Mandatory Reporting of Greenhouse Gases

Federal RegisterAug 11, 2010

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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/climatechange/emissions/ghgrulemaking.html.

SUPPLEMENTARY INFORMATION:

Additional Information on Submitting Comments: To expedite review of your comments by Agency staff, you are encouraged to send a separate copy of your comments, in addition to the copy you submit to the official docket, to Carole Cook, U.S. EPA, Office of Atmospheric Programs, Climate Change Division, Mail Code 6207-J, Washington, DC 20460, telephone (202) 343-9263, e-mail address:

GHGReportingRule@epa.gov.

Regulated Entities. The Administrator determined that this action is subject to the provisions of Clean Air Act (CAA) section 307(d).

See

CAA section 307(d)(1)(V) (the provisions of section 307(d) apply to “such other actions as the Administrator may determine”). These are proposed amendments to existing regulations. If finalized, these amended regulations would affect owners or operators of certain fossil fuel and industrial gas suppliers, and direct emitters of GHGs. Regulated categories and entities include those listed in Table 1 of this preamble:

Table 1—Examples of Affected Entities by Category

Category

NAICS

Examples of affected facilities

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 Management

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 (CO

)

325120

Industrial gas production facilities.

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

Table 1 of this preamble is not intended to be exhaustive, but rather provides a guide for readers 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

methane

CO carbon monoxide

carbon dioxide

e CO

-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

mtCO

e metric tons of CO

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

O nitrous oxide

NAICS North American Industry Classification System

NGLs natural gas liquids

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

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.

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.

Consolidated Appropriations Act, 2008, Public Law 110-161, 121 Stat. 1844, 2128.

This is the second time that EPA has published a notice proposing amendments to Part 98 to, among other things, correct certain technical and editorial errors that have been identified since promulgation and clarify or

propose amendments to certain provisions that have been the subject of questions from reporting entities. The first proposal was published on June 15, 2010 (75 FR 33950). This proposal complements the proposal published on June 15, 2010 and is not intended to duplicate or replace the proposed amendments published on June 15, 2010. We are seeking public comment only on the issues specifically identified in this proposal for the identified subparts. We will not respond to any comments addressing other aspects of Part 98 or any other related rulemakings.

C. Legal Authority

EPA is proposing these rule amendments under its existing CAA authority, specifically authorities provided in section 114 of the CAA.

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.

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.

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 CO

equivalents (mtCO

e) 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 CO

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 CO

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 CO

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 60ºF or 68ºF, so the facilities will not have to make those corrections in their data.

We are also proposing corrections to terms and definitions in certain equations. For example, in subpart Y, Petroleum Refineries, we are proposing to clarify in an equation that for coke calcining units that recycle the collected coke dust, the mass of coke dust removed from the process is the mass of coke dust collected less the mass of coke dust recycled to the process. These clarifications do not result in additional requirements; therefore, we have concluded that reporters can follow Part 98, as amended, in submitting their first reports in 2011.

Finally, we are proposing other technical corrections that have no impact on facility's data collection efforts in 2010. For example, we are proposing to amend subpart C to remove a second copy of Table C-2 that was inadvertently 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

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

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

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 CO

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 CO

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 NO

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 CO

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

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 CO

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 CO

emissions to be optional for units subject to subpart D. However, the current rule does not consistently affirm this. Section 98.3(c)(4) of subpart A requires sources to report facility-wide GHG emissions, excluding biogenic CO

, and to report CO

emissions for each source category excluding biogenic CO

. To meet these reporting requirements, facilities with subpart D and/or other Part 75 units on-site would have to separately account for the biogenic CO

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 CO

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 CO

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 CO

; instead, it would require all owners or operators to report annual facility-wide emissions,

including

biogenic CO

• 40 CFR 98.3(c)(4)(ii) and (c)(4)(iii)(A) would be amended to state that separate reporting of biogenic CO

emissions is not required for units using part 75 methodologies to calculate CO

mass emissions.

• 40 CFR 98.3(c)(4)(ii)(B) would be revised to no longer require reporting of the annual CO

emissions from subparts C through JJ,

excluding

biogenic CO

; instead, it would require reporting of the total annual CO

emissions for each subpart,

including

biogenic CO

• 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 CO

emissions is optional for part 75 units that qualify for and elect to use the alternative CO

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 CO

emissions is not required for units subject to subpart D of part 98, and for part 75 units using the alternative CO

mass emissions reporting options in 40 CFR 98.33(a)(5). However, if the owner or operator elects to report biogenic CO

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 CO

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 CO

, although they retain the option to report biogenic CO

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

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 NO

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 mtCO

e 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 mtCO

e, 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 mtCO

e 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

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 CO

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

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.

• CH

and N

O calculations.

• CO

emissions from sorbent.

• Biogenic CO

emissions from biomass combustion.

• Fuel sampling for coal and fuel oil.

• Tier 3 sampling frequency for gaseous fuels.

• CO

emissions from blended fuel combustion.

• Use of consensus standard methods.

• CO

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 CO

emission factors.

• Table C-2 default CH

and N

O 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 CO

, CH

, and N

O 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 CO

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 CO

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 CO

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 CO

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 CO

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 CO

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 CO

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 fuel-derived gaseous fuels, and for biogas, when the Tier 2 methodology is used to calculate CO

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 CO

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 CO

CEMS to be used together with a stack gas flow rate monitor to measure CO

mass emissions. If the CO

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 CO

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 non-representative, due to changes in unit or process operation. The updated moisture value would be used in the subsequent CO

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 CO

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 CO

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 CO

is removed or chemically altered in a way that significantly changes the CO

concentration at the outlet of the unmonitored stack, compared to the outlet CO

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

40 CFR 98.33(a)(5) to clarify that the separate reporting of biogenic CO

is optional for units that are not subject to the Acid Rain Program, but are using Part 75 methodologies to calculate CO

mass emissions, as described in 40 CFR 98.33(a)(5)(i) through (a)(5)(iii). As discussed above, separate reporting of biogenic CO

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 CO

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 CO

mass emissions to continuously monitor and report the combined CO

mass emissions at the common stack (or duct), in lieu of separately monitoring and reporting the CO

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 CO

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

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 CO

mass emissions at the Tier 4 unit(s) before the effluent streams are combined together, or monitor the combined CO

mass emissions from all units at the common stack or duct. However, if it is not feasible to monitor the individual units, the combined CO

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 CO

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 CO

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 CO

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 CH

and N

O 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 CO

mass emissions, Equation C-8 is used to calculate CH

and N

O 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 CH

and N

O emissions. If multiple HHV values are obtained during the year, the arithmetic average would be used in Equation C-8.

Units that monitor heat input year-round according to 40 CFR Part 75 or that use the Tier 4 CO

calculation methodology are required to use Equation C-10 in Subpart C to calculate CH

and N

O 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 CH

and N

O 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 year-round using part 75 CEMS. For all multi-fuel units that use CEMS to comply with Part 98, subpart C requires the “best available information” to be used to determine the percentage of the annual unit heat input contributed by each type of fuel, for the purposes of calculating CH

and N

O mass emissions.

For part 75 units that use CEMS to quantify unit heat input, the fuel-specific annual heat input values needed for the CH

and N

O 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 fuel-specific 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

CFR 98.33(c)(4)(i), and we are proposing to allow it under 40 CFR 98.33(c)(4)(ii)(D) as an alternative for part 75 units, in cases where fuel-specific heat input values cannot be 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 CO

mass emissions from sorbent, except where the total CO

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 CO

(for instance, Ca(OH)

does not). Further, the 1.00 value of R in Equation C-11 applies only to SO

removal, indicating that one mole of CO

is produced for every mole of SO

removed. We have also been informed that CO

-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 CO

-producing sorbents. The term “R” would be redefined as the number of moles of CO

released upon capture of one mole of acid gas. When the sorbent is CaCO

, the value of R would be 1.00. For other CO

-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 CO

Emissions From Biomass Combustion.

In response to questions about the methodologies in 40 CFR 98.33(e) for calculating biogenic CO

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 CO

emissions. In general, biogenic CO

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 CO

emissions separate from total CO

emissions:

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

emissions would need to be reported separately from total CO

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 CO

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 CO

emissions.

2. If a unit is subject to Subpart C or D and uses the CO

mass emissions calculation methodologies in 40 CFR Part 75 to satisfy the Part 98 reporting requirements, the reporting of biogenic CO

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 CO

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 CO

emissions on units that use CEMS to measure the total CO

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 CO

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 CO

mass emissions, by:

1. Limiting it to cases where the CO

emissions measured by the CEMS are solely from combustion,

i.e.,

the stack gas contains no additional process CO

or CO

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 CO

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 CO

from the combustion of all fuels (as determined from the CEMS data). The difference is assumed to be the volume of biogenic CO

. However, this approach is only viable if all of the CO

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 CO

emissions or CO

emissions from sorbent in the stack effluent, the volumes of those CO

emissions would have to be subtracted from the total volume of CO

derived from the CEMS data in order to determine the biogenic CO

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 CO

volumes from sorbent or from non-combustion industrial processes. For these reasons, we are proposing restrictions “1” and “2” above on the use of the methodology in 40 CFR 98.33(e)(2).

For sources that are combusting MSW, we are proposing to amend 40 CFR 98.33(e)(3) to require the use of ASTM methods D7459-08 and D6866-08 quarterly, as described in 40 CFR 98.34(d), when any MSW is combusted, either as the primary fuel or as the only fuel with a biogenic component. We are proposing to further amend 40 CFR 98.33(e)(3) to allow the ASTM methods to be used, as described in 40 CFR 98.34(e), for any unit in which biogenic (or partly biogenic) fuels, and non-biogenic fuels are combusted, in any proportions.

We are also proposing to delete and reserve 40 CFR 98.33(e)(4) and the related subparagraphs. Although 40 CFR 98.33(e)(4) allows the ASTM methods to be used to determine biogenic CO

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 CO

mass emissions. The proposed amendments to 40 CFR 98.33(e)(3) described above would achieve the same intended purpose as 40 CFR 98.33(e)(4), without imposing this restriction, so 40 CFR 98.33(e)(4) is no longer needed.

Finally, we are proposing to amend 40 CFR 98.33(e)(5) so that it would also

apply to units that are using Tier 2 (Equation C-2a), as well as Tier 1 (Equation C-1), for calculating biogenic CO

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 CO

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 CO

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.

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 CO

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 CO

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 CO

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 CO

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 CO

emission factor would be calculated, using proposed Equation C-16. For Tier 1 applications, a heat-weighted default HHV would also have to be determined, using proposed Equation C-17.

In cases where a fuel blend consists of a mixture of fuel(s) listed in Table C-1 and fuel(s) not listed in Table C-1, calculation of CO

and other GHG emissions from combustion of the blend would be required only for the Table C-1 fuel(s), using the best available estimate of the mass or volume percentage(s) of the Table C-1 fuel(s) in the blend. In these cases, the use of Tier 1 would be required, with modifications to certain terms in Equations C-17 and

C-1, to account for the fact that the blend is not composed entirely of Table C-1 fuels. An example calculation is provided in proposed 40 CFR 98.34(a)(3)(iv).

For larger combustion units (heat input capacity greater than 250 mmBtu/hr) that do not qualify to use Tier 1 or 2, we are proposing that the owner or operator would use Tier 3 to calculate the CO

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 CH

and N

O 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 CH

and N

O 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 CH

and N

O 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 CH

and N

O 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 CH

and N

O emissions would be summed across all components, and these sums would be reported as the annual CH

and N

O 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).

Monitor Span Values.

The Tier 4 calculation method in 40 CFR 98.33(a)(4) requires a CO

concentration monitor and a stack gas flow rate monitor to measure CO

mass emissions. The CO

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 CO

monitor is a cylinder gas audit (CGA). The CGA checks the response of the CO

analyzer at two calibration gas concentrations,

i.e.,

one between 5 and 8 percent CO

and one between 10 and 14 percent CO

. These CO

concentration levels are appropriate for most stationary combustion applications. For example, a typical span value for a CO

monitor installed on a coal-fired boiler is 20 percent CO

; therefore, the CGA concentrations represent 25 to 40 percent of span and 50 to 70 percent of span. However, when CO

emissions from an industrial process (

e.g.,

cement manufacturing) are combined with combustion CO

emissions, the resultant CO

concentration in the stack gas can be substantially higher than for the combustion emissions alone. In such cases, a span value of 30 percent CO

(or higher) may be required.

When the CO

span exceeds 20 percent CO

, 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 CO

monitor to be performed using calibration gas concentrations of 40 to 60 percent of span and 80 to 100 percent of span, when the CO

span value is set higher than 20 percent CO

CEMS Data Validation.

The Tier 4 methodology in 40 CFR 98.33(a)(4) requires the use of CEMS to measure CO

mass emissions. For each unit operating hour, the CO

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

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 CO

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 CO

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 quality-assure the data.

Section 98.36 of subpart C provides several lists of data elements that must be reported for stationary combustion units. These lists are specific to the CO

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 CO

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 CO

e (

i.e.,

the sum of the CO

, CH

, and N

O 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 CH

and N

O 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 CH

and N

O 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 CO

emissions and CO

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 CO

emissions is optional for units using the CO

mass emissions calculation methods in 40 CFR Part 75.

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

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” CO

mass emissions to be reported instead of reporting the annual CO

mass emissions from fossil fuel combustion.

These revisions are being proposed because the total annual CO

mass emissions measured by CEMS sometimes includes CO

from sorbent or process CO

emissions in addition to CO

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

emissions in the flue gas stream. These units would be required only to report the combined annual non-biogenic CO

mass emissions, rather than having to separately account for the fossil CO

emissions. Tier 4 units that do not have any sorbent or process CO

emissions in the flue gas would be unaffected by these proposed revisions, because their non-biogenic CO

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 CO

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 CO

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 CO

emissions from all of the units in lieu of reporting CO

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 CO

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

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 CO

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 CO

emission factors for various types of fuel. These default values are needed to calculate CO

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 CO

emission factor in the Table. This emission factor is needed to apply the Tier 2 CO

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 CO

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 CO

emission factor and a default high heat value would be added to the Table for petroleum-derived ethanol. These would be the same as the default values for biomass-derived ethanol.

We are soliciting comment on these proposed amendments to Table C-1. Specifically, we request comment on: (1) The new and revised fuel categories; (2) the appropriateness of the HHVs and CO

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 CO

emission factors for those fuels should be.

Table C-2.

In the October 30, 2009 publication of Part 98, two essentially identical iterations of Table C-2 of Subpart C were printed. The first iteration of Table 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 right-hand column of the Table currently have an “underscore” character where there should be a minus sign, and one of the exponents is missing a zero.

Miscellaneous Proposed Revisions.

In addition to the more substantive proposed amendments to Subpart C, we are proposing to correct a number of typographical errors, and to re-word the rule text in a few places for added clarity. We are also proposing to amend 40 CFR 98.34(c) by adding the citations from 40 CFR Part 75 that pertain to the initial certification of Tier 4 moisture monitoring systems. Although these rule citations were inadvertently omitted from the October 30, 2009 publication of Part 98, we believe that Tier 4 sources understand that

all

required CEMS, including moisture monitoring systems, must be initially certified.

How Would These Amendments to Subpart C Apply to the 2011 GHG Emissions Reports

? EPA plans to address the comments on the proposed amendments to Subpart C and to publish the final amendments before the end of 2010. Therefore, reporters would be expected to use provisions of Part 98, as amended, to collect the relevant data and to calculate GHG emissions for the reports that are submitted 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 CO

emissions is optional for units using the CO

mass emissions calculation methodologies in 40 CFR Part 75.

• How CH

and N

O emissions are calculated for multi-fuel units that use the Tier 4 CO

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 CO

, CH

, and N

O 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 fuel-specific CH

and N

O 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 CO

, CH

, and N

O emissions from fossil fuel combustion.

• Remove the requirement for natural gas users to report their customer meter ID numbers.

• Emphasize that biogenic CO

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 CO

monitors to be set higher than 20 percent CO

if necessary, when process CO

and combustion CO

emissions exit to the atmosphere through a common stack.

• Allow the use of site-specific default moisture values for Tier 4 units that measure CO

concentration on a dry basis.

• Provide a new Tier 1 equation for calculating CO

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 portio

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