D2593–93 (Reapproved 

2009) Standard Test Method for 

Butadiene Purity and Hydrocarbon 

Impurities by Gas Chromatography, 

(incorporated by reference, see § 98.7), 

effective as of January 1, 2010. 

(xii) An industry standard practice for 

carbon black feedstock oils and carbon 

black products, effective as of January 1, 

2010. 

(xiii) Modifications of existing 

analytical methods or other analytical 

methods that are applicable to your 

process provided that the methods 

listed in § 98.244(b)(4)(i) through 

§ 98.244(b)(4)(xii) are not appropriate 

because the relevant compounds cannot 

be detected, the quality control 

requirements are not technically 

feasible, or use of the method would be 

unsafe, effective as of January 1, 2010. 

36. Section 98.246 is amended by: 

a. Revising paragraphs (a) 

introductory text and (a)(4). 

b. Removing and reserving paragraph 

(a)(7). 

c. Revising paragraph (a)(10). 

d. Adding paragraph (a)(11). 

e. Revising paragraphs (b) 

introductory text, and (b)(1) through 

(b)(5). 

f. Revising paragraph (c). 

§ 98.246 Data reporting requirements. 

* * * * * 

(a) If you use the mass balance 

methodology in § 98.243(c), you must 

report the information specified in 

paragraphs (a)(1) through (a)(11) of this 

section for each type of petrochemical 

produced, reported by process unit. 

* * * * * 

(4) Each of the monthly volume, mass, 

and carbon content values used in 

Equations X–1 through X–3 of this 

subpart (i.e., the directly measured 

values, substitute values, or the 

calculated values based on other 

measured data such as tank levels or gas 

composition) and the molecular weights 

for gaseous feedstocks and products 

used in Equation X–1 of this subpart, 

and the temperture (in °F) at which the 

gaseous feedstock and product volumes 

used in Equation X–1 of this subpart 

were determined. Indicate whether you 

used the alternative to sampling and 

analysis specified in § 98.243(c)(4). 

* * * * * 

(10) You may elect to report the flow 

and carbon content of wastewater, and 

you may elect to report the annual mass 

of carbon released in fugitive emissions 

and in process vents that are not 

controlled with a combustion device. 

These values may be estimated based on 

engineering analyses. These values are 

not to be used in the mass balance 

calculation. 

(11) If you determine carbon content 

or composition of a feedstock or product 

using a method under 

§ 98.244(b)(4)(xiii), report the 

information listed in paragraphs 

(a)(11)(i) through (a)(11)(iii) of this 

section. Include the information in 

paragraph (a)(11)(i) of this section in 

each annual report. Include the 

information in paragraphs (a)(11)(ii) and 

(a)(11)(iii) of this section only in the 

first applicable annual report, and 

provide any changes to this information 

in subsequent annual reports. 

(i) Name or title of the analytical 

method. 

(ii) A copy of the method. If the 

method is a modification of a method 

listed in § 98.244(b)(4)(i) through (xii), 

you may provide a copy of only the 

sections that differ from the listed 

method. 

(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 


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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 

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). 

37. 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] 

38. Section 98.252 is amended by 

revising paragraph (a) and the first 

sentence of paragraph (i) to read as 

follows: 

§ 98.252 GHGs to report. 

* * * * * 

(a) CO2, CH4, and N2O combustion 

emissions from stationary combustion 

units and from each flare. Calculate and 

report the emissions from stationary 

combustion units under subpart C of 

this part (General Stationary Fuel 

Combustion Sources) by following the 

requirements of subpart C, except for 

emissions from combustion of fuel gas. 

For CO2 emissions from combustion of 

fuel gas, use either Equation C–5 in 

subpart C of this part or the Tier 4 

methodology in subpart C of this part, 

unless either of the conditions in 

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

are met, in which case use either 

Equations C–1 or C–2a in subpart C of 

this part. For CH4 and N2O emissions 

from combustion of fuel gas, use the 

applicable procedures in § 98.33(c) for 

the same tier methodology that was 

used for calculating CO2 emissions. (Use 

the default CH4 and N2O emission 

factors for ‘‘Petroleum (All fuel types in 

Table 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 upsteam common pipe; or 

(ii) The fuel gas line contains only 

vapors from loading or unloading, waste 

or wastewater handling, and 

remediation activities that are 

combusted in a thermal oxidizer or 

thermal incinerator. 

* * * * * 

(i) CO2 emissions from non-merchant 

hydrogen production process units (not 

including hydrogen produced from 

catalytic reforming units) under this 

subpart. * * * 

39. Section 98.253 is amended by: 

a. Revising paragraph (b)(1)(ii)(A). 

b. Revising the definition of ‘‘MVC’’ in 

Equation Y–3 in paragraph (b)(1)(iii)(C). 


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c. Revising paragraph (c)(1)(ii). 

d. Revising the definition of ‘‘MVC’’ in 

Equation Y–6 in paragraph (c)(2)(i). 

e. Revising paragraph (c)(2)(ii). 

f. Revising the definition of ‘‘CBQ’’ and 

‘‘n’’ in Equation Y–11 in paragraph 

(e)(3). 

g. Revising the first sentence of 

paragraph (f) introductory text and the 

last sentence of paragraph (f)(1). 

h. Revising the definition of ‘‘MVC’’ in 

Equation Y–12 in paragraph (f)(4). 

i. Revising the definition of ‘‘Mdust’’ in 

Equation Y–13 in paragraph (g)(2). 

j. Revising paragraphs (h) 

introductory text and (h)(2). 

k. In paragraph (i)(1), revising the first 

two sentences and the definition of 

‘‘MVC’’ in Equation Y–18. 

l. In paragraph (j), revising both 

sentences; and revising the definitions 

of ‘‘(VR)p,’’ ‘‘(MFx)p,’’ and ‘‘MVC’’ in 

Equation Y–19. 

m. In paragraph (k), revising the first 

sentence and the definition of ‘‘MVC’’ in 

Equation Y–20. 

n. Revising paragraph (m) 

introductory text. 

o. Revising the definitions of ‘‘MFCH4’’ 

and ‘‘MVC’’ in Equation Y–23 in 

paragraph (m)(2). 

p. Revising paragraph (n). 

§ 98.253 Calculating GHG emissions. 

* * * * * 

(b) * * * 

(1) * * * 

(ii) * * * 

(A) If you monitor gas composition, 

calculate the CO2 emissions from the 

flare using either Equation Y–1a or 

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. 

CO Flare

MW

MVC

CC p

p

p p=

n

2

1

44

12

=× × ×( ) ×

( )

×( )

⎡

⎣

⎢

⎢

⎤

⎦

⎥

⎥

⎛

⎝

0 98 0 001 . . ⎜

⎜∑ ⎞

⎠

⎟

⎟ ( ) Eq. Y-1a

Where: 

CO2 = Annual CO2 emissions for a specific 

fuel type (metric tons/year). 

0.98 = Assumed combustion efficiency of a 

flare. 

0.001 = Unit conversion factor (metric tons 

per kilogram, mt/kg). 

n = Number of measurement periods. The 

minimum value for n is 52 (for weekly 

measurements); the maximum value for 

n is 366 (for daily measurements during 

a leap year). 

p = Measurement period index. 

44 = Molecular weight of CO2 (kg/kg-mole). 

12 = Atomic weight of C (kg/kg-mole). 

(Flare)p = Volume of flare gas combusted 

during measurement period (standard 

cubic feet per period, scf/period). If a 

mass flow meter is used, measure flare 

gas flow rate in kg/period and replace 

the term ‘‘(MW)p/MVC’’ with ‘‘1’’. 

(MW)p = Average molecular weight of the 

flare gas combusted during measurement 

period (kg/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 ßF and 14.7 

pounds per square inch absolute (psia) or 

836.6 scf/kg-mole at 60 ßF 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. 

CO Flare

MVC

CO C

CMN p

p x p

2 x

44 2 %

100% = ( ) × ××

( )

+ ×

( )

×

⎧

0 001

100 . 0 98

%

% ⎨ . ⎪

⎩⎪

⎫

⎬

⎪

⎭⎪

⎛

⎝

⎜

⎜

⎞

⎠

⎟

⎟

⎡

⎣

⎢

⎢

⎤

⎦

⎥

⎥ ∑ ∑ ( ) x=

y

p=

n

1 1

Eq. Y-1b

Where: 

CO2 = Annual CO2 emissions for a specific 

fuel type (metric tons/year). 

n = Number of measurement periods. The 

minimum value for n is 52 (for weekly 

measurements); the maximum value for 

n is 366 (for daily measurements during 

a leap year). 

p = Measurement period index. 

(Flare)p = Volume of flare gas combusted 

during measurement period (standard 

cubic feet per period, scf/period). If a 

mass flow meter is used, you must 

determine the average molecular weight 

of the flare gas during the measurement 

period and convert the mass flow to a 

volumetric flow. 

44 = Molecular weight of CO2 (kg/kg-mole). 

MVC = Molar volume conversion factor 

(849.5 scf/kg-mole at 68ßF and 14.7 psia 

or 836.6 scf/kg-mole at 60ßF 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. 

* * * * * 

(iii) * * * 

(C) 

* * * * * 

MVC = Molar volume conversion factor 

(849.5 scf/kg-mole at 68 ßF and 14.7 psia 

or 836.6 scf/kg-mole at 60 ßF 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 ßF and 14.7 psia 

or 836.6 scf/kg-mole at 60 ßF and 14.7 

psia). 

* * * * * 

(ii) Either continuously monitor the 

volumetric flow rate of exhaust gas from 


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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. 

Q

Q OQ

CO CO - O r

a oxy oxy

= ( ) ∗+ − ( ) ∗

− − ( )

79 100

100

7

2 2

%

% %% Eq Y a . -

Where: 

Qr = Volumetric flow rate of exhaust gas from 

the fluid catalytic cracking unit 

regenerator or fluid coking unit burner 

prior to the combustion of other fossil 

fuels (dscfh). 

Qa = Volumetric flow rate of air to the fluid 

catalytic cracking unit regenerator or 

fluid coking unit burner, as determined 

from control room instrumentation 

(dscfh). 

Qoxy = Volumetric flow rate of oxygen 

enriched air to the fluid catalytic 

cracking unit regenerator or fluid coking 

unit burner as determined from control 

room instrumentation (dscfh). 

%O2 = Hourly average percent oxygen 

concentration in exhaust gas stream from 

the fluid catalytic cracking unit 

regenerator or fluid coking unit burner 

(percent by volume—dry basis). 

%Ooxy = O2 concentration in oxygen enriched 

gas stream inlet to the fluid catalytic 

cracking unit regenerator or fluid coking 

unit burner based on oxygen purity 

specifications of the oxygen supply used 

for enrichment (percent by volume—dry 

basis). 

%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. 

Q

QN Q

N r

a oxy oxy

exhaust

= ( ) ∗ + ( ) ∗

( )

78 1 2

2

. %

%

,

,

Eq. Y-7b

Where: 

Qr = Volumetric flow rate of exhaust gas from 

the fluid catalytic cracking unit 

regenerator or fluid coking unit burner 

prior to the combustion of other fossil 

fuels (dscfh). 

Qa = Volumetric flow rate of air to the fluid 

catalytic cracking unit regenerator or 

fluid coking unit burner, as determined 

from control room instrumentation 

(dscfh). 

Qoxy = Volumetric flow rate of oxygen 

enriched air to the fluid catalytic 

cracking unit regenerator or fluid coking 

unit burner as determined from control 

room instrumentation (dscfh). 

%N2,oxy = N2 concentration in oxygen 

enriched gas stream inlet to the fluid 

catalytic cracking unit regenerator or 

fluid coking unit burner based on 

measured value or maximum N2

impurity specifications of the oxygen 

supply used for enrichment (percent by 

volume—dry basis). 

%N2,exhaust = Hourly average percent N2

concentration in the exhaust gas stream 

from the fluid catalytic cracking unit 

regenerator or fluid coking unit burner 

(percent by volume—dry basis). 

* * * * * 

(e) * * * 

(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). 


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CO Q CEF 2 AB AB 0 98 44

12

=× × × 16 ⎛

⎝

⎜ ⎞

⎠

⎟ . . ( ) Eq Y a -

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). 

CO Q EF AB AB,CO CEF EF 2 AB AB,CO2 2 0 98 44

12

=× +× × ⎛

⎝

⎜ ⎞

⎠

⎟ − ⎡

⎣

⎢ ⎤

⎦

⎥

⎛

⎝

⎜ ⎞

⎠

. ⎟ ( ) Eq. Y-16b

Where: 

CO2 = Annual CO2 emissions from controlled 

asphalt blowing (metric tons CO2/year). 

QAB = Quantity of asphalt blown (MMbbl/ 

year). 

0.98 = Assumed combustion efficiency of 

thermal oxidizer or flare. 

EFAB,CO2 = Emission factor for CO2 from 

uncontrolled asphalt blowing from 

facility-specific test data (metric tons 

CO2/MMbbl asphalt blown); default = 

1,100. 

CEFAB = Carbon emission factor from asphalt 

blowing from facility-specific test data 

(metric tons C/MMbbl asphalt blown); 

default = 2,750. 

44 = Molecular weight of CO2 (kg/kg-mole). 

12 = Atomic weight of C (kg/kg-mole). 

CH4 AB AB CH EF 4 =× × 0 02 . ( ) Q , ( ) Eq. Y-17

Where: 

CH4 = Annual methane emissions from 

controlled asphalt blowing (metric tons 

CH4/year). 

0.02 = Fraction of methane uncombusted in 

thermal oxidizer or flare based on 

assumed 98% combustion efficiency. 

QAB = Quantity of asphalt blown (million 

barrels per year, MMbbl/year). 

EFAB,CH4 = Emission factor for CH4 from 

uncontrolled asphalt blowing from 

facility-specific test data (metric tons 

CH4/MMbbl asphalt blown); default = 

580. 

(i) * * * 

(1) Use the process vent method in 

paragraph (j) of this section to calculate 

the CH4 emissions from the 

depressurization of the coke drum or 

vessel regardless of the CH4

concentration and also calculate the CH4

emissions from the subsequent opening 

of the vessel for coke cutting operations 

using Equation Y–18 of this section. If 

you have coke drums or vessels of 

different dimensions, use the process 

vent method in paragraph (j) of this 

section and Equation Y–18 for each set 

of coke drums or vessels of the same 

size and sum the resultant emissions 

across each set of coke drums or vessels 

to calculate the CH4 emissions for all 

delayed coking units. 

* * * * * 

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 be reasonably expected 

to contain greater than 2 percent by 

volume CO2 or greater than 0.5 percent 

by volume of CH4 or greater than 0.01 

percent by volume (100 parts per 

million) of N2O, calculate GHG 

emissions using the Equation Y–19 of 

this section. You must use Equation Y– 

19 of this section to calculate CH4

emissions for catalytic reforming unit 

depressurization and purge vents when 

methane is used as the purge gas or if 

you elected this method as an 

alternative to the methods in paragraphs 

(f), (h), or (k) of this section. 

* * * * * 

(VR)p = Average volumetric flow rate of 

process gas during the event (scf per 

hour) from measurement data, process 

knowledge, or engineering estimates. 

(MFx)p = Mole fraction of GHG × in process 

vent during the event (kg-mol of GHG ×/ 

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. 

(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 Section 5.2 of the AP–42: 

‘‘Compilation of Air Pollutant Emission 

Factors, Volume 1: Stationary Point and 

Area Sources.’’ For loading operations in 

which the vapor-phase concentration of 

methane is less than 0.5 volume 

percent, you may assume zero methane 

emissions. 

40. Section 98.254 is amended by: 

a. Revising paragraph (a). 


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b. Revising paragraph (b). 

c. Revising paragraph (c). 

d. Revising paragraphs (d) 

introductory text and (d)(6). 

e. Adding a new 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 

according to subpart C of this part or 

that are associated with stationary 

combustion sources must meet the 

applicable monitoring and QA/QC 

requirements in § 98.34. 

(b) All gas flow meters, gas 

composition monitors, and heating 

value monitors that are used to provide 

data for the GHG emissions calculations 

in this subpart for sources other than 

those subject to the requirements in 

paragraph (a) of this section shall be 

calibrated according to the procedures 

in the applicable methods specified in 

paragraphs (c) through (g) of this section 

or the procedures specified by the 

manufacturer. In the case of gas flow 

meters, all gas flow meters must meet 

the calibration accuracy requirements in 

§ 98.3(i). You must recalibrate each gas 

flow meter according to one of the 

following frequencies. You may 

recalibrate either biennially (every two 

years), at the minimum frequency 

specified by the manufacturer, or at the 

interval specified by the industry 

consensus standard practice used. You 

must recalibrate each gas composition 

monitor and heating value monitor 

according to one of the following 

frequencies. You may recalibrate either 

annually, at the minimum frequency 

specified by the manufacturer, or at the 

interval specified by the industry 

consensus standard practice used. 

(c) For flare or sour gas flow meters, 

operate, calibrate, and maintain the flow 

meter according to one of the following. 

You may use a method published by a 

consensus-based standards organization 

or the procedures specified by the flow 

meter manufacturer. Consensus-based 

standards include, but are not limited 

to, the following: ASTM International, 

the American Society of Mechanical 

Engineers (ASME), and the American 

Gas Association (AGA). 

(d) Except as provided in paragraph 

(g) of this section, determine gas 

composition and, if required, average 

molecular weight of the gas using any of 

the following methods. Alternatively, 

the results of chromatographic analysis 

of the fuel may be used, provided that 

the gas chromatograph is operated, 

maintained, and calibrated according to 

the manufacturer’s instructions; and the 

methods used for operation, 

maintenance, and calibration of the gas 

chromatograph are documented in the 

written Monitoring Plan for the unit 

under § 98.3(g)(5). 

* * * * * 

(6) ASTM D2503–92 (Reapproved 

2007) Standard Test Method for Relative 

Molecular Mass (Molecular Weight) of 

Hydrocarbons by Thermoelectric 

Measurement of Vapor Pressure 

(incorporated by reference, see § 98.7). 

(e) Determine flare gas higher heating 

value using any of the following 

methods. Alternatively, the results of 

chromatographic analysis of the fuel 

may be used, provided that the gas 

chromatograph is operated, maintained, 

and calibrated according to the 

manufacturer’s instructions; and the 

methods used for operation, 

maintenance, and calibration of the gas 

chromatograph are documented in the 

written Monitoring Plan for the unit 

under § 98.3(g)(5). 

* * * * * 

(f) For gas flow meters used to comply 

with the requirements in 

§ 98.253(c)(2)(ii) or § 98.253(j), install, 

operate, calibrate, and maintain each gas 

flow meter according to the 

requirements in 40 CFR 63.1572(c) and 

the following requirements. 

(1) Locate the flow monitor at a site 

that provides representative flow rates. 

Avoid locations where there is swirling 

flow or abnormal velocity distributions 

due to upstream and downstream 

disturbances. 

* * * * * 

(g) For exhaust gas CO2/CO/O2

composition monitors used to comply 

with the requirements in § 98.253(c)(2), 

install, operate, calibrate, and maintain 

exhaust gas composition monitors 

according to the the requirements in 40 

CFR 60.105a(b)(2) or 40 CFR 63.1572(c) 

or according to the manufacturer’s 

specifications and requirements. 

(h) * * * Calibrate the measurement 

device according to the procedures 

specified by NIST handbook 44 or the 

procedures specified by the 

manufacturer. * * * 

* * * * * 

41. Section 98.256 is amended by: 

a. Revising paragraph (e)(6). 

b. Redesignating paragraphs (e)(7) 

through (e)(9) as (e)(8) through (e)(10), 

respectively. 

c. Adding a new paragraph (e)(7). 

d. Revising newly designated 

paragraphs (e)(8) and (e)(9). 

e. Revising paragraphs (f)(6) through 

(f)(8). 

f. Redesignating paragraphs (f)(9) 

through (f)(12) as (f)(10) through (f)(13), 

respectively. 

g. Adding a new paragraph (f)(9). 

h. Revising newly designated 

paragraphs (f)(11) through (f)(13). 

i. Revising paragraphs (g)(5), (h)(2), 

(h)(4), and (h)(6). 

j. Adding paragraph (h)(7). 

k. Revising paragraphs (i)(5), (i)(6), 

(i)(8), and (j)(2). 

l. Redesignating paragraph (j)(8) as 

(j)(9). 

m. Adding a new paragraph (j)(8). 

n. Revising paragraphs (k)(1), (k)(3), 

(l) introductory text, (l)(5), and (m). 

o. Revising paragraph (o). 

§ 98.256 Data reporting requirements. 

* * * * * 

(e) * * * 

(6) If you use Equation Y–1a of this 

subpart, an indication of whether daily 

or weekly measurement periods are 

used, the annual volume of flare gas 

combusted (in scf/year) and the annual 

average molecular weight (in kg/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 

or weekly measurement periods are 

used, the annual volume of flare gas 

combusted (in million (MM) scf/year) 

and the annual average higher heating 

value of the flare gas (in MMBtu per 

MMscf). 

(9) If you use Equation Y–3 of this 

subpart, the annual volume of flare gas 

combusted (in MMscf/year) during 


srobinson on DSKHWCL6B1PROD with PROPOSALS2
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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 

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. 


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48810 Federal Register / Vol. 75, No. 154 / Wednesday, August 11, 2010 / Proposed Rules 

(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 (Section 

7.1 of the AP–42: ‘‘Compilation of Air 

Pollutant Emission Factors, Volume 1: 

Stationary Point and Area Sources’’, 

including TANKS Model (Version 

4.09D) or similar programs, or Equation 

Y–22 of this section, other). 

(ii) The total quantity (in MMbbl) of 

crude oil plus the quantity of 

intermediate products received from offsite that are processed at the facility in 

the reporting year. 

(3) The cumulative CH4 emissions (in 

metric tons of CH4) for storage tanks 

used to process unstabilized crude 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. 

* * * * * 

42. Section 98.257 is revised to read 

as follows: 

§ 98.257 Records that must be retained. 

In addition to the records required by 

§ 98.3(g), you must retain the records of 

all parameters monitored under 

§ 98.255. If you comply with the 

combustion methodology in § 98.252(a), 

then you must retain under this subpart 

the records required for the Tier 3 and/ 

or Tier 4 Calculation Methodologies in 

§ 98.37 and you must keep records of 

the annual average flow calculations. 

Subpart AA—[Amended] 

43. Section 98.273 is amended by: 

a. Revising paragraphs (a)(1) and 

(a)(2). 

b. Revising paragraphs (b)(1) and 

(b)(2). 

c. Revising paragraphs (c)(1) and 

(c)(2). 

§ 98.273 Calculating GHG emissions. 

(a) * * * 

(1) Calculate fossil fuel-based CO2

emissions from direct measurement of 

fossil fuels consumed and default 

emissions factors according to the Tier 

1 methodology for stationary 

combustion sources in § 98.33(a)(1). A 

higher tier from § 98.33(a) may be used 

to calculate fossil 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). 

* * * * * 

(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. 

* * * * * 

44. Section 98.276 is amended by 

revising the introductory text to read as 

follows: 

§ 98.276 Data reporting requirements. 

In addition to the information 

required by § 98.3(c) and the applicable 

information required by § 98.36, each 

annual report must contain the 

information in paragraphs (a) through 

(k) of this section as applicable: 

* * * * * 

45. In the Tables to Subpart AA of 

Part 98, Table AA–2 is revised to read 

as follows: 


srobinson on DSKHWCL6B1PROD with PROPOSALS2
Federal Register / Vol. 75, No. 154 / Wednesday, August 11, 2010 / Proposed Rules 48811 

TABLE AA–2 OF 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 0.0001 

Biogas 0.0001 

Petroleum coke NA aNA 

aEmission factors for kraft calciners are not available. 

Subpart OO—[Amended] 

46. Section 98.410 is amended by 

revising paragraph (b) to read as follows: 

§ 98.410 Definition of the source category. 

* * * * * 

(b) To produce a fluorinated GHG 

means to manufacture a fluorinated 

GHG from any raw material or feedstock 

chemical. Producing a fluorinated GHG 

includes the manufacture of a 

fluorinated GHG as an isolated 

intermediate for use in a process that 

will result in its transformation either at 

or outside of the production facility. 

Producing a fluorinated GHG also 

includes the creation of a fluorinated 

GHG (with the exception of 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). 

* * * * * 

47. Section 98.414 is amended by: 

a. Adding a second and third sentence 

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 

fluorinated GHG being destroyed 

considering current or previous 

representative concentration 

measurements and other relevant 

process information. You must multiply 

this concentration (mass fraction) by the 

mass measurement to obtain the mass of 

the fluorinated GHG destroyed. 

* * * * * 

(n) If the mass coming out of the 

production process includes more than 

one fluorinated GHG, you shall measure 

the concentrations of all of the 

fluorinated GHGs, other than 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 October 12, 2010 if the fluorinated 

GHG product is being produced on 

August 11, 2010. Perform the 

measurements within 60 days of 

commencing production of any 

fluorinated GHG product that was not 

being produced on August 11, 2010. 


srobinson on DSKHWCL6B1PROD with PROPOSALS2
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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. 

48. Section 98.416 is amended by: 

a. Revising paragraph (a)(3). 

b. Removing and reserving paragraph 

(a)(4). 

c. Revising paragraph (a)(11). 

d. Revising paragraphs (c) 

introductory text and (c)(1). 

e. Revising paragraph (d) introductory 

text. 

f. Adding paragraphs (f) through (h). 

§ 98.416 Data reporting requirements. 

* * * * * 

(a) * * * 

(3) Mass in metric tons of each 

fluorinated GHG that is destroyed at that 

facility and that was previously 

produced as defined at § 98.410(b). 

Quantities to be reported under this 

paragraph (a)(3) of this section include 

but are not limited to quantities that are 

shipped to the facility by another 

facility for destruction and quantities 

that are returned to the facility for 

reclamation but are found to be 

irretrievably contaminated and are 

therefore destroyed. 

* * * * * 

(11) Mass in metric tons of each 

fluorinated GHG that is fed into the 

destruction device and that was 

previously produced as defined at 

§ 98.410(b). Quantities to be reported 

under this paragraph (a)(11) of this 

section include but are not limited to 

quantities that are shipped to the facility 

by another facility for destruction and 

quantities that are returned to the 

facility for reclamation but are found to 

be irretrievably contaminated and are 

therefore destroyed. 

* * * * * 

(c) Each bulk importer of fluorinated 

GHGs or nitrous oxide shall submit an 

annual report that summarizes its 

imports at the corporate level, except for 

shipments including less than 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. 

* * * * * 

(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: 

* * * * * 

(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. 

49. Section 98.417 is amended by 

revising paragraph (a)(2); and by adding 

paragraphs (f) and (g) to read as follows: 

§ 98.417 Records that must be retained. 

(a) * * * 

(2) Records documenting the initial 

and periodic calibration of the 

analytical equipment (including but not 

limited to GC, IR, FTIR, or NMR), weigh 

scales, flowmeters, and volumetric and 

density measures used to measure the 

quantities reported under this subpart, 

including the industry standards or 

manufacturer directions used for 

calibration pursuant to § 98.414(m) and 

(o). 

* * * * * 

(f) Isolated intermediates that are 

produced and transformed at the same 

facility are exempt from the 

recordkeeping requirements of this 

section. 

(g) Low-concentration constituents are 

exempt from the recordkeeping 

requirements of this section. 

50. Section 98.418 is revised to read 

as follows: 

§ 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 


srobinson on DSKHWCL6B1PROD with PROPOSALS2
Federal Register / Vol. 75, No. 154 / Wednesday, August 11, 2010 / Proposed Rules 48813 

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] 

51. Section 98.422 is amended by 

revising paragraphs (a) and (b) to read 

as follows: 

§ 98.422 GHGs to report. 

(a) Mass of CO2 captured from 

production process units. 

(b) Mass of CO2 extracted from CO2

production wells. 

* * * * * 

52. Section 98.423 is amended by: 

a. Revising the first sentence of 

paragraph (a) introductory text. 

b. Revising the first sentence of 

paragraphs (a)(1) and (a)(2). 

c. Redesignating paragraph (b) as 

paragraph (c) and revising the only 

sentence in newly designated paragraph 

(c). 

d. Adding a new paragraph (b). 

§ 98.423 Calculating CO2 Supply. 

(a) Except as allowed in paragraph (b) 

of this section, calculate the annual 

mass of CO2 captured, extracted, 

imported, or exported through each flow 

meter in accordance with the 

procedures specified in either paragraph 

(a)(1) or (a)(2) of this section. * * * 

(1) For each mass flow meter, you 

shall calculate quarterly the mass of CO2

in a CO2 stream in metric tons by 

multiplying the mass flow by the 

composition data, according to Equation 

PP–1 of this section. * * * 

* * * * * 

(2) For each volumetric flow meter, 

you shall calculate quarterly the mass of 

CO2 in a CO2 stream in metric tons by 

multiplying the volumetric flow by the 

concentration and density data, 

according to Equation PP–2 of this 

section. * * * 

* * * * * 

(b) As an alternative to paragraphs 

(a)(1) through (3) of this section for CO2

that is supplied in containers, calculate 

the annual mass of CO2 supplied in 

containers delivered by each CO2 stream 

in accordance with the procedures 

specified in either paragraph (b)(1) or 

(b)(2) of this section. If multiple CO2

streams are used to deliver CO2 to 

containers, you shall calculate the 

annual mass of CO2 supplied in 

containers delivered by all CO2 streams 

according to the procedures specified in 

paragraph (b)(3) of this section. 

(1) For each CO2 stream that delivers 

CO2 to containers, for which mass is 

measured, you shall calculate CO2

supply in containers using Equation 

PP–1 of this section. 

Where: 

CO2,u = Annual mass of CO2 (metric tons) 

supplied in containers delivered by CO2

stream u. 

CCO2,p,u = Quarterly CO2 concentration 

measurement of CO2 stream u that 

delivers CO2 to containers in quarter p 

(wt. %CO2). 

Qp,u = Quarterly mass of contents supplied in 

all containers delivered by CO2 stream u 

in quarter p (metric tons). 

p = Quarter of the year. 

u = CO2 stream that delivers to containers. 

(2) For each CO2 stream that delivers 

to containers, for which volume is 

measured, you shall calculate CO2

supply in containers using Equation 

PP–2 of this section. 

Where: 

CO2,u = Annual mass of CO2 (metric tons) 

supplied in containers delivered by CO2

stream u. 

CCO2,p,u = Quarterly CO2 concentration 

measurement of CO2 stream u that 

delivers CO2 to containers in quarter p 

(vol. %CO2). 

Qp = Quarterly volume of contents supplied 

in all containers delivered by CO2 stream 

u in quarter p (metric tons) (standard 

cubic meters). 

Dp = Quarterly CO2 stream density 

determination for CO2 stream u in 

quarter p (metric tons per standard cubic 

meter). 

p = Quarter of the year. 

u = CO2 stream that delivers to containers. 

(3) To aggregate data, sum the mass of 

CO2 supplied in containers delivered by 

all CO2 streams in accordance with 

Equation PP–3 of this section. 

Where: 

CO2 = Annual mass of CO2 (metric tons) 

supplied in containers delivered by all 

CO2 streams. 

CO2,u = Annual mass of CO2 (metric tons) 

supplied in containers delivered by CO2

stream u. 

u = CO2 stream that delivers to containers. 

(c) Importers or exporters that import 

or export CO2 in containers shall 

calculate the total mass of CO2 imported 

or exported in metric tons based on 

summing the mass in each CO2

container using weigh bills, scales, or 

load cells according to Equation PP–4 of 

this section. 

* * * * * 

53. Section 98.424 is amended by 

revising paragraphs (a)(1), (a)(2), 

(a)(5)introductory text, (a)(5)(ii), the last 

sentence in paragraph (b)(2); and by 

adding paragraph (c) to read as follows: 

§ 98.424 Monitoring and QA/QC 

requirements. 

(a) * * * 

(1) Reporters following the procedures 

in paragraph (a) of § 98.423 shall 

determine quantity using a flow meter 

or meters located in accordance with 

this paragraph. 

(i) If the CO2 stream is segregated such 

that only a portion is captured for 

commercial application or for injection, 

you must locate the flow meter after the 

point of segregation. 

(ii) Reporters that have a mass flow 

meter or volumetric flow meter installed 

to measure the flow of a CO2 stream that 

meets the requirements of paragraph 

(a)(1)(i) of this section shall base 

calculations in § 98.423 of this subpart 

on the installed mass flow or volumetric 

flow meters. 

(iii) Reporters that do not have a mass 

flow meter or volumetric flow meter 

installed to measure the flow of the CO2

stream that meets the requirements of 

paragraph (a)(1)(i) of this section shall 

base calculations in § 98.423 of this 

subpart on the flow of gas transferred off 

site using a mass flow meter or a 

volumetric flow meter located at the 

point of off-site transfer. 

(2) Reporters following the procedures 

in paragraph (b) of § 98.423 shall 

determine quantity in accordance with 

this paragraph. 

(i) Reporters that supply CO2 in 

containers using weigh bills, scales, or 

load cells shall measure the mass of 

contents of each CO2 container to which 

the CO2 stream delivered, sum the mass 

of contents supplied in all containers to 

which the CO2 stream delivered during 

each quarter, sample the CO2 stream 

delivering CO2 to containers on a 

quarterly basis to determine the 

composition of the CO2 stream, and 

apply Equation PP–1. 

(ii) Reporters that supply CO2 in 

containers using loaded container 

volumes shall measure the volume of 

contents of each CO2 container to which 

the CO2 stream delivered, sum the 

volume of contents supplied in all 

containers to which the CO2 stream 

delivered during each quarter, sample 

the CO2 stream on a quarterly basis to 

determine the composition of the CO2

stream, determine the density quarterly, 

and apply Equation PP–2. 

* * * * * 

(5) Reporters using Equation PP–2 of 

this subpart shall determine the density 

of the CO2 stream on a quarterly basis 

in order to calculate the mass of the CO2

stream according to one of the following 

procedures: 

* * * * * 

(ii) You shall follow industry standard 

practices. 


srobinson on DSKHWCL6B1PROD with PROPOSALS2
48814 Federal Register / Vol. 75, No. 154 / Wednesday, August 11, 2010 / Proposed Rules 

(b) * * * 

(2) * * * Acceptable methods include 

U.S. Food and Drug Administration 

food-grade specifications for CO2 (see 21 

CFR 184.1240) and ASTM standard 

E1747–95(Reapproved 2005) Standard 

Guide for Purity of Carbon Dioxide Used 

in Supercritical Fluid Applications 

(incorporated by reference, see § 98.7 of 

subpart A of this part). 

(c) If you measure the flow of the CO2

stream with a volumetric flow meter, 

you shall convert all measured volumes 

of carbon dioxide to the following 

standard industry temperature and 

pressure conditions: standard cubic 

meters at a temperature of 60 degrees 

Fahrenheit and at an absolute pressure 

of 1 atmosphere. If you apply the 

density value for CO2 at standard 

conditions, you must use must use 

0.0018704 metric tons per standard 

cubic meter. 

54. Section 98.425 is amended by 

adding a new paragraph (d) to read as 

follows: 

§ 98.425 Procedures for estimating 

missing data. 

* * * * * 

(d) Whenever the quality assurance 

procedures in § 98.424(a)(2) of this 

subpart cannot be followed to measure 

quarterly quantity of CO2 in containers, 

the most appropriate of the following 

missing data procedures shall be 

followed: 

(1) A quarterly quantity of CO2 in 

containers that is missing may be 

substituted with a quarterly value 

measured during another representative 

quarter of the current reporting year. 

(2) A quarterly quantity of CO2 in 

containers that is missing may be 

substituted with a quarterly value 

measured during the same quarter from 

the past reporting year. 

(3) The quarterly quantity of CO2 in 

containers recorded for purposes of 

product tracking and billing according 

to the reporter’s established procedures 

may be substituted for any period 

during which measurement equipment 

is inoperable. 

55. Section 98.426 is amended by: 

a. Revising paragraphs (a) 

introductory text and (a)(2). 

b. Adding a new paragraph (a)(5). 

c. Revising paragraphs (b) 

introductory text and (b)(2). 

d. Adding a new paragraph (b)(7). 

e. Revising paragraphs (c) and (e)(1). 

§ 98.426 Data reporting requirements. 

* * * * * 

(a) If you use Equation PP–1 of this 

subpart, report the following 

information for each mass flow meter or 

CO2 stream that delivers CO2 to 

containers: 

* * * * * 

(2) Quarterly mass in metric tons of 

CO2.

* * * * * 

(5) The location of the flow meter in 

your process chain in relation to the 

points of CO2 stream capture, 

deyhdration, compression, and other 

processing. 

(b) If you use Equation PP–2 of this 

subpart, report the following 

information for each volumetric flow 

meter or CO2 stream that delivers CO2

to containers: 

* * * * * 

(2) Quarterly volume in standard 

cubic meters of CO2.

* * * * * 

(7) The location of the flow meter in 

your process chain in relation to the 

points of CO2 stream capture, 

deyhdration, compression, and other 

processing. 

(c) If you use Equation PP–3 of this 

subpart report the annual CO2 mass in 

metric tons from all flow meters and 

CO2 streams that delivers CO2 to 

containers. 

* * * * * 

(e) * * * 

(1) The type of equipment used to 

measure the total flow of the CO2 stream 

or the total mass or volume in CO2

containers. 

* * * * * 

[FR Doc. 2010–18354 Filed 8–10–10; 8:45 am] 

BILLING CODE 6560–50–P 


srobinson on DSKHWCL6B1PROD with PROPOSALS2