Proposed National Emission Standards for Hazardous Air Pollutants; and, in the Alternative, Proposed Standards of Performance for New and Existing Stationary Sources: Electric Utility Steam Generating Units

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ENVIRONMENTAL PROTECTION AGENCY 40 CFR Parts 60 and 63 [OAR-2002-0056; FRL-7606-3] RIN 2060-AJ65 Proposed National Emission Standards for Hazardous Air Pollutants; and, in the Alternative, Proposed Standards of Performance for New and Existing Stationary Sources: Electric Utility Steam Generating Units AGENCY:

Environmental Protection Agency (EPA).

ACTION:

Proposed rule.

SUMMARY:

In this document, EPA is proposing to: set national emission standards for hazardous air pollutants (NESHAP) pursuant to section 112 of the Clean Air Act (CAA); alternatively, to revise the regulatory finding that it made on December 20, 2000 (65 FR 79825) pursuant to CAA section 112(n)(1)(A); and if the December 2000 finding is revised as proposed herein, to set standards of performance for mercury (Hg) for new and existing coal-fired electric utility steam generating units (Utility Units), as defined in CAA section 112(a)(8), and for nickel (Ni) for new and existing oil-fired Utility Units pursuant to CAA section 111. The decision concerning which authority to base regulation of Hg and Ni emissions on, CAA section 112 or section 111, will depend upon whether EPA takes final action to revise the December 2000 section 112(n)(1)(A) finding in the manner described herein. In either event, however, EPA intends to require reductions in the emissions of Hg and Ni from coal- and oil-fired Utility Units, respectively. This action is one part of a broader effort to issue a coordinated set of emissions limitations for the power sector.

In December 2000, EPA found pursuant to CAA section 112(n)(1)(A) that regulation of coal- and oil-fired Utility Units under CAA section 112 is appropriate and necessary. Today's proposed section 112 “MACT” rule would require coal- and oil-fired Utility Units to meet hazardous air pollutant (HAP) emissions standards reflecting the application of the maximum achievable control technology (MACT) determined pursuant to the procedures set forth in CAA section 112(d)

that regulation of coal- and oil-fired Utility Units under CAA section 112 is appropriate and necessary. Today's proposed section 112 “MACT” rule would require coal- and oil-fired Utility Units to meet hazardous air pollutant (HAP) emissions standards reflecting the application of the maximum achievable control technology (MACT) determined pursuant to the procedures set forth in CAA section 112(d). The EPA also is co-proposing and soliciting comment on implementing a cap-and-trade program under section 112, similar to that being proposed under section 111 of the CAA.

Coal- and oil-fired Utility Units emit a wide variety of metal, organic, and inorganic HAP, depending on the type of fuel that is combusted. The proposed CAA section 112 MACT rule would limit emissions of Hg and Ni. Exposure to Hg and Ni above identified thresholds has been demonstrated to cause a variety of adverse health effects.

Today's proposed amendments to CAA section 111 rules would establish a mechanism by which Hg emissions from new and existing coal-fired Utility Units would be capped at specified, nation-wide levels. A first phase cap would become effective in 2010 and a second phase cap in 2018. Facilities would demonstrate compliance with the standard by holding one “allowance” for each ounce of Hg emitted in any given year. Allowances would be readily transferrable among all regulated facilities. We believe that such a “cap and trade” approach to limiting Hg emissions is the most cost effective way to achieve the reductions in Hg emissions from the power sector that are needed to protect human health and the environment.

th and the environment.

The added benefit of this cap-and-trade approach is that it dovetails well with the sulfur dioxide (SO 2 ) and nitrogen oxides (NO X ) Interstate Air Quality Rule (IAQR) published elsewhere in today's Federal Register . That proposed rule would establish a broadly-applicable cap and trade program that would significantly limit SO 2 and NO X emissions from the power sector. The advantage of regulating Hg at the same time and using the same regulatory mechanism as for SO 2 and NO X is that significant Hg emissions reductions can and will be achieved by the air pollution controls designed and installed to reduce SO 2 and NO X . In other words, significant Hg emissions reductions can be obtained as a “co-benefit” of controlling emissions of SO 2 and NO X . Thus, the coordinated regulation of Hg, SO 2 , and NO X allows Hg reductions to be achieved in a cost effective manner. This is consistent with Congress's intent expressed in CAA section 112(n), that EPA would regulate HAP emissions from Utility Units only after taking into account compliance with other CAA programs.

This action also proposes to add Performance Specification 12A, “Specification and Test Methods for Total Vapor Phase Mercury Continuous Emission Monitoring Systems in Stationary Sources” to 40 CFR part 60, appendix B, and to add one EPA method to 40 CFR part 63, appendix A: Method 324, “Determination of Vapor Phase Flue Gas Mercury Emissions from Stationary Sources Using Dry Sorbent Trap Sampling.”

DATES:

Comments. Submit comments on or before March 30, 2004.

Public Hearing. The EPA will be holding a public hearing on today's proposal during the public comment period. The details of the public hearing, including the time, date, and location, will be provided in a future Federal Register notice and announced on EPA's Web site for this rulemaking http://www.epa.gov/ttn/atw/combust/utiltox/utoxpg . The public hearing will provide interested parties the opportunity to present data, views, or arguments concerning the proposed rules. The EPA may ask clarifying questions during the hearing, but will not respond to the presentations or comments at that time. Written comments and supporting information submitted during the comment period will be considered with the same weight as any oral comments and supporting information presented at a public hearing.

ADDRESSES:

Comments. Comments may be submitted by mail (in duplicate, if possible) to EPA Docket Center (Air Docket), U.S. EPA West (6102T), Room B-108, 1200 Pennsylvania Ave., NW., Washington, DC 20460, Attention Docket ID No. OAR-2002-0056. By hand delivery/courier, comments may be submitted (in duplicate, if possible) to EPA Docket Center, Room B-108, U.S. EPA West, 1301 Constitution Ave., NW, Washington, DC 20460, Attention Docket ID No. OAR-2002-0056. Also, comments may be submitted electronically according to the detailed instructions as provided in the SUPPLEMENTARY INFORMATION section.

Docket. The official public docket is available for public viewing at the EPA Docket Center, EPA West, Room B-108, 1301 Constitution Ave., NW., Washington, DC 20460

. The details of the public hearing, including the time, date, and location, will be provided in a future Federal Register notice and announced on EPA's Web site for this rulemaking http://www.epa.gov/ttn/atw/combust/tuiltox/utoxpg .

Docket. The official public docket is available for public viewing at the EPA Docket Center, EPA West, Room B-108, 1301 Constitution Ave., NW., Washington, DC 20460.

FOR FURTHER INFORMATION CONTACT:

William Maxwell, Combustion Group (C439-01), Emission Standards Division, Office of Air Quality Planning and Standards, U.S. EPA, Research Triangle Park, NC 27711, telephone number (919) 541-5430, fax number (919) 541-5450, electronic mail (e-mail) address, maxwell.bill@epa.gov .

SUPPLEMENTARY INFORMATION:

Regulated Entities. Categories and entities potentially regulated by this action include the following:

Category NAICS code 1 Examples of potentially regulated entities Industry 221112 Fossil fuel-fired electric utility steam generating units. Federal government 2 221122 Fossil fuel-fired electric utility steam generating units owned by the Federal government. State/local/tribal government 2 221122 Fossil fuel-fired electric utility steam generating units owned by municipalities. 921150 Fossil fuel-fired electric utility steam generating units in Indian Country. 1 North American Industry Classification System. 2 Federal, State, or local government-owned and operated establishments are classified according to the activity in which they are engaged. This table is not intended to be exhaustive, but rather provides a guide for readers regarding entities likely to be regulated by this action. This table lists examples of the types of entities EPA is now aware could potentially be regulated by this action. Other types of entities not listed could also be affected

d establishments are classified according to the activity in which they are engaged. This table is not intended to be exhaustive, but rather provides a guide for readers regarding entities likely to be regulated by this action. This table lists examples of the types of entities EPA is now aware could potentially be regulated by this action. Other types of entities not listed could also be affected. To determine whether your facility, company, business, organization, etc., is regulated by this action, you should examine the applicability criteria in § 63.9981 of the proposed rule or §§ 60.45a and 60.46a of the proposed NSPS amendments. If you have any questions regarding the applicability of this action to a particular entity, consult the person listed in the preceding FOR FURTHER INFORMATION CONTACT section.

Docket. The EPA has established an official public docket for this action including both Docket ID No. OAR-2002-0056 and Docket ID No. A-92-55. The official public docket consists of the documents specifically referenced in this action, any public comments received, and other information related to this action. Not all items are listed under both docket numbers, so interested parties should inspect both docket numbers to ensure that they have received all materials relevant to the proposed rule. The official public docket is available for public viewing at the EPA Docket Center (Air Docket), EPA West, Room B-108, 1301 Constitution Ave., NW., Washington, DC. The EPA Docket Center Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays. The telephone number for the Reading Room is (202) 566-1744, and the telephone number for the Air Docket is (202) 566-1742. A reasonable fee may be charged for copying docket materials.

Electronic Access. You may access this Federal Register document electronically through the Internet under the Federal Register listings at http://www.epa.gov/fedrgstr/

y through Friday, excluding legal holidays. The telephone number for the Reading Room is (202) 566-1744, and the telephone number for the Air Docket is (202) 566-1742. A reasonable fee may be charged for copying docket materials.

Electronic Access. You may access this Federal Register document electronically through the Internet under the Federal Register listings at http://www.epa.gov/fedrgstr/.

An electronic version of the public docket is available through EPA's electronic public docket and comment system, EPA Dockets. You may use EPA Dockets at http://www.epa.gov/edocket/ to submit or view public comments, access the index listing of the contents of the official public docket, and access those documents in the public docket that are available electronically. Once in the system, select “search,” then key in the appropriate docket identification number.

Certain types of information will not be placed in EPA Dockets. Information claimed as confidential business information (CBI) and other information whose disclosure is restricted by statute, which is not included in the official public docket, will not be available for public viewing in EPA's electronic public docket. The EPA's policy is that copyrighted material will not be placed in EPA's electronic public docket but will be available only in printed paper form in the official public docket. To the extent feasible, publicly available docket materials will be made available in EPA's electronic public docket. When a document is selected from the index list in EPA Dockets, the system will identify whether the document is available for viewing in EPA's electronic public docket. Although not all docket materials may be available electronically, you may still access any of the publicly available docket materials through the EPA Docket Center

terials will be made available in EPA's electronic public docket. When a document is selected from the index list in EPA Dockets, the system will identify whether the document is available for viewing in EPA's electronic public docket. Although not all docket materials may be available electronically, you may still access any of the publicly available docket materials through the EPA Docket Center.

For public commenters, it is important to note that EPA's policy is that public comments, whether submitted electronically or on paper, will be made available for public viewing in EPA's electronic public docket as EPA receives them and without change, unless the comment contains copyrighted material, CBI, or other information whose disclosure is restricted by statute. When EPA identifies a comment containing copyrighted material, EPA will provide a reference to that material in the version of the comment that is placed in EPA's electronic public docket. The entire printed comment, including the copyrighted material, will be available in the public docket.

Public comments submitted on computer disks that are mailed or delivered to the docket will be transferred to EPA's electronic public docket. Public comments that are mailed or delivered to the Docket will be scanned and placed in EPA's electronic public docket. Where practical, physical objects will be photographed, and the photograph will be placed in EPA's electronic public docket along with a brief description written by the docket staff.

For additional information about EPA's electronic public docket, visit EPA Dockets online or see 67 FR 38102, May 31, 2002.

EPA's electronic public docket, visit EPA Dockets online or see 67 FR 38102, May 31, 2002.

You may submit comments electronically, by mail, or through hand delivery/courier. To ensure proper receipt by EPA, identify the appropriate docket identification number in the subject line on the first page of your comment. Please ensure that your comments are submitted within the specified comment period. Comments received after the close of the comment period will be marked “late.” The EPA is not required to consider these late comments. However, late comments may be considered if time permits.

Electronically. If you submit an electronic comment as prescribed below, EPA recommends that you include your name, mailing address, and an e-mail address or other contact information in the body of your comment. Also include this contact information on the outside of any disk or CD-ROM you submit, and in any cover letter accompanying the disk or CD-ROM. This ensures that you can be identified as the submitter of the comment and allows EPA to contact you in case EPA cannot read your comment due to technical difficulties or needs further information on the substance of your comment. The EPA's policy is that EPA will not edit your comment, and any identifying or contact information provided in the body of a comment will be included as part of the comment that is placed in the official public docket and made available in EPA's electronic public docket. If EPA cannot read your

Your use of EPA's electronic public docket to submit comments to EPA electronically is EPA's preferred method for receiving comments. Go directly to EPA Dockets at http://www.epa.gov/edocket and follow the online instructions for submitting comments. To access EPA's electronic public docket from the EPA Internet home page, select “Information Sources,” “Dockets,” and “EPA Dockets.” Once in the system, select “search,” and then key in Docket ID No. OAR-2002-0056

EPA electronically is EPA's preferred method for receiving comments. Go directly to EPA Dockets at http://www.epa.gov/edocket and follow the online instructions for submitting comments. To access EPA's electronic public docket from the EPA Internet home page, select “Information Sources,” “Dockets,” and “EPA Dockets.” Once in the system, select “search,” and then key in Docket ID No. OAR-2002-0056. The system is an anonymous access system, which means EPA will not know your identity, e-mail address, or other contact information unless you provide it in the body of your comment.

Comments may be sent by e-mail to a-and-r-docket@epa.gov, Attention Docket ID No. OAR-2002-0056. In contrast to EPA's electronic public docket, EPA's e-mail system is not an anonymous access system. If you send an e-mail comment directly to the Docket without going through EPA's electronic public docket, EPA's e-mail system automatically captures your e-mail address. E-mail addresses that are automatically captured by EPA's e-mail system are included as part of the comment that is placed in the official public docket and made available in EPA's electronic public docket.

You may submit comments on a disk or CD-ROM that you mail to the mailing address identified below. These electronic submissions will be accepted in WordPerfect or ASCII file format. Avoid the use of special characters and any form of encryption.

By Mail. Send your comments (in duplicate if possible) to EPA Docket Center (Air Docket), U.S. EPA West (6102T), Room B-108, 1200 Pennsylvania Ave., NW., Washington, DC, 20460, Attention Docket ID No. OAR-2002-0056. The EPA requests a separate copy also be sent to the contact person listed above ( see FOR FURTHER INFORMATION CONTACT ).

hington, DC, 20460, Attention Docket ID No. OAR-2002-0056. The EPA requests a separate copy also be sent to the contact person listed above ( see FOR FURTHER INFORMATION CONTACT ).

By Hand Delivery or Courier. Deliver your comments (in duplicate, if possible) to EPA Docket Center, Room B-102, U.S. EPA West, 1301 Constitution Ave., NW., Washington, DC, 20460, Attention Docket ID No. OAR-2002-0056. Such deliveries are only accepted during the Docket's normal hours of operation as identified above.

By Facsimile. Fax your comments to (202) 566-1741, Attention Docket ID No. OAR-2002-0056.

CBI. Do not submit information that you consider to be CBI electronically through EPA's electronic public docket or by e-mail. Send or deliver information identified as CBI only to the following address: Mr. William Maxwell, c/o OAQPS Document Control Officer (Room C404-2), U.S. EPA, Research Triangle Park, 27711, Attention Docket ID No. OAR-2002-0056. You may claim information that you submit to EPA as CBI by marking any part or all of that information as CBI (if you submit CBI on disk or CD-ROM, mark the outside of the disk or CD-ROM as CBI and then identify electronically within the disk or CD-ROM the specific information that is CBI). Information so marked will not be disclosed except in accordance with procedures set forth in 40 CFR part 2.

In addition to one complete version of the comment that includes any information claimed as CBI, a copy of the comment that does not contain the information claimed as CBI must be submitted for inclusion in the public docket and EPA's electronic public docket. If you submit the copy that does not contain CBI on disk or CD-ROM, mark the outside of the disk or CD-ROM clearly that it does not contain CBI. Information not marked as CBI will be included in the public docket and EPA's electronic public docket without prior notice. If you have any questions about CBI or the procedures for claiming CBI, please consult the person identified in the FOR FURTHER INFORMATION CONTACT section

at does not contain CBI on disk or CD-ROM, mark the outside of the disk or CD-ROM clearly that it does not contain CBI. Information not marked as CBI will be included in the public docket and EPA's electronic public docket without prior notice. If you have any questions about CBI or the procedures for claiming CBI, please consult the person identified in the FOR FURTHER INFORMATION CONTACT section.

Public Hearing. Persons interested in presenting oral testimony should contact Ms. Kelly Hayes, Combustion Group (C439-01), Emission Standards Division, Office of Air Quality Planning and Standards, U.S. EPA, Research Triangle Park, North Carolina 27711, telephone (919) 541-5578, at least 2 days in advance of the public hearing. Persons interested in attending the public hearing must also call Ms. Kelly Hayes to verify the time, date, and location of the hearing.

The public hearing will provide interested parties the opportunity to present data, views, or arguments concerning the proposed rule. The EPA will ask clarifying questions during the oral presentation but will not respond to the presentations or comments. Written statements and supporting information will be considered with the same weight as any oral statement and supporting information presented at a public hearing.

Outline. The information presented in this preamble is organized as follows:

I. Background Information A. What is the regulatory development background? 1. What is the statutory background? 2. What was the scope of, and basis for, EPA's December 2000 finding? B. What is the relationship between the proposed rule and other combustion rules? C. What are the health effects of HAP emitted from coal- and oil-fired Utility Units? II. Proposed National Emission Standards for Hazardous Air Pollutants for Mercury and Nickel from Stationary Sources: Electric Utility Steam Generating Units A. What is the statutory authority for the proposed section 112 rule? B. Summary of the Proposed Section 112 MACT Rule 1. What is the affected source? 2

es? C. What are the health effects of HAP emitted from coal- and oil-fired Utility Units? II. Proposed National Emission Standards for Hazardous Air Pollutants for Mercury and Nickel from Stationary Sources: Electric Utility Steam Generating Units A. What is the statutory authority for the proposed section 112 rule? B. Summary of the Proposed Section 112 MACT Rule 1. What is the affected source? 2. What are the proposed emission limitations? 3. What are the proposed testing and initial compliance requirements? 4. What are the proposed continuous compliance requirements? 5. What are the proposed notification, recordkeeping, and reporting requirements? C. Rationale for the Proposed Section 112 MACT Rule 1. How did EPA select the affected sources that would be regulated under the proposed rule? 2. How did EPA select the format of the proposed emission standards? 3. How did EPA determine the proposed MACT floor for existing units? 4. How did EPA derive the MACT floor for each subcategory? 5. How did EPA account for variability? 6. How did EPA consider beyond-the-floor options for existing units? 7. Should EPA consider different subcategories for coal- and oil-fired electric Utility Units? 8. How did EPA determine the proposed MACT floor for new units? 9. How did EPA consider beyond-the-floor for new units? 10. How did EPA select the proposed testing and monitoring requirements? 11. How did EPA determine compliance dates for the proposed rule? 12. How did EPA select the proposed recordkeeping and reporting requirements? 13. Will EPA allow for facility-wide averaging? III. Proposed Revision of Regulatory Finding on the Emissions of Hazardous Air Pollutants from Electric Utility Steam Generating Units A. What action is EPA taking today? B. Is it appropriate and necessary to regulate coal- and oil-fired Utility Units under section 112 based solely on emissions of non-Hg and non-Ni HAP? C

and reporting requirements? 13. Will EPA allow for facility-wide averaging? III. Proposed Revision of Regulatory Finding on the Emissions of Hazardous Air Pollutants from Electric Utility Steam Generating Units A. What action is EPA taking today? B. Is it appropriate and necessary to regulate coal- and oil-fired Utility Units under section 112 based solely on emissions of non-Hg and non-Ni HAP? C. What effect does today's proposal have on the December 2000 decision to list coal- and oil-fired Utility Units under section 112(c)? IV. Proposed Standards of Performance for Mercury and Nickel From New Stationary Sources and Emission Guidelines for Control of Mercury and Nickel From A. Background Information 1. What is the statutory authority for the proposed section 111 rulemaking? 2. What criteria are used in the development of NSPS? B. Proposed New Standards and Guidelines 1. What source category is affected by the proposed rulemaking? 2. What pollutants are covered by the proposed rulemaking? 3. What are the affected sources? 4. What emission limits must I meet? 5. What are the testing and initial compliance requirements? 6. What are the continuous compliance requirements? 7. What are the notification, recordkeeping, and reporting requirements? C. Rationale for the Proposed Subpart Da Standards 1. What is the rationale for the proposed subpart Da Hg and Ni standards? 2. What is the performance of control technology on Hg? 3. What is the performance of control technology on Ni? 4. What is the regulatory approach? 5. What are the subpart Da Hg and Ni emission standards? 6. How did EPA select the format for the proposed standards? 7. How did EPA determine testing and monitoring requirements for the proposed standards? 8. How did EPA determine the compliance times for the proposed standards? 9. How did EPA determine the required records and reports for the proposed standards? D. Rationale for the Proposed Hg Emission Guidelines 1. What is the authority for cap-and-trade under section 111(d)? 2

mat for the proposed standards? 7. How did EPA determine testing and monitoring requirements for the proposed standards? 8. How did EPA determine the compliance times for the proposed standards? 9. How did EPA determine the required records and reports for the proposed standards? D. Rationale for the Proposed Hg Emission Guidelines 1. What is the authority for cap-and-trade under section 111(d)? 2. What is the regulatory approach for existing and new sources? 3. What are the subpart Da Hg emission guidelines? 4. How did EPA select the format for the proposed emission guidelines? 5. How did EPA determine the emissions monitoring and reporting requirements for the proposed emission guidelines? 6. How did EPA determine the compliance times for the proposed emission guidelines? E. Rationale for the Proposed Ni Guidelines 1. What is the rationale for the proposed subpart Da Ni emission guidelines? 2. How did EPA address dual-fired (oil/natural gas) units? V. Impacts of the Proposed Rule A. What are the air impacts? B. What are the water and solid waste impacts? C. What are the energy impacts? D. What are the control costs? E. Can we achieve the goals of the proposed section 112 MACT rule in a less costly manner? F. What are the social costs and benefits of the proposed section 112 MACT rule? VI. Statutory and Executive Order Reviews A. Executive Order 12866: Regulatory Planning and Review B. Paperwork Reduction Act C. Regulatory Flexibility Act D. Unfunded Mandates Reform Act 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 and Safety Risks H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use I. National Technology Transfer and Advancement Act I. Background Information

A. What Is the Regulatory Development Background?

ltation and Coordination with Indian Tribal Governments G. Executive Order 13045: Protection of Children from Environmental Health and Safety Risks H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use I. National Technology Transfer and Advancement Act I. Background Information

A. What Is the Regulatory Development Background?

1. What Is the Statutory Background?

In the 1990 Amendments to the CAA, Congress substantially modified section 112 of the CAA, which is the provision of the CAA that expressly addresses HAP. Among other things, CAA section 112 sets forth a list of 188 HAP, to which EPA can add, and requires EPA to list categories and subcategories of “major sources” of listed pollutants. Congress defined “major source” as any stationary source 1 or group of stationary sources at a single location and under common control that emits or has the potential to emit 10 tons per year or more of any HAP or 25 tons per year or more of any combination of HAP. ( See CAA section 112(a)(1).)

1 A “stationary source” of hazardous air pollutants is any building, structure, facility or installation that emits or may emit any air pollutant. CAA Section 111(a)(3).

Section 112 further requires EPA to list categories and subcategories of area sources 2 provided those sources meet one of the following statutory criteria: (1) EPA determines that the category or subcategory of area sources presents a threat of adverse effects to human health or the environment in a manner that warrants regulation under CAA section 112; or (2) the category or subcategory of area sources falls within the purview of CAA section 112(k)(3)(B) (the Urban Area Source Strategy). Once EPA has listed a source category, whether it be a category of major sources or area sources, section 112(d) calls for the promulgation of emission standards.

2 A stationary source that is not a major source is an “area source.” CAA section 112(a)(2)

112; or (2) the category or subcategory of area sources falls within the purview of CAA section 112(k)(3)(B) (the Urban Area Source Strategy). Once EPA has listed a source category, whether it be a category of major sources or area sources, section 112(d) calls for the promulgation of emission standards.

2 A stationary source that is not a major source is an “area source.” CAA section 112(a)(2).

Congress, therefore, treated area sources differently from major sources in that categories of major sources are listed under CAA section 112 based solely on the number of tons of HAP emitted from sources in the category on an annual basis. By contrast, area source categories are not listed unless either the health and environmental effects warrant regulation under section 112, or reductions from the category are required to meet the requirements of the Urban Area Source Strategy.

Congress also treated Utility Units differently from major and area sources. ( See CAA section 112(n)(1)(A).) Specifically, Congress directed EPA to conduct a study that analyzed what hazards to public health resulting from emissions of HAP from Utility Units, if any, would reasonably be anticipated to occur following imposition of the other requirements of the CAA. Congress further directed EPA to report to it the results of such study. Finally, Congress directed EPA to determine whether, based on the results of the study, regulation of Utility Units under CAA section 112 was appropriate and necessary. Congress did not define the terms “appropriate” and “necessary,” but required that regulation of Utility Units under section 112 occur only if EPA found such regulation to be both appropriate and necessary.

2. What Was the Scope of, and Basis for, EPA's December 2000 Finding?

on of Utility Units under section 112 occur only if EPA found such regulation to be both appropriate and necessary.

2. What Was the Scope of, and Basis for, EPA's December 2000 Finding?

Scope of finding. On December 20, 2000, pursuant to CAA section 112(n)(1)(A), EPA determined that it was both appropriate and necessary to regulate coal- and oil-fired Utility Units under section 112 of the CAA. (65 FR 79826) Solely because of this finding, EPA added these units to the list of source categories under section 112(c) of the CAA. (Id.) In December 2000, EPA also concluded that the impacts associated with HAP emissions from natural-gas fired Utility Units were negligible and that regulation of such units under CAA section 112 was not appropriate or necessary.

Basis for finding. Nature of record. The EPA premised its December 2000 “appropriate and necessary” finding primarily on the results of the February 1998 “Study of Hazardous Air Pollutant Emissions from Electric Utility Steam Generating Units—Final Report to Congress” (Utility RTC). The EPA prepared this study pursuant to the terms of CAA section 112(n)(1)(A) and provided it to Congress. The EPA also based its December 2000 finding on certain information that it obtained following completion of the Utility RTC, which served only to confirm the conclusions of the Utility RTC.

In the Utility RTC, EPA examined 67 of the 188 HAP listed in section 112(b) of the CAA. These 67 HAP represent the pollutants EPA believes could potentially be emitted from Utility Units. The EPA assessed these HAP in terms of potential health hazards and

The Utility RTC identifies Hg as the HAP emitted from Utility Units that is of greatest concern from a public health perspective. (Executive Summary Utility RTC (“ES”), at 27.) The health effects of Hg exposure are presented elsewhere in this preamble

t the pollutants EPA believes could potentially be emitted from Utility Units. The EPA assessed these HAP in terms of potential health hazards and

The Utility RTC also included information indicating that Ni was the pollutant of concern from oil-fired Utility Units due to its high level of emissions from those units and the potential health effects arising from exposure to it. The health effects of Ni exposure also are presented elsewhere in this preamble.

As for the other non-Hg and non-Ni metallic HAP examined, EPA made the following conclusions. With regard to arsenic, a metal, EPA concluded that there were several uncertainties associated with both the cancer risk estimates from arsenic and the health effects data for arsenic, and that further analyses were needed to characterize the risks posed by arsenic emissions from Utility Units (ES at 21). As to lead and cadmium, which are also metals, EPA found that the emission quantities and inhalation risks of these HAP were low and did not warrant further evaluation (ES at 24). As for the remaining, non-Hg, non-Ni metallic HAP, EPA found that such pollutants posed no hazards to public health.

The EPA also examined HCl and HF, which are inorganic or acid gas HAP, and found no exceedances of the health benchmark for either substance (ES at 24)

found that the emission quantities and inhalation risks of these HAP were low and did not warrant further evaluation (ES at 24). As for the remaining, non-Hg, non-Ni metallic HAP, EPA found that such pollutants posed no hazards to public health.

The EPA also examined HCl and HF, which are inorganic or acid gas HAP, and found no exceedances of the health benchmark for either substance (ES at 24). As for dioxins, organic HAP, EPA concluded that the quantitative exposure and risk results for such HAP “d(id) not conclusively demonstrate the existence of health risks of concern associated with exposures to utility emissions either on a national scale or from any actual individual utility.” (Utility RTC at 11-5.) Finally, EPA concluded that emissions from Utility Units of the remaining HAP examined in the Study did not appear to be a concern for public health (65 FR 79827).

As part of the Utility RTC, EPA also examined several provisions of the CAA relating to electric utilities, including different sections of title I and title IV (Utility RTC, Ch.1). The EPA did not focus in the Utility RTC or the December 2000 finding, however, on whether section 111 of the CAA could be used specifically to regulate HAP from new and existing Utility Units, or the extent to which regulation under section 111 might address any HAP-related issues for Utility Units.

Following completion of the Utility RTC, EPA obtained additional information, which is summarized in EPA's December 20, 2000, notice. That information addressed Hg and methylmercury and confirmed the hazards to public health associated therewith. 4

nd confirmed the hazards to public health associated therewith. 4

4 Subsequent to issuance of the December 2000 Notice, EPA also conducted additional modeling for HCl, chlorine (Cl 2 ), and HF. Such modeling predicted concentrations of these HAP to be well below the relevant respiratory benchmark concentrations for the model plants examined. Hazard indices did not exceed 0.2 for any of these HAP. This modeling, therefore, confirmed the conclusion EPA reached in the Utility RTC, which is that inorganic or acid gas HAP from Utility Units, even in the absence of additional control measures, do not pose any hazards to the public health.

In addition, at the direction of Congress, EPA funded the National Academy of Sciences (NAS) to perform an independent evaluation of the available data related to the health impacts of methylmercury and provide recommendations for EPA's reference dose (RfD). An RfD is the amount of a chemical which, when ingested daily over a lifetime, is anticipated to be without adverse health effects to humans, including sensitive subpopulations. The NAS conducted an 18-month study of the available data on the health effects of methylmercury and provided EPA with a report of its findings in July 2000. Although the NAS recommended reliance on different studies for setting the methylmercury RfD, the value of EPA's RfD was found to be scientifically justifiable.

December 2000 finding. In December 2000, EPA found Hg to be the HAP emitted by Utility Units that was of greatest concern from a public health perspective because Hg is highly toxic, persistent, and bioaccumulates in food chains. The EPA also found that the data which it had gathered since the Utility RTC corroborated the previous nationwide Hg emissions estimate and confirmed that Utility Units are the largest anthropogenic source of Hg emissions in the United States. The EPA further found that there is a plausible link between methylmercury concentrations in fish and Hg emissions from coal-fired Utility Units (65 FR 79830)

e EPA also found that the data which it had gathered since the Utility RTC corroborated the previous nationwide Hg emissions estimate and confirmed that Utility Units are the largest anthropogenic source of Hg emissions in the United States. The EPA further found that there is a plausible link between methylmercury concentrations in fish and Hg emissions from coal-fired Utility Units (65 FR 79830).

Based on these findings, EPA stated that it was “appropriate to regulate HAP emissions from coal- and oil-fired electric utility steam generating units under section 112 of the CAA because, as documented in the utility RTC * * *, electric utility steam generating units are the largest domestic source of Hg emissions and Hg in the environment presents significant hazards to public health and the environment.” The EPA further noted that the National Academy of Science's study “confirm(ed) that Hg in the environment presents significant hazards to public health.”

The EPA also found that it was appropriate to regulate HAP emissions from coal- and oil-fired Utility Units under CAA section 112 because EPA had identified several control options that should reduce these emissions. ( See 65 FR 79830 (noting that “There are a number of alternative control strategies that are effective in controlling some of the HAP emitted from electric utility steam generating units.”) (emphasis added).) Thus, EPA's appropriateness finding in December 2000 focused on the significant health hazards associated with Hg and the availability of control strategies for certain HAP. The determination also rested, in part, however, on the uncertainties regarding the public health effects associated with HAP from oil-fired units

HAP emitted from electric utility steam generating units.”) (emphasis added).) Thus, EPA's appropriateness finding in December 2000 focused on the significant health hazards associated with Hg and the availability of control strategies for certain HAP. The determination also rested, in part, however, on the uncertainties regarding the public health effects associated with HAP from oil-fired units. ( See 65 FR 79830.) Although EPA did not specify in the December 2000 notice which HAP emissions from oil-fired units posed hazards to public health that warrant regulation, the record demonstrates that Ni was the HAP emitted by oil-fired units that was of greatest concern from a public health perspective because of the significant quantities of Ni emitted from oil-fired units and the scope and number of adverse health effects associated with Ni exposure. However, only 11 of the 137 oil-fired Utility Units considered in this finding posed an inhalation risk to human health greater than one in a million (1 × 10 − 6 ).

Finally, EPA stated that it was “necessary” to regulate HAP emissions from coal- and oil-fired Utility Units “because the implementation of other requirements under the CAA will not adequately address the serious public health and environmental hazards arising from such emissions.” ( See 65 FR 79830.)

The EPA had a desire to keep the regulatory process open and include all stakeholders involved. After discussion with the various stakeholder groups, it was decided that the most effective means of ensuring that inclusion was to form a Working Group under the existing Permits, New Source Review, and Toxics Subcommittee of the Clean Air Act Advisory Committee (CAAAC), chartered under the Federal Advisory Committee Act (FACA). The Working Group was designed and created to foster active participation from stakeholders, including environmental groups, the regulated industry, and State and local regulatory agencies

sion was to form a Working Group under the existing Permits, New Source Review, and Toxics Subcommittee of the Clean Air Act Advisory Committee (CAAAC), chartered under the Federal Advisory Committee Act (FACA). The Working Group was designed and created to foster active participation from stakeholders, including environmental groups, the regulated industry, and State and local regulatory agencies. Over the period of August 2001 to March 2003, the Working Group held 14 meetings and discussed a number of issues related to the proposed CAA section 112 rule.

To enhance the public's ability to participate, EPA maintained an Internet website to disseminate information on the Working Group and the regulatory process. The recommendations of the Working Group and other interested parties have been considered by EPA in developing the proposed rule for coal- and oil-fired Utility Units. On several occasions, EPA met with individual stakeholder groups to discuss the status of the proposed rulemaking and to hear their concerns and comments regarding the proposed CAA section 112 rule.

B. What Is the Relationship Between the Proposed Rule and Other Combustion Rules?

The EPA has previously developed two other combustion-related MACT standards in addition to today's proposed rule for coal- and oil-fired Utility Units. The EPA proposed standards for industrial, commercial, and institutional boilers and process heaters (IB) on January 13, 2003 (68 FR 1660) and promulgated standards for stationary combustion turbines (CT) in 2004. These regulations have been issued pursuant to CAA section 112, but not under CAA section 112(n)(1)(A), as is today's proposal, because section 112(n)(1)(A) is uniquely applicable to Utility Units as defined by the CAA.

All three of the rules pertain to HAP emission sources that combust fossil fuels for electrical power, process operations, or heating

stationary combustion turbines (CT) in 2004. These regulations have been issued pursuant to CAA section 112, but not under CAA section 112(n)(1)(A), as is today's proposal, because section 112(n)(1)(A) is uniquely applicable to Utility Units as defined by the CAA.

All three of the rules pertain to HAP emission sources that combust fossil fuels for electrical power, process operations, or heating. The differences among these rules are due to the size of the unit (megawatts electric (MWe) or British thermal unit per hour (Btu/hr)) they regulate, the boiler/furnace technology they employ, or the portion of their electrical output (if any) for sale to any utility power distribution systems.

Section 112(a)(8) of the CAA defines an “electric utility steam generating unit” as “any fossil fuel-fired combustion unit of more than 25 megawatts that serves a generator that produces electricity for sale.” A unit that cogenerates steam and electricity and supplies more than one-third of its potential electric output capacity and more than 25 MWe output to any utility power distribution system for sale is also considered a Utility Unit. All of the MWe ratings quoted in the proposed rule are considered to be the original nameplate rated capacity of the unit. Cogeneration is defined as the simultaneous production of power (electricity) and another form of useful thermal energy (usually steam or hot water) from a single fuel-consuming process. Today's proposed section 112 MACT rule would not regulate a unit that meets the definition of a Utility Unit but combusts natural gas greater than 98 percent of the time.

The CT rule regulates HAP emissions from all simple-cycle and combined-cycle turbines producing electricity or steam for any purpose. Because of their combustion technology, simple-cycle and combined-cycle turbines (with the exception of integrated gasification combined cycle (IGCC) units that burn gasified coal gas) are not considered Utility Units for purposes of today's proposed rule

he time.

Any combustion unit that produces steam to serve a generator that produces electricity exclusively for industrial, commercial, or institutional purposes is considered an IB unit. A fossil-fuel-fired combustion unit that serves a generator that produces electricity for sale is not considered to be a Utility Unit under the proposed rule if its size is less than or equal to 25 MWe. Also, a cogeneration facility that sells electricity to any utility power distribution system equal to more than one-third of their potential electric output capacity and more than 25 MWe is considered to be an electric utility steam generating unit. However, a cogeneration facility that meets the above definition of a Utility Unit during any portion of a year would be subject to the proposed rule.

Because of the similarities in the design and operational characteristics of the units that would be regulated by the different combustion rules, there are situations where coal- or oil-fired units potentially could be subject to multiple MACT rules. An example of this situation would be cogeneration units that are covered under the proposed IB rule, potentially meeting the definition of a Utility Unit, and vice versa. This might occur where a decision is made to increase/decrease the proportion of production output being supplied to the electric utility grid, thus causing the unit to exceed the IB/electric utility cogeneration criteria ( i.e. greater than one-third of its potential output capacity and greater than 25 MWe).

The EPA solicits comment on the extent to which this situation might occur

vice versa. This might occur where a decision is made to increase/decrease the proportion of production output being supplied to the electric utility grid, thus causing the unit to exceed the IB/electric utility cogeneration criteria ( i.e. greater than one-third of its potential output capacity and greater than 25 MWe).

The EPA solicits comment on the extent to which this situation might occur. Given the differences between rules, how should EPA address reclassification of the sources between the two rules, particularly with regard to initial and ongoing compliance requirements and schedules? (As noted above, EPA is proposing to consider as a Utility Unit any cogeneration unit that meets the definition noted earlier at any time during a year.)

Another situation could occur where one or more coal- or oil-fired Utility Unit(s) share an air pollution control device (APCD) and/or an exhaust stack with one or more similarly-fueled IB units. To demonstrate compliance with two different rules, the emissions have to either be apportioned to the appropriate source or the more stringent emission limit must be met. Data needed to apportion emissions are not currently required by the proposed rule or the proposed IB rule.

The EPA solicits comment on the extent to which this situation might occur. Given potential differences between rules, how should EPA address apportionment of the emissions to the individual sources with regard to initial and ongoing compliance requirements? The EPA specifically requests comment on the appropriateness of a mass balance-type methodology to determine pollutant apportionment between sources both pre-APCD and post-APCD.

C. What Are the Health Effects of HAP Emitted From Coal- and Oil-Fired Utility Units?

methodology to determine pollutant apportionment between sources both pre-APCD and post-APCD.

C. What Are the Health Effects of HAP Emitted From Coal- and Oil-Fired Utility Units?

Data collected during development of the proposed section 112 rule show that coal- and oil-fired Utility Units emit a wide variety of metal, organic, and inorganic HAP, depending on the type of fuel that is combusted. Today's proposed rules, both under CAA section 111 and 112, would protect air quality and promote the public health by reducing emissions of Hg and Ni from coal- and oil-fired Utility Units. Exposure to Hg and Ni at sufficiently high levels is associated with a variety of adverse health effects. The EPA cannot currently quantify whether, and the extent to which, the adverse health effects occur in the populations surrounding these facilities, and the contribution, if any, of the facilities to those problems. However, to the extent the adverse effects do occur, either of today's proposed actions would reduce emissions and subsequent exposures. Following is a summary of the health effects for the Hg and Ni emissions that would be reduced by either of the proposed rules.

Mercury. Mercury is a persistent, bioaccumulative toxic metal that exists in three forms: elemental Hg (Hg 0 ), inorganic Hg (Hg ++ ) compounds (primarily mercuric chloride), and organic Hg compounds (primarily methylmercury). Each form exhibits different health effects. Various major sources may release elemental or inorganic Hg; environmental methylmercury, the form of concern for this rulemaking, is typically formed by biological processes after Hg has precipitated from the air and deposited into water bodies.

Mercury is toxic to humans from both the inhalation and oral exposure routes. In the proposed rulemaking, we focus

Fish consumption dominates the pathway for human and wildlife exposure to methylmercury. There is a great deal of variability among individuals in fish consumption rates

ypically formed by biological processes after Hg has precipitated from the air and deposited into water bodies.

Mercury is toxic to humans from both the inhalation and oral exposure routes. In the proposed rulemaking, we focus

Fish consumption dominates the pathway for human and wildlife exposure to methylmercury. There is a great deal of variability among individuals in fish consumption rates. Critical elements in estimating methylmercury exposure and risk from fish consumption include the species of fish consumed, the concentrations of methylmercury in the fish, the quantity of fish consumed, and how frequently the fish is consumed. The typical U.S. consumer eating a wide variety of fish from restaurants and grocery stores is not in danger of consuming harmful levels of methylmercury from fish and is not advised to limit fish consumption. Those who regularly and frequently consume large amounts of fish, either marine or freshwater, are more exposed. Because the developing fetus may be the most sensitive to the effects from methylmercury, women of child-bearing age are regarded as the population of greatest interest. The EPA, Food and Drug Administration, and many States have issued fish consumption advisories to inform this population of protective consumption levels.

The EPA's 1997 Mercury Study RTC supports a plausible link between anthropogenic releases of Hg from industrial and combustion sources in the U.S. and methylmercury in fish. However, these fish methylmercury concentrations also result from existing background concentrations of Hg (which may consist of Hg from natural sources, as well as Hg which has been re-emitted from the oceans or soils) and deposition from the global reservoir (which includes Hg emitted by other countries). Given the current scientific understanding of the environmental fate and transport of this element, it is not possible to quantify how much of the methylmercury in fish consumed by the U.S. population is contributed by U.S

from natural sources, as well as Hg which has been re-emitted from the oceans or soils) and deposition from the global reservoir (which includes Hg emitted by other countries). Given the current scientific understanding of the environmental fate and transport of this element, it is not possible to quantify how much of the methylmercury in fish consumed by the U.S. population is contributed by U.S. emissions relative to other sources of Hg (such as natural sources and re-emissions from the global pool). As a result, the relationship between Hg emission reductions from Utility Units and methylmercury concentrations in fish cannot be calculated in a quantitative manner with confidence. In addition, there is uncertainty regarding over what time period these changes would occur. This is an area of ongoing study.

Given the present understanding of the Hg cycle, the flux of Hg from the atmosphere to land or water at one location is comprised of contributions from: the natural global cycle; the cycle perturbed by human activities; regional sources; and local sources. Recent advances allow for a general understanding of the global Hg cycle and the impact of the anthropogenic sources. It is more difficult to make accurate generalizations of the fluxes on a regional or local scale due to the site-specific nature of emission and deposition processes. Similarly, it is difficult to quantify how the water deposition of Hg leads to an increase in fish tissue levels. This will vary based on the specific characteristics of the individual lake, stream, or ocean.

As part of routine U.S. population surveillance, the U.S. Centers for Disease Control (CDC) assessed Hg concentrations in blood of over 1,500 women of child-bearing age. A recent analysis of these data reported that about 8 percent of these women of child-bearing age have levels of Hg in their blood that are at or above the U.S. EPA's RfD. The CDC also surveyed the same group of women about their eating habits

utine U.S. population surveillance, the U.S. Centers for Disease Control (CDC) assessed Hg concentrations in blood of over 1,500 women of child-bearing age. A recent analysis of these data reported that about 8 percent of these women of child-bearing age have levels of Hg in their blood that are at or above the U.S. EPA's RfD. The CDC also surveyed the same group of women about their eating habits. The surveyed women reported eating shrimp and tuna more frequently than other fish and shellfish options. Hg concentrations in seafood may be largely responsible for elevated levels of Hg in U.S. women of child-bearing age. We have little information about how Hg emissions from U.S. power plants may affect Hg concentrations in shrimp, tuna, and other marine fish. We seek comment on this issue and in particular, any data or other information that would allow us to better estimate the extent to which today's proposal would reduce blood Hg concentrations in U.S. women.

Recent estimates (which are highly uncertain) of annual total global Hg emissions from all sources (natural and anthropogenic) are about 5,000 to 5,500 tons per year (tpy). Of this total, about 1,000 tpy are estimated to be natural emissions and about 2,000 tpy are estimated to be contributions through the natural global cycle of re-emissions of Hg associated with past anthropogenic activity. Current anthropogenic emissions account for the remaining 2,000 tpy. Point sources such as fuel combustion; waste incineration; industrial processes; and metal ore roasting, refining, and processing are the largest point source categories on a world-wide basis. Given the global estimates noted above, U.S. anthropogenic Hg emissions are estimated to account for roughly 3 percent of the global total, and U.S. utilities are estimated to account for about 1 percent of total global emissions. (Utility RTC at 7-1 to 7-2.)

Nickel. Nickel is a natural element of the earth's crust; therefore, small amounts are found in food, water, soil and air

orld-wide basis. Given the global estimates noted above, U.S. anthropogenic Hg emissions are estimated to account for roughly 3 percent of the global total, and U.S. utilities are estimated to account for about 1 percent of total global emissions. (Utility RTC at 7-1 to 7-2.)

Nickel. Nickel is a natural element of the earth's crust; therefore, small amounts are found in food, water, soil and air. Food is the major source of Ni exposure. Ni is an essential element in some animal species. Individuals may also be exposed to Ni if they are employed in occupations involved in Ni production, processing, and use, or through contact with every day items such as Ni-containing jewelry and stainless steel cooking and eating utensils, and by smoking tobacco. The route of human exposure to Ni that we are concerned with in this rulemaking is Ni that is found in ambient air at very low levels as a result of releases from oil-fired Utility Units. The differing forms of Ni have varying levels of toxicity. There is great uncertainty about the different species of Ni emitted by Utility Units.

Respiratory effects, including a type of asthma specific to Ni, decreased lung function and bronchitis have been reported in humans who have been occupationally exposed to high-levels of Ni in air. Animal studies have reported effects on the lungs and immune system from inhalation exposure to soluble and insoluble Ni compounds (nickel oxide, subsulfide, sulfate heptahydrate). Soluble Ni compounds are more toxic to the respiratory tract than less soluble compounds. The EPA has not established a reference concentration (RfC)for Ni. No information is available regarding the reproductive or developmental effects of Ni in humans, but animal studies have reported such effects, although a consistent dose-response relationship has not been seen. Human and animal studies have reported an increased risk of lung and nasal cancers from exposure to Ni refinery dusts and Ni subsulfide

t established a reference concentration (RfC)for Ni. No information is available regarding the reproductive or developmental effects of Ni in humans, but animal studies have reported such effects, although a consistent dose-response relationship has not been seen. Human and animal studies have reported an increased risk of lung and nasal cancers from exposure to Ni refinery dusts and Ni subsulfide. The EPA has classified Ni carbonyl as a Group B2, probable human carcinogen based on lung tumors in animals. ( see ).

We ask for comment on all aspects of our proposed revised determination that it is necessary and appropriate to regulate Ni emissions from oil-fired Utility Units under section 112. In particular, we ask for comments and additional information related to the speciation of Ni compounds directly emitted by oil-fired Utility Units and those that may be formed through atmospheric transformation, as well as information on potential health effects. We also ask commenters—especially current owners and operators of potentially affected oil-fired units—to provide information on the current operating status and anticipated mode of operation in the future of potentially affected oil-fired Utility Units, including current control technology. To the extent possible, we would like to have up-to-date information on fuel use, emissions, stack parameters and other location-specific data that would be relevant to the assessment of emissions, dispersion, and ambient air quality. We also ask for comment on our finding in the Utility RTC that only 11 of 137 oil-fired Utility Units considered in the Utility RTC posed an inhalation risk to human health greater than one in a million (1 × 10 − 6 ) and whether data exists as to whether emissions from these plants no longer pose such risk.

II. Proposed National Emission Standards for Hazardous Air Pollutants for Mercury and Nickel From Stationary Sources: Electric Utility Steam Generating Units

f 137 oil-fired Utility Units considered in the Utility RTC posed an inhalation risk to human health greater than one in a million (1 × 10 − 6 ) and whether data exists as to whether emissions from these plants no longer pose such risk.

II. Proposed National Emission Standards for Hazardous Air Pollutants for Mercury and Nickel From Stationary Sources: Electric Utility Steam Generating Units

A. What Is the Statutory Authority for the Proposed Section 112 Rule?

Section 112 of the CAA requires that EPA promulgate regulations requiring the control of HAP emissions from listed categories of sources. The control of HAP is typically achieved through promulgation of emission standards under sections 112(d) and (f) of the CAA and, in appropriate circumstances, work practice standards under section 112(h) of the CAA.

Section 112(n)(1)(A), which provides the authority for today's proposed section 112 rule, states as follows:

The Administrator shall perform a study of the hazards to public health reasonably anticipated to occur as a result of emissions by electric utility steam generating units of pollutants listed under subsection (b) after imposition of the requirements of this Act. The Administrator shall report the results of this study to the Congress within 3 years after the date of the enactment of the Clean Air Act Amendments of 1990. The Administrator shall develop and describe in the Administrator's report to Congress alternative control strategies for emissions which may warrant regulation under this section. The Administrator shall regulate electric utility steam generating units under this section, if the Administrator finds such regulation is appropriate and necessary after considering the results of the study required by this subparagraph. By its express terms, section 112(n)(1)(a) applies only to Utility Units

native control strategies for emissions which may warrant regulation under this section. The Administrator shall regulate electric utility steam generating units under this section, if the Administrator finds such regulation is appropriate and necessary after considering the results of the study required by this subparagraph. By its express terms, section 112(n)(1)(a) applies only to Utility Units. It establishes certain predicates and requirements that are uniquely applicable to the regulation of Utility Units, and that have not been the subject of previous EPA regulatory decisions under section 112. In the circumstances presented here, and as discussed below, EPA interprets section 112(n)(1)(A) only to authorize the Agency to promulgate section 112 standards for Utility Units with respect to HAP emissions from such units that are reasonably anticipated to result in a hazard to public health after imposition of the other requirements of the CAA. To the extent section 112 can be interpreted as authorizing but not requiring EPA to go beyond that, and to promulgate section 112 standards for HAP emissions that are not reasonably anticipated to result in a hazard to public health, EPA has decided not to do so. Section 112(n)(1)(a) contains four basic instructions to EPA. First, EPA must prepare a study on “the hazards to public health reasonably anticipated to occur as a result of emissions by electric utility steam generating units of * * * [HAP] * * * after imposition of the requirements of this Act,” and submit the results in a report to Congress. Second, EPA must develop alternative control strategies for HAP emissions from Utility Units and describe them in the report. Third, and “after considering the results of the study required by” section 112(n)(1)(A), the EPA may determine whether regulation of Utility Units under section 112 is “appropriate and necessary.” Finally, if EPA determines that regulation under section 112 is appropriate and necessary, EPA must promulgate such regulations

gies for HAP emissions from Utility Units and describe them in the report. Third, and “after considering the results of the study required by” section 112(n)(1)(A), the EPA may determine whether regulation of Utility Units under section 112 is “appropriate and necessary.” Finally, if EPA determines that regulation under section 112 is appropriate and necessary, EPA must promulgate such regulations.

We carried out our obligations with respect to the first of these instructions when we completed and submitted to Congress in February 1998 the Utility RTC. The Utility RTC did not expressly state conclusions about any HAP, other than Hg, that was known to be emitted from coal-fired Utility Units. The RTC also included information indicating that Ni emissions from oil-fired Utility Units are of concern. Additionally, the ICR conducted in 1999 served to collect data and inform the EPA further only with respect to Hg emissions from coal-fired units, the pollutant of greatest concern in the health-based Utility RTC.

The Utility RTC also carried out a portion of the second instruction—the development of alternative control strategies. Later in this notice, we will discuss additional alternative control strategies.

We carried out the third step in the section 112(n)(1)(A) process when, on December 20, 2000, EPA published a “Regulatory Finding on the Emissions of Hazardous Air Pollutants From Electric Utility Steam Generating Units.” (65 FR 79825) We determined at that time that it was appropriate to regulate HAP emissions from coal- and oil-fired Utility Units because: (1) Such units “are the largest domestic source of [Hg] emissions, and [Hg] in the environment presents significant hazards to public health and the environment;” and (2) we had “identified a number of control options which EPA anticipates will effectively reduce HAP emissions from such units.” Id. at 79830

t was appropriate to regulate HAP emissions from coal- and oil-fired Utility Units because: (1) Such units “are the largest domestic source of [Hg] emissions, and [Hg] in the environment presents significant hazards to public health and the environment;” and (2) we had “identified a number of control options which EPA anticipates will effectively reduce HAP emissions from such units.” Id. at 79830. The EPA also found that “regulation of HAP emissions from natural gas-fired electric utility steam generating units is not appropriate or necessary because the impacts due to HAP emissions from such units are negligible based on the results of the study documented in the [U]tility RTC.” Id. at 79831. We have found no reason to reconsider or revise that finding, and therefore today's proposed section 112 rule does not address gas-fired Utility Units. 5

5 As EPA stated in the December 2000 finding, it does not believe that the definition of electric utility steam generating unit found in section 112(a)(8) of the Act encompasses stationary combustion turbines. 65 FR 79831. Therefore, today's proposed section 112 regulation does not address stationary combustion turbines. As further discussed elsewhere in this preamble, stationary combustion turbines are covered under the combustion turbine MACT standard.

Thus, EPA's appropriateness finding in December 2000 focused on the significant health hazards associated with Hg and the availability of control strategies for certain HAP from coal-fired Utility Units. The finding also rested, in part, however, on the uncertainties regarding the public health effects associated with HAP from oil-fired units. Id. Although EPA did not specify in the December 2000 finding which HAP emissions from oil-fired units posed hazards to public health, the record demonstrates that Ni was the HAP of greatest concern from a public health perspective because of the quantities of Ni emitted from oil-fired Utility Units and the scope and number of adverse health effects associated with Ni exposure

rom oil-fired units. Id. Although EPA did not specify in the December 2000 finding which HAP emissions from oil-fired units posed hazards to public health, the record demonstrates that Ni was the HAP of greatest concern from a public health perspective because of the quantities of Ni emitted from oil-fired Utility Units and the scope and number of adverse health effects associated with Ni exposure.

Our December 2000 finding stated that it was necessary to regulate HAP Id. at 79830.

While the December 2000 finding recounts at length the Agency's analysis and conclusions concerning the health risks from Hg exposure, it does not expressly state findings about health risks that are presented by other HAP emissions from Utility Units.

With today's notice, EPA is proposing to carry out the fourth of the four instructions in section 112(n)(1)(A)—that is, EPA is proposing to regulate Utility Units under section 112. In doing so, a threshold question is presented as to whether EPA must regulate the two HAP that were the primary focus of the step 2 finding, or whether it must regulate emissions of all HAP listed in section 112(b). Section 112(n)(1)(A) provides no express direction to EPA as to the HAP that should be addressed if we determine that regulation of Utility Units under section 112 is appropriate and necessary.

The EPA interprets section 112(n)(1)(A) as only authorizing regulation of Utility Units under section 112 with respect to HAP emissions from such units that EPA has determined are “appropriate and necessary” to regulate under section 112 because they are reasonably anticipated to result in a hazard to public health even after imposition of the other requirements of the CAA. Because EPA's December 2000 determination only made such a finding as to, at most, Hg emissions from coal-fired units and Ni emissions from oil-fired units, today's section 112 proposal only addresses those HAP emissions from the respective units

er section 112 because they are reasonably anticipated to result in a hazard to public health even after imposition of the other requirements of the CAA. Because EPA's December 2000 determination only made such a finding as to, at most, Hg emissions from coal-fired units and Ni emissions from oil-fired units, today's section 112 proposal only addresses those HAP emissions from the respective units.

As explained above, section 112(n)(1)(A) sets forth a regulatory scheme that is predicated on the completion of a study of hazards to public health. The EPA is to develop and describe in the report “alternative control strategies for emissions which may warrant regulation under this section,” and then may determine regulation of the source category “is appropriate and necessary after considering the results of the study.” Fairly read, this section requires EPA to narrowly focus any regulation it may promulgate pursuant to this authority. Indeed, an interpretation of section 112(n)(1)(A) that it automatically requires EPA to regulate HAP emissions from Utility Units for which no health hazard had been found would effectively read out of the statute much of the language set forth in this section and render superfluous much of the section 112(n)(1)(A) processes and requirements.

More specifically, the study that EPA is required to perform is to address the “hazards to public health reasonably anticipated to occur as a result of” HAP emissions by Utility Units. The EPA is authorized to regulate under section 112 only if the Agency “finds such regulation is appropriate and necessary after considering the results of the study required by this subparagraph .” (Emphasis added.) Because the decision to regulate is expressly linked to the results of the study, it is reasonable to interpret section 112(n)(1)(A) as authorizing EPA to promulgate section 112 emissions regulations for Utility Units only with respect to the HAP that the EPA has determined are appropriate and necessary to regulate under this section

of the study required by this subparagraph .” (Emphasis added.) Because the decision to regulate is expressly linked to the results of the study, it is reasonable to interpret section 112(n)(1)(A) as authorizing EPA to promulgate section 112 emissions regulations for Utility Units only with respect to the HAP that the EPA has determined are appropriate and necessary to regulate under this section. Furthermore, EPA is directed to develop and describe “alternative control strategies for emissions which may warrant regulation under this section .” (Emphasis added.) The emphasized phrase signals that an “appropriate and necessary” finding under section 112(n)(1)(A) does not require EPA to regulate emissions of all HAP from Utility Units once an “appropriate and necessary” finding as to at least one HAP has been made. In fact, that phrase has no meaning at all if EPA automatically is required to regulate all HAP from electric utility steam generating units once EPA makes an “appropriate and necessary” finding. The EPA believes the better interpretation of this language is that an appropriate and necessary finding can be made as to emissions of some HAP but not others, and trigger a requirement to promulgate section 112 regulations only as to the specific HAP for which the Agency has made the “appropriate and necessary” finding.

It might be argued that, even though our section 112(n)(1)(A) finding was based on concern about hazards to human health only from particular HAP, that the “under this section” phrase means that once EPA makes an “appropriate and necessary” finding with respect to the emissions of any one HAP, EPA must regulate all HAP listed in CAA section 112(b). That, in fact, is what EPA is required to do with respect to source categories other than Utility Units ( i.e. , source categories to which section 112(n)(1)(A) does not apply). See National Lime Association v. EPA, 223 F.3d 625 (D.C. Cir. 2000).

The EPA rejects such an interpretation of section 112(n)(1)(A)

to the emissions of any one HAP, EPA must regulate all HAP listed in CAA section 112(b). That, in fact, is what EPA is required to do with respect to source categories other than Utility Units ( i.e. , source categories to which section 112(n)(1)(A) does not apply). See National Lime Association v. EPA, 223 F.3d 625 (D.C. Cir. 2000).

The EPA rejects such an interpretation of section 112(n)(1)(A). As explained above, EPA believes that interpreting section 112(n)(1)(A) in this manner would ignore much of the language set forth in that section, and would render superfluous the section's processes and requirements. By contrast, EPA's interpretation gives meaning to all of the words of section 112(n)(1)(A) and is consistent with requiring regulation under section 112 only of those HAP emissions from Utility Units that are identified as appropriate and necessary to regulate under section 112 because they are reasonably anticipated to result in a hazard to public health after imposition of the other requirements of the CAA.

Our interpretation of section 112(n)(1)(A) is supported by the legislative history of this section. The House version of what became section 112(n)(1)(A) was adopted in lieu of the Senate provision. Senate Bill S. 1630, which contained the version that was not adopted, would have required regulation of HAP from Utility Units under section 112(d), notwithstanding the results of certain mandated studies. The House language, by contrast, did not presume that regulation was needed and certainly did not require that EPA regulate all HAP emissions from Utility Units if it regulated any. “[I]f the Administrator regulates any of these units, he may regulate only those units that he determines—after taking into account compliance with all provisions of the Act and any other Federal, State or local regulation and voluntary emission reductions—have been demonstrated to cause a significant threat of adverse effects on the public health.” 136 Cong. Rec. E3670, E3671 (Nov. 2, 1990) (statement of Cong. Oxley)

or regulates any of these units, he may regulate only those units that he determines—after taking into account compliance with all provisions of the Act and any other Federal, State or local regulation and voluntary emission reductions—have been demonstrated to cause a significant threat of adverse effects on the public health.” 136 Cong. Rec. E3670, E3671 (Nov. 2, 1990) (statement of Cong. Oxley).

Finally, even if it is possible to construe section 112(n)(1)(A) as allowing EPA to regulate Utility Unit emissions of all HAP listed in section 112(b) once the EPA has made an “appropriate and necessary” finding under section 112(n)(1)(A) with respect to any one or more HAP, we still believe that the better interpretation and application of that section is for EPA only to regulate HAP emissions that EPA has determined are “appropriate and necessary” to regulate under section 112 after imposition of the other requirements of the CAA. The EPA believes it would not be consistent with the policy Congress established when it enacted a separate section 112(n)(1)(A) for Utility Units, and required EPA to conduct a public health study and make a determination of appropriateness and necessity, for EPA to decide that utilities simply should be subject to the same types of regulation and in the

In developing today's proposed section 112 MACT rule, EPA has decided, as one regulatory option, to employ the section 112(d) process and propose a MACT standard. This is the result of EPA's having accompanied its December 2000 finding with a decision to list coal-fired and oil-fired Utility Units under section 112(c) of the CAA (65 FR 79825, 79830, December 20, 2000).

ion 112(c) of the CAA (65 FR 79825, 79830, December 20, 2000).

A standard developed pursuant to section 112(d) must reflect the maximum degree of reductions in emissions of HAP that is achievable taking into consideration the cost of achieving emissions reductions, any non-air-quality health and environmental impacts, and energy requirements. This level of control is commonly referred to as MACT. The MACT standards can be based on the emissions reductions achievable through application of measures, processes, methods, systems, or techniques including, but not limited to: (1) Reducing the volume of, or eliminating emissions of, such pollutants through process changes, substitutions of materials, or other modifications; (2) enclosing systems or processes to eliminate emissions; (3) collecting, capturing, or treating such pollutants when released from a process, stack, storage or fugitive emission point; (4) implementing design, equipment, work practices, or operational standards as provided in subsection 112(h) of the Act; or (5) a combination of the above.

For new sources, MACT standards cannot be less stringent than the emission control achieved in practice by the best-controlled similar source. The MACT standards for existing sources can be less stringent than standards for new sources, but they cannot be less stringent than the average emission limitation achieved by the best performing 12 percent of existing sources (for which the Administrator has emissions information) for categories and subcategories with 30 or more sources, or the best-performing 5 sources for categories or subcategories with fewer than 30 sources.

sources, or the best-performing 5 sources for categories or subcategories with fewer than 30 sources.

Even though EPA has developed today's proposed section 112 MACT rule pursuant to section 112(d)'s procedures and standards, section 112(n)(1)(A) expressly calls for EPA to develop “alternative control strategies” for the regulation of HAP emissions that “may warrant regulation” under section 112. In addition, section 112(n)(1)(A) specifies that any regulation should be “appropriate and necessary” in light of “hazards to public health reasonably expected to occur”—a departure from the traditional section 112(d) approach applicable to other types of sources. As set forth in the second part of today's notice, EPA is proposing to revise the December 2000 regulatory finding, to remove coal- and oil-fired Utility Units from the section 112(c) list, and instead to regulate Hg emissions from coal-fired Utility Units and Ni emissions from oil-fired units pursuant to existing authority in section 111 of the Act.

But as an alternative to revising the December 2000 finding and regulating under section 111, EPA believes it also has authority to leave the December 2000 “appropriate and necessary” finding in place, and to proceed to regulate under section 112(n) of the Act. In that event, EPA could promulgate, under section 112(n)(1)(A), a cap-and-trade program for Hg somewhat like the one that EPA is today proposing pursuant to CAA section 111. Therefore, and as another alternative, EPA also is proposing in today's notice to remove coal-fired Utility Units from the section 112(c) list, and to promulgate pursuant to section 112(n)(1)(A) a cap-and-trade program for Hg from coal-fired Utility Units.

ion 112(c) list, and to promulgate pursuant to section 112(n)(1)(A) a cap-and-trade program for Hg from coal-fired Utility Units.

In implementing this program under section 112, EPA would adopt a cap that reflects the projected Hg emissions that would occur under the section 112 MACT approach, which EPA currently projects to be 34 tons per year under the MACT proposal set forth in today's notice. The EPA would apportion this cap level of annual emissions across coal-fired units using the proposed MACT emission limits presented in Tables 1 and 2 and the proportionate share of their baseline heat input to total heat input of all affected units. Alternatively, EPA would apportion this cap level of annual emissions across all coal-fired Utility Units in accordance with the emission guidelines associated with the section 111 cap-and-trade proposal, contained in today's proposal. The EPA would implement a MACT cap-and-trade rule using a model trading rule similar to the model rule that we would use for our section 111 trading proposal. The EPA explains below its interpretation of CAA section 112 and why these trading approaches are permissible under section 112, and solicits comment on these approaches.

Section 112(n), which is quoted in part above, provides EPA's authority to regulate HAP emissions from Utility Units. By its express terms, section 112(n)(1)(A) applies only to such units and establishes certain predicates and requirements that are uniquely applicable to the regulation of this source category. In the typical cases of regulating HAP from other source categories, EPA's regulatory authority is derived from section 112(d), which prescribes a relatively rigid, plant-by-plant, MACT approach. By contrast, section 112(n) can be interpreted to authorize a more flexible, risk-based approach; there is nothing in section 112(n)(1)(A) that requires an “appropriate and necessary” finding to result in a section 112(c) listing or regulation under section 112(d)

egories, EPA's regulatory authority is derived from section 112(d), which prescribes a relatively rigid, plant-by-plant, MACT approach. By contrast, section 112(n) can be interpreted to authorize a more flexible, risk-based approach; there is nothing in section 112(n)(1)(A) that requires an “appropriate and necessary” finding to result in a section 112(c) listing or regulation under section 112(d).

While section 112(d) mandates regulation of all HAP emissions based on the emissions limitations achieved by similar sources, section 112(n) calls for regulation of Utility Unit HAP emissions as EPA determines is “appropriate and necessary after considering the results of the study” of public health hazards reasonably anticipated to occur from those Utility Unit HAP emissions. Congress provided EPA with distinct regulatory authority to address HAP emissions from Utility Units “because of the logic of basing any decision to regulate on the results of scientific study and because of the emission reductions that will be achieved and the extremely high costs that electric generators will face under other provisions of the new Clean Air Act Amendments.” 136 Cong. Rec. E3670, E3671 (Nov. 2, 1990) (statement of Cong. Oxley).

Congress’s intent to authorize EPA to regulate Utility Unit HAP emissions in ways other than with the prescriptive requirements of section 112(d) is indicated by the section 112(n) requirement that EPA develop alternative control strategies for HAP emissions from these units. These alternative control strategies must address the hazards to public health that EPA reasonably anticipates will occur as a result of Utility Unit HAP emissions. Congress authorized EPA to consider a wider range of control alternatives for the utility sector than the source-by-source approach EPA has prescribed in standards for other source categories under the traditional section 112(d) MACT approach

lternative control strategies must address the hazards to public health that EPA reasonably anticipates will occur as a result of Utility Unit HAP emissions. Congress authorized EPA to consider a wider range of control alternatives for the utility sector than the source-by-source approach EPA has prescribed in standards for other source categories under the traditional section 112(d) MACT approach. Because Congress directed EPA to develop control strategies that would be alternatives to the usual section 112(d) MACT

As a result, EPA believes that section 112(n) confers on the Agency the authority to develop a system-wide or pooled performance standard for HAP emissions from Utility Units. Notably, in the December 2000 section 112(n)(1)(A) finding, we identified the “considerable interest in an approach to Hg regulation for power plants that would incorporate economic incentives such as emissions trading.” 65 FR at 79830. We also offered the conclusion that “[r]ecent data * * * indicate the possibility for multipollutant control with other pollutants ( e.g. , NO X , SO 2 , and PM), greatly reducing mercury control costs.”

In addition, section 112(n)(1)(A) specifies that any regulation of HAP emissions from Utility Units should be “appropriate and necessary” in light of “hazards to public health reasonably anticipated to occur”—a departure from the traditional 112(d) approach applicable to other types of sources. Read as a whole, section 112(n)(1)(A) could be read to grant authority to develop and propose different control mechanisms than might be required under the section 112(d) approach. Under this reading, EPA could adopt any control strategy that is “appropriate and necessary” in light of “hazards to public health reasonably anticipated to occur.”

approach. Under this reading, EPA could adopt any control strategy that is “appropriate and necessary” in light of “hazards to public health reasonably anticipated to occur.”

As discussed at length elsewhere in today's notice, a trading approach for Utility Unit emissions of Hg has many advantages over a prescriptive, technology-based approach such as a MACT. See discussion, infra, section IV(D). We also reiterate that a cap and trade approach to controlling Hg emissions dovetails well with our proposal concerning an IAQR. See discussion, infra, section IV. Accordingly, a trading approach for Hg is consistent with Congress’s direction in section 112(n)(1)(A) that any EPA regulation of HAP emissions from Utility Units must take into account compliance by those units with regulations and emissions reductions under other provisions of the CAA.

In past MACT rulemakings and with respect to source categories other than Utility Units, EPA has not resolved whether a system-wide or pooled performance standard is permitted under section 112(d). However, EPA has under the authority of section 112(d) established affected source-wide emissions averaging provisions that do not necessarily require each regulated source to apply controls. The EPA requests comment on whether we can expand upon this idea and establish a program similar to the program we believe could be promulgated pursuant to section 112(n), including system averaging, based on section 112(d). If EPA concludes that nothing in section 112(d) precludes this result, that section could provide a basis for EPA's final rule.

this result, that section could provide a basis for EPA's final rule.

We note that implementing a cap and trade rule for Utility Units under section 112 could offer certain advantages as compared to our proposed section 111 approach. For example, EPA should be able to directly implement a national standard under section 112, instead of relying on the SIP-type approach required under section 111. As a result, a section 112 trading program would, among other things, reduce the administrative burdens on both EPA and the States and would assure national consistency.

The EPA invites public comment on all aspects of implementing a trading program under section 112. The EPA also requests comment on how it should design a trading program under section 112, including whether the title IV Acid Rain SO 2 program, the Acid Rain NO X program, the NO X SIP Call or today's proposed section 111 trading program are useful models for regulating Hg emissions.

In conjunction with this proposal to establish a cap-and-trade program under the authority of section 112(n)(1)(A) and/or 112(d), we also propose to revise the definition of “emission standard” in 40 CFR 63.2. We propose to amend the phrase “pursuant to sections 112(d), 112(h), or 112(f) of the Act” to include reference to section 112(n).

B. Summary of the Proposed Section 112 MACT Rule

1. What Is the Affected Source?

An existing affected source for the proposed rule is each group of coal- or oil-fired Utility Units located at a facility. A new affected source is a coal- or oil-fired Utility Unit for which construction or reconstruction began after January 30, 2004. The proposed rule defines a Utility Unit as:

a fossil fuel-fired combustion unit of more than 25 megawatts electric (MWe) that serves a generator that produces electricity for sale

proposed rule is each group of coal- or oil-fired Utility Units located at a facility. A new affected source is a coal- or oil-fired Utility Unit for which construction or reconstruction began after January 30, 2004. The proposed rule defines a Utility Unit as:

a fossil fuel-fired combustion unit of more than 25 megawatts electric (MWe) that serves a generator that produces electricity for sale. A unit that cogenerates steam and electricity and supplies more than one-third of its potential electric output capacity and more than 25 MWe output to any utility power distribution system for sale is also an electric utility steam generating unit. If a unit burns coal (either as a primary fuel or as a supplementary fuel), or any combination of coal with another fuel, the unit is considered to be coal-fired under the proposed rule. If a unit is not a coal-fired unit and burns only oil, or oil in combination with natural gas (except as noted below), the unit is considered to be oil-fired under the proposed rule. If a new or existing unit burns natural gas exclusively or natural gas in combination with oil where the oil constitutes less than 2 percent of the unit's annual fuel consumption (used for start-up purposes), the unit is considered to be natural gas-fired and would not be subject to the proposed rule.

2. What Are the Proposed Emission Limitations?

The proposed rule would establish separate emissions limits for new and existing coal- and oil-fired Utility Units. For coal-fired units, limits would be established for Hg depending on the rank of coal. For oil-fired units, limits would be established for Ni emissions. The proposed limits for Hg for coal-fired units are expressed in pound per trillion British thermal unit (lb/TBtu) on an input basis or pound per Megawatt hour (lb/MWh) on an output basis. The proposed Ni limits for oil-fired units are expressed in lb/TBtu on an input basis or lb/MWh on an output basis

epending on the rank of coal. For oil-fired units, limits would be established for Ni emissions. The proposed limits for Hg for coal-fired units are expressed in pound per trillion British thermal unit (lb/TBtu) on an input basis or pound per Megawatt hour (lb/MWh) on an output basis. The proposed Ni limits for oil-fired units are expressed in lb/TBtu on an input basis or lb/MWh on an output basis. For both Hg and Ni, owners/operators of existing units would have the option of complying with either the input- or the output-based limit; owners/operators of new units would be subject to the output-based limit. The owner/operator would establish a unit-specific limit (according to methods provided in the proposed rule) for each coal-fired unit that burns blended coal. The proposed limits for coal-fired and oil-fired units are shown in Tables 1 and 2, respectively, of this preamble (for existing affected sources) and Tables 3 and 4, respectively, of this preamble (for new affected sources).

Table 1.—Emission Limits for Existing Coal-Fired Electric Utility Steam Generating Units Unit type Hg (lb/TBtu) 1 Hg (10 −6 lb/MWh) 1 Bituminous-fired 2 2.0 or 21 Subbituminous-fired 5.8 or 61 Lignite-fired 9.2 or 98 IGCC unit 19 or 200 Coal refuse-fired 0.38 or 4.1 1 Based on 12-month rolling average. 2 Anthracite units are included with bituminous units. Table 2.—Emission Limits for Existing Oil-Fired Electric Utility Steam Generating Units Unit type Ni (lb/TBtu) 1 Ni (lb/MWh) 1 Oil-fired 210 or 0.002 1 Based on do-not-exceed limit. Table 3.—Emission Limits for New Coal-Fired Electric Utility Steam Generating Units Unit type Hg (10 −6 lb/MWh) 1 Bituminous-fired 2 6.0 Subbituminous-fired 20 Lignite-fired 62 IGCC unit 3 20 Coal refuse-fired 1.1 1 Based on 12-month rolling average. 2 Anthracite units are included with bituminous units. 3 Based on 90 percent reduction for beyond-the-floor control

2 1 Based on do-not-exceed limit. Table 3.—Emission Limits for New Coal-Fired Electric Utility Steam Generating Units Unit type Hg (10 −6 lb/MWh) 1 Bituminous-fired 2 6.0 Subbituminous-fired 20 Lignite-fired 62 IGCC unit 3 20 Coal refuse-fired 1.1 1 Based on 12-month rolling average. 2 Anthracite units are included with bituminous units. 3 Based on 90 percent reduction for beyond-the-floor control. Table 4.—Emission Limits for New Oil-Fired Electric Utility Steam Generating Units Unit type Ni (lb/MWh) 1 Oil-fired 0.0008 1 Based on do-not-exceed limit. Two alternatives for compliance purposes are provided in the proposed rule for oil-fired units. The owner/operator can elect to: (1) meet the Ni limit, or (2) burn distillate oil (exclusively) rather than residual oil. If an oil-fired unit is currently burning, or switches to burning, distillate oil (exclusively), it would be exempt from all oil-fired unit initial and continuous compliance requirements until such time as it begins burning any oil other than distillate oil. The proposed rule would require that the exempted oil-fired unit begin the performance testing procedures if it resumes burning a fuel other than distillate oil.

The proposed rule would also allow emissions averaging as a compliance option for existing coal-fired units located at a single contiguous plant. The owner/operator could elect to establish an overall Hg limit for an emissions averaging group using the procedures in the proposed rule and comply with that limit during each 12-month compliance period. The emissions averaging compliance approach is also applicable to coal-fired Utility Units subject to the Hg emission limits for new affected sources as long as they meet the new source limits.

The proposed emission limitations also include operating limits for control devices used to meet an emissions limitation

he proposed rule and comply with that limit during each 12-month compliance period. The emissions averaging compliance approach is also applicable to coal-fired Utility Units subject to the Hg emission limits for new affected sources as long as they meet the new source limits.

The proposed emission limitations also include operating limits for control devices used to meet an emissions limitation. If an electrostatic precipitator (ESP) is used to meet a Ni limit, the owner/operator would be required to operate each ESP such that the hourly average voltage and secondary current (or total power input) do not fall below the limit established in the most recent performance test. Operating limits would not apply to control devices used to meet Hg emission limits where a continuous emission monitoring system (CEMS) or an appropriate long-term method is used to demonstrate compliance.

3. What Are the Proposed Testing and Initial Compliance Requirements?

New or reconstructed units must be in compliance with the applicable rule requirements upon initial startup or by the effective date of the final rule, whichever is later. Existing units must be in compliance with the applicable rule requirements no later than 3 years after the effective date of the final rule. The effective date is the date on which the final rule is published in the Federal Register .

Prior to the compliance date, the owner/operator would be required to prepare a unit-specific monitoring plan and submit the plan to the Administrator for approval. The proposed rule would require that the plan address certain aspects with regard to the monitoring system; installation, performance and equipment specifications; performance evaluations; operation and maintenance procedures; quality assurance techniques; and recordkeeping and reporting procedures. Beginning on the compliance date, the owner/operator would be required to comply with the plan requirements for each monitoring system.

Mercury emission limits

aspects with regard to the monitoring system; installation, performance and equipment specifications; performance evaluations; operation and maintenance procedures; quality assurance techniques; and recordkeeping and reporting procedures. Beginning on the compliance date, the owner/operator would be required to comply with the plan requirements for each monitoring system.

Mercury emission limits. Compliance with the Hg emission limit would be determined based on a rolling 12-month average calculation. The Hg emissions are determined by continuously collecting Hg emission data from each affected unit by installing and operating a CEMS or an appropriate long-term method that can collect an uninterrupted, continuous sample of the Hg in the flue gases emitted from the unit. The proposed rule would allow the owner/operator to use any CEMS that meets requirements in Performance Specification 12A (PS-12A), “Specifications and Test Procedures for Total Vapor-phase Mercury Continuous Monitoring Systems in Stationary Sources.” An owner/operator electing to use long-term Hg monitoring would be required to comply using the new EPA Method 324, “Determination of Vapor Phase Flue Gas Mercury Emissions from Stationary Sources Using Dry Sorbent Trap Sampling.” Performance Specification 12A and Test Method 324 are proposed as part of this rulemaking. The owner/operator would use the procedures outlined in § 63.10009 of the proposed rule to convert the concentration output from a CEMS or Method 324 to an emission rate format in lb/TBtu or lb/MWh. The proposed rule would require the owner or operator to begin compliance monitoring on the compliance date.

tion output from a CEMS or Method 324 to an emission rate format in lb/TBtu or lb/MWh. The proposed rule would require the owner or operator to begin compliance monitoring on the compliance date.

For new or existing cogeneration units, steam is also generated for process use. The energy content of this process steam must also be considered in determining compliance with the output-based standard. Therefore, the owner/operator of a new or existing cogeneration unit would be required to calculate emission rates based on electrical output to the grid plus half the equivalent electrical output energy in the unit's process steam. The procedure for determining these Hg emission rates is included in § 63.10009(c) of the proposed rule.

The owner/operator of a new or existing coal-fired unit that burns a blend of fuels would develop a unit-specific Hg emission limitation and the unit Hg emission rate for the portion of the compliance period that the unit burned the blend of fuels. The procedure for determining these emission limitations is outlined in § 63.9990(a)(5) of the proposed rule.

Nickel emission limits. Compliance with the applicable Ni emission limits in the proposed rule would be determined by performance tests conducted according to the requirements in 40 CFR 63.7 of the NESHAP General Provisions and the requirements in the proposed rule. The proposed rule would require EPA Method 29 in appendix A to 40 CFR part 60 to be used for the measurement of Ni emissions in the flue gas. With Method 29, Method 1 would be used to select the sampling port location and the number of traverse points; Method 2 would be used to measure the volumetric flow rate; Method 3 would be used for gas analysis; and Method 4 would be used to determine stack gas moisture. Method 19 would be used to convert the Method 29 Ni measurements to an emission rate expressed in units of lb/TBtu if complying with an input-based standard

ld be used to select the sampling port location and the number of traverse points; Method 2 would be used to measure the volumetric flow rate; Method 3 would be used for gas analysis; and Method 4 would be used to determine stack gas moisture. Method 19 would be used to convert the Method 29 Ni measurements to an emission rate expressed in units of lb/TBtu if complying with an input-based standard. The owner/operator would use the procedures outlined in § 63.10009 of the proposed rule to convert the concentration output of

The proposed rule would require the owner/operator to establish limits for control device operating parameters based on the actual values measured during each performance test. The proposed rule specifies the parameters to be monitored for the types of emission control systems commonly used in the industry. The owner/operator would be required to submit a monitoring plan identifying the operating parameters to be monitored for any control device used that is not specified in the proposed rule.

An initial performance test to demonstrate compliance with each applicable Ni emission limit would be required no later than 180 days after initial startup or 180 days after publication of the final rule, whichever is later, for a new or reconstructed unit, and no later than the compliance date for an existing unit (3 years after publication of the final rule).

The owner/operator of a new or existing cogeneration unit would have to account for the process steam portion of their emissions in the same manner for Ni emissions as they did for Hg emissions. The owner/operator of a cogeneration unit would be required to calculate the Ni emission rate based on electrical output to the grid plus half the equivalent electrical output energy in the unit's process steam ( see section II.C.2 for an explanation of the basis for this approach). The procedure for determining these Ni emission rates are given in § 63.10009(c) of the proposed rule.

missions. The owner/operator of a cogeneration unit would be required to calculate the Ni emission rate based on electrical output to the grid plus half the equivalent electrical output energy in the unit's process steam ( see section II.C.2 for an explanation of the basis for this approach). The procedure for determining these Ni emission rates are given in § 63.10009(c) of the proposed rule.

4. What Are the Proposed Continuous Compliance Requirements?

To demonstrate continuous compliance with the applicable emission limits under the proposed rule, the owner/operator would be required to perform continuous Hg emission monitoring for coal-fired units and continuous monitoring of appropriate operating parameters for the ESP used to comply with the Ni limit for oil-fired units. In addition, an annual performance test will be required for demonstrating compliance with the Ni emission limitation for oil-fired units. The annual performance test would be conducted in the same manner as the initial compliance demonstration.

5. What Are the Proposed Notification, Recordkeeping, and Reporting Requirements?

The proposed rule would require the owner/operator to keep records and file reports consistent with the notification, recordkeeping, and reporting requirements of the General Provisions of 40 CFR part 63, subpart A. Records required under the proposed rule would be kept for 5 years, with the 2 most recent years being on the facility premises. These records would include copies of all Hg emission monitoring data, coal usage, MWh generated, and heating value data required for compliance calculations; reports that have to be submitted to the responsible authority; control equipment inspection records; and monitoring data from control devices demonstrating that emission limitations are being maintained.

Two basic types of reports would be required: initial notifications and periodic reports

monitoring data, coal usage, MWh generated, and heating value data required for compliance calculations; reports that have to be submitted to the responsible authority; control equipment inspection records; and monitoring data from control devices demonstrating that emission limitations are being maintained.

Two basic types of reports would be required: initial notifications and periodic reports. The owner/operator would be required to submit notifications described in the General Provisions (40 CFR part 63, subpart A), which include initial notification of applicability, notifications of performance tests, and notification of compliance status. For oil-fired units, if you at any time during the reporting period comply with an applicable emissions limit by switching fuel (in other than emergency situations), the proposed rule would also require that you notify EPA in writing at least 30 days prior to using a fuel other than distillate oil. In emergency situations, such notification must be within 30 days. As required by the General Provisions, the owner/operator would be required to submit a report of performance test results; develop and implement a written startup, shutdown, and malfunction plan and report semi-annually any events in which the plan was not followed; and submit semi-annual reports of any deviations when any monitored parameters fell outside the range of values established during the performance test.

C. Rationale for the Proposed Section 112 MACT Rule

1. How Did EPA Select the Affected Sources That Would Be Regulated Under the Proposed Rule?

hed during the performance test.

C. Rationale for the Proposed Section 112 MACT Rule

1. How Did EPA Select the Affected Sources That Would Be Regulated Under the Proposed Rule?

As defined in section 112(a)(8) of the CAA, an “electric utility steam generating unit” means “any fossil fuel fired combustion unit of more than 25 megawatts that serves a generator that produces electricity for sale. A unit that cogenerates steam and electricity and supplies more than one-third of its potential electric output capacity and more than 25 megawatts electrical output to any utility power distribution system for sale shall be considered an electric utility steam generating unit.” For purposes of this proposed standard, any steam supplied to a steam distribution system for the purpose of providing steam to a steam-electric generator that would produce electrical energy for sale is also considered in determining the electrical energy gross output capacity of the affected facility.

Only Utility Units that are fired by coal or oil, or combinations of fuels that include coal and oil, are subject to this proposal. Integrated gasification combined cycle units are also subject to this proposal. Boilers otherwise meeting the definition but fueled by gaseous fuels (other than gasified coal) at greater than or equal to 98 percent of their annual fuel consumption (when the other fuel burned is fuel oil or coal) are not included in the proposed rule.

An affected source under MACT is the equipment or collection of equipment to which the MACT rule limitations or control technology is applicable. For the proposed rule, the affected source would be the group of coal- or oil-fired units at a facility (a contiguous plant site where one or more Utility Units are located). Each unit would consist of the combination of a furnace firing a boiler used to produce steam, which is in turn used for a steam-electric generator that produces electrical energy for sale

or control technology is applicable. For the proposed rule, the affected source would be the group of coal- or oil-fired units at a facility (a contiguous plant site where one or more Utility Units are located). Each unit would consist of the combination of a furnace firing a boiler used to produce steam, which is in turn used for a steam-electric generator that produces electrical energy for sale. This definition of affected source would include a wide range of regulated units with varying process configurations and emission profile characteristics.

Therefore, the first step towards rule development is to determine if dissimilarities between sources within the source category warrant subcategorization. Under CAA section 112(d)(1), which EPA is proposing to use for purposes of developing this rule pursuant to CAA section 112(n)(1)(A), the Administrator has the discretion to “ * * * distinguish among classes, types, and sizes of sources within a category or subcategory in establishing * * * ” standards.

Historically and as EPA noted in the December 2000 finding, the criteria used by EPA in evaluating differences in combustion sources for purposes of subcategorization have included the size of the facility, type of fuel used, and plant type. (65 FR 79830) The EPA also is free to consider other relevant factors, such as geographic factors, process design or operation, variations in emissions profiles, or differences in the feasibility of application of control technology (APCD or work practices).

For the coal- and oil-fired Utility Unit source category, the individual units or sources exhibited obvious and significant variations with regard to some of these criteria. The most prominent dissimilarity was that between coal- and oil-fired units. Coal- and oil-fired units have vastly different i.e. , the units are designed to run continuously except for maintenance intervals). Oil-fired units are generally used as “peaking” units ( i.e. , the units are operated when extra electrical power is needed)

and significant variations with regard to some of these criteria. The most prominent dissimilarity was that between coal- and oil-fired units. Coal- and oil-fired units have vastly different i.e. , the units are designed to run continuously except for maintenance intervals). Oil-fired units are generally used as “peaking” units ( i.e. , the units are operated when extra electrical power is needed). Coal combustion produces higher emission levels of Hg than does a comparably sized oil-fired unit whereas oil combustion produces higher levels of Ni compounds. For these reasons, EPA divided sources into the initial subcategories of coal- and oil-fired units. Additional evaluation of the data was then conducted to ascertain if further subcategorization within coal-fired or within oil-fired units was warranted.

Subcategorization within existing coal-fired units. The American Society for Testing and Materials (ASTM) classifies coals by rank, a term which relates to the carbon content of the coal and other related parameters such as volatile-matter content, heating value, and agglomerating properties. The coal-fired electric utility industry combusts the following coal ranks, presented in decreasing order: anthracite, bituminous, subbituminous, and lignite. The higher heating value (HHV) of coal is measured as the gross calorific value, reported in British thermal units per pound (Btu/lb). The heating value of coal increases with increasing coal rank. The youngest, or lowest rank, coals are termed lignite. Lignites have the lowest heating value of the coals typically used in power plants. Their moisture content can be as high as 30 percent, but their volatile content is also high; consequently, they ignite easily. Next in rank are subbituminous coals, which also have a relatively high moisture content, typically ranging from 15 to 30 percent. Subbituminous coals also are high in volatile matter content and ignite easily. Their heating value is generally in between that of the lignites and the bituminous coals

e as high as 30 percent, but their volatile content is also high; consequently, they ignite easily. Next in rank are subbituminous coals, which also have a relatively high moisture content, typically ranging from 15 to 30 percent. Subbituminous coals also are high in volatile matter content and ignite easily. Their heating value is generally in between that of the lignites and the bituminous coals. Bituminous coals are next in rank, with higher heating values and lower moisture and volatile content than the subbituminous and lignite coals. Anthracites are the highest rank coals. Because of the difficulty in obtaining and igniting anthracite and the difficulties in maintaining anthracite-fired boilers, only a single electric utility boiler in the U.S. burned anthracite as its only fuel in 1999. Because bituminous coal is the most similar coal to anthracite coal based on coal physical characteristics (ash content, sulfur content, HHV), anthracite coal is considered to be equivalent to bituminous coal for the purposes of the proposed rule and, thus, the anthracite-fired unit is considered a bituminous-fired unit for the purposes of the proposed rule.

Although there is overlap in some of the ASTM classification properties, the ASTM method of classifying coals by rank has been in use for decades and generally is successful in identifying some common core characteristics that have implications for power plant design and operation.

wer plant design and operation.

Coal refuse ( i.e. , anthracite coal refuse (culm), bituminous coal refuse (gob), and subbituminous coal refuse) is also combusted in Utility Units. Coal refuse refers to the waste products of coal mining, physical coal cleaning, and coal preparation operations ( e.g. culm, gob, etc.) containing coal, matrix material, clay, and other organic and inorganic material. Previously considered unusable by the industry because of the high ash content and relatively low heat content, it now may be utilized as a supplemental fuel in limited amounts in some units or as the primary fuel in a fluidized bed combustor (FBC). Because of the inherent inability to utilize coal refuse as the primary fuel in anything other than an FBC, it is considered to be a separate coal rank for purposes of the proposed rule.

The rank of coal to be burned has a significant impact on overall plant design. The goal of the plant designer is to arrange boiler components (furnace, superheater, reheater, boiler bank, economizer, and air heater) to provide the rated steam flow, maximize thermal efficiency, and minimize cost. Engineering calculations are used to determine the optimum positioning and sizing of these components, which cool the flue gas and generate the superheated steam. The accuracy of the parameters specified by the owner/operators is critical to designing and building an optimally efficient plant. The rank of coal to be burned greatly impacts the entire design process. The rank of coal burned also has significant impact on the design and operation of the emission control equipment ( e.g. , ash resistivity impacts ESP performance).

f coal burned also has significant impact on the design and operation of the emission control equipment ( e.g. , ash resistivity impacts ESP performance).

For the above reasons, one of the most important factors in modern electric utility boiler design involves the differences in the ranks and range of coals to be fired and their impact on the details and overall arrangement of boiler components. Coal rank is so important that plant designers and manufacturers expect to be provided with a complete list of all coal ranks presently available or planned for future use, along with their complete chemical and ash analyses, so that the engineers can properly design and specify plant equipment. The various coal characteristics ( e.g. , how hard the coal is to pulverize; how high its ash content; the chemical content of the ash; how the ash “slags” (fused deposits or resolidified molten material that forms primarily on furnace walls or other surfaces exposed predominantly to radiant heat or high temperature); how big the boiler has to be to adequately utilize the heat content; etc.), therefore, affect design from the pulverizer through the boiler to the final steam tubes. For a boiler to operate efficiently, it is critical to recognize the differences in coals and make the necessary modifications in boiler components during design to provide optimum conditions for efficient combustion.

Coal-fired units are designed and constructed with different process configurations partially because of the constraints, including the properties of the fuel to be used, placed on the initial design of the unit. Accordingly, these site-specific constraints dictate the process equipment selected, the component order, the materials of construction, and the operating conditions

ficient combustion.

Approximately 23 percent of coal-fired Utility Units either (1) co-fire two or more ranks of coal (with or without other fuels) in the same boiler, or (2) fire two or more ranks of coal (with or without other fuels) in the same boiler at different times (1999 EPA ICR). This coal “blending” is done generally for one of three reasons: (1) to achieve SO 2 emission compliance with title IV provisions of the CAA, (2) to prevent excessive slagging by improving the heat content of a lower grade coal, or (3) for economic reasons ( i.e. , coal rank price and availability).

These blended coals, although of different rank, do have similar properties. That is, because of the overlap in various characteristics in the ASTM definitions of coal rank, certain bituminous and subbituminous coals (for example) exhibit similar handling and combustion properties. Plant designers and operators have learned to accommodate these blends in certain circumstances without significant impact on plant operation or control.

There are five basic types of coal combustion processes used in the coal-fired electric utility industry. These are conventional-fired boilers, stoker-fired boilers, cyclone-fired boilers, IGCC units, and FBC units.

Conventional boilers, also known as pulverized coal (PC) boilers, have a number of firing configurations based on their burner placement. The basic

In stoker-fired boilers, fuel is deposited on a moving or stationary grate or spread mechanically or pneumatically from points usually 10 to 20 feet above the grate

ed boilers, stoker-fired boilers, cyclone-fired boilers, IGCC units, and FBC units.

Conventional boilers, also known as pulverized coal (PC) boilers, have a number of firing configurations based on their burner placement. The basic

In stoker-fired boilers, fuel is deposited on a moving or stationary grate or spread mechanically or pneumatically from points usually 10 to 20 feet above the grate. The process utilizes both the combustion of fine coal powder in air and the combustion of larger particles that fall and burn in the fuel bed on the grate.

Cyclone-fired boilers use several water-cooled horizontal burners that produce high-temperature flames that circulate in a cyclonic pattern. The burner design and placement cause the coal ash to become a molten slag that is collected below the furnace.

Fluidized bed combustors combust coal, in a bed of inert material ( e.g. , sand, silica, alumina, or ash) and/or a sorbent such as limestone, that is suspended through the action of primary combustion air distributed below the combustor floor. “Fluidized” refers to the state of the bed of material (coal and inert material (or sorbent)) as gas passes through the bed. As the gas flow rate is increased, the force on the fuel particles becomes just sufficient to cause buoyancy. The gas cushion between the solids allows the particles to move freely, giving the bed a liquid-like (or fluidized) characteristic.

Integrated-coal gasification combined cycle units are specialized units in which coal is first converted into synthetic coal gas. In this conversion process, the carbon in the coal reacts with water to produce hydrogen gas and carbon monoxide (CO). The synthetic coal gas (syngas) is then combusted in a combustion turbine which drives an electric generator. Hot gases from the combustion turbine then pass through a waste heat boiler to produce steam. This steam is fed to a steam turbine connected to a second electric generator

In this conversion process, the carbon in the coal reacts with water to produce hydrogen gas and carbon monoxide (CO). The synthetic coal gas (syngas) is then combusted in a combustion turbine which drives an electric generator. Hot gases from the combustion turbine then pass through a waste heat boiler to produce steam. This steam is fed to a steam turbine connected to a second electric generator.

After examining a number of possible subcategorization options, EPA identified three basic ways to subcategorize coal-fired Utility Units.

No subcategorization. This approach would treat all coal ranks and all coal combustion process types as one, with the MACT floor developed using all of the coal-fired unit data.

Subcategorization by coal rank. Subcategorization by individual coal rank accommodates the various design and control constraints resulting from the various coal ranks.

Subcategorization by process type. Another option is to subcategorize by process type ( e.g. , stoker-fired, cyclone-fired, FBC, IGCC).

To determine the appropriate subcategorization approach, the EPA evaluated fuel, process, and control technology and found that the data did not identify any common attribute among the top units that could be credited with the demonstrated better performance. The EPA found that each of the best-performing units had a combination of factors that was the basis for the better performance on that particular unit. The factors identified included the Hg and chlorine (Cl) contents of the coal, the speciation of the Hg in the flue gas stream, and the control device configuration.

tion of the Hg in the flue gas stream, and the control device configuration.

Based on this information, EPA then analyzed the available data to determine which coal ranks were burned, and why, to ascertain if changing coal rank would be a conceivable control strategy. The EPA found that the characteristics of the coal rank to be burned was the driving factor in how a coal-fired unit was designed. Further, the choice of coal ranks to be burned for a given unit is based on economic issues, including availability of the coal within the region or locale. A number of coal-fired units, including all known lignite-fired units, are “mine mouth” (or near mine-mouth) operations ( i.e. , the unit is constructed on or near the coal mine itself with coal transport often being done by conveyor directly from the mine) and many do not have the infrastructure in place ( e.g. , interstate rail lines) to import other ranks of coal in quantities sufficient to replace all lignite coal combusted. The EPA also found that substitution of coal rank, in most cases, would require significant modification or retooling of a unit, which would indicate a pertinent difference in the design/operation of the units. Because not all units are designed to combust the same rank of coal and the Hg emissions from some ranks of coal are easier to control than those from other ranks, a standard based on “no subcategorization” likely would be unachievable for some units. For these reasons, EPA decided that subcategorization of coal-fired units based on coal rank (fuel type) was warranted. We note again that certain Utility Units are, in fact, able to effectively combust coals from different ASTM ranks because of the overlap in coal classification properties. We do not, however, believe that this “overlap” compromises our ability to subcategorize by coal rank because it remains true that coal rank is a significant factor that distinguishes the design and operational characteristics of different boilers. We ask for comment on this issue

able to effectively combust coals from different ASTM ranks because of the overlap in coal classification properties. We do not, however, believe that this “overlap” compromises our ability to subcategorize by coal rank because it remains true that coal rank is a significant factor that distinguishes the design and operational characteristics of different boilers. We ask for comment on this issue.

Although conventional-, stoker-, and cyclone-fired boilers use different firing techniques, the Hg emissions characteristics of these boilers are similar (when common ranks of coal are fired) and, therefore, the units can be grouped together and further subcategorization by these process types is not necessary.

Based on their unique firing designs, FBC units employ a fundamentally different process for combusting coal from that employed by conventional-, stoker-, or cyclone-fired boilers. Fluidized-bed combustors are capable of combusting many coal ranks, including coal refuse. For these reasons, FBC units can be considered a distinct type of boiler. However, the Hg emissions test data results for FBC units were not substantially different from those at similarly-fueled conventionally-fired units with similar emission levels, either in mass of emissions or in emissions characteristics. Therefore, EPA has decided not to establish a separate subcategory for FBC units.

Integrated gasification combined cycle units combust a synthetic coal gas. No coal is directly combusted in the unit during operation (although a coal-derived fuel is fired), and, thus, IGCC units are a distinct class or type of boiler for the proposed rule

ther in mass of emissions or in emissions characteristics. Therefore, EPA has decided not to establish a separate subcategory for FBC units.

For the purposes of the proposed rule and based on the above information, the coal-fired units at existing affected sources are subcategorized into five subcategories, four based on coal rank and one based on process type: bituminous (including anthracite); subbituminous; lignite; coal refuse (which includes anthracite coal refuse (culm), bituminous coal refuse (gob), and subbituminous coal refuse); and IGCC (coal syngas). Because few units fire anthracite coal and because there are significant similarities in the emissions resulting from the combustion of anthracite and bituminous coals, EPA chose to combine anthracite coal with bituminous coal for the purposes of this rule. A more detailed description of the specific elements and rationale used to determine this subcategorization scheme is located in the docket.

Subcategorization within existing oil-fired units. The EPA analyzed the data available on the fuel, process, emission profiles, and APCD for oil-fired units at existing affected sources. An oil-fired electric utility boiler combusts fuel oil exclusively, or combusts fuel oil at certain times of the year and natural gas at other times (not simultaneously). The choice of when to combust oil

The type of oil to be burned has little impact on overall boiler design. The goal of the plant designer is to make sure the plant can handle the different viscosities of oil (and natural gas if applicable) that the boiler is likely to combust.

There is only one basic type of oil combustion process used in the oil-fired electric utility industry, known as a conventional-fired boiler

combust oil

There is only one basic type of oil combustion process used in the oil-fired electric utility industry, known as a conventional-fired boiler. Conventional-fired boilers have a number of firing configurations based on their burner placement. The basic characteristic that all conventional-fired boilers have in common is that they inject oil and primary air through a burner where ignition of the oil occurs, which in turn creates an individual flame. Conventional-fired boilers fire through many such burners mounted in the furnace walls.

The data available to EPA indicated that there is very little variation in the process or control technologies used in the industry. Therefore, EPA found no criteria that would warrant further subcategorization within existing oil-fired units and is not doing so in the proposed rule.

Subcategorization within new units. With regard to new sources, EPA has no data that indicate that the rationale for subcategorization for existing coal-fired units would not be applicable to new units ( i.e., there is no reason to believe that new units will not utilize the full range of coal ranks and combustion process types currently used by existing units). New units constructed at the same facilities as existing units could still be restricted, at least in concept, to the same physical constraints ( e.g., coal handling and processing, access to interstate rail lines) as are the co-located existing units. Further, EPA has no data indicating the availability of existing coal ranks is likely to substantially change for a given locale. For this reason, EPA is proposing that the subcategorization scheme for new coal- and oil-fired units be the same as for the existing units

physical constraints ( e.g., coal handling and processing, access to interstate rail lines) as are the co-located existing units. Further, EPA has no data indicating the availability of existing coal ranks is likely to substantially change for a given locale. For this reason, EPA is proposing that the subcategorization scheme for new coal- and oil-fired units be the same as for the existing units.

The EPA solicits comment on this decision that new and existing units should be subcategorized in the same manner.

2. How Did EPA Select the Format of the Proposed Emission Standards?

The EPA has established pollution prevention as one of the its highest priorities. One of the opportunities for pollution prevention lies in simply using energy efficient technologies to minimize the generation of emissions. The EPA has previously investigated ways to promote energy efficiency in utility plants by changing the manner in which it regulates flue gas emissions. Therefore, in an effort to promote energy efficiency in utility steam generating facilities, the Administrator is proposing output-based standards for new sources for emissions of Hg and Ni under this rule. This format has been used successfully on other EPA rules ( e.g., subpart Da NSPS NO X , 40 CFR 63.44a). Existing sources would have the option of using either input- or output-based limits based on the potential increase in cost resulting from the need to add instrumentation.

Traditionally, utility emissions have been controlled on the basis of boiler input energy (lb/million British thermal units (MMBtu) heat input). However, input-based limitations allow units with low operating efficiency to emit more per megawatt (MWe) of electricity produced than more efficient units. Considering two units of equal capacity, under current regulations, the less efficient unit will emit more because it uses more fuel to produce the same amount of electricity

input energy (lb/million British thermal units (MMBtu) heat input). However, input-based limitations allow units with low operating efficiency to emit more per megawatt (MWe) of electricity produced than more efficient units. Considering two units of equal capacity, under current regulations, the less efficient unit will emit more because it uses more fuel to produce the same amount of electricity. One way to regulate mass emissions and plant efficiency is to express the emission standard in terms of output energy. Thus, an output-based emission standard would provide a regulatory incentive to enhance unit operating efficiency and reduce emissions. Two of the possible output-based formats considered for the revised standards were: (1) Mass emitted per gross boiler steam output (lb/TBtu heat output), and (2) mass emitted per net energy output (lb/MWh). The criteria used for selecting the format were ease in monitoring and compliance testing and ability to promote energy efficiency.

The objective of an output-based standard is to establish an emission limit in a format that incorporates the effects of plant efficiency. Additionally, the limit should be in a format that is practical to implement. Thus, the format selected must satisfy the following: (1) Provide flexibility in promotion of plant efficiency; (2) permit measurement of parameters related to stack emissions and plant efficiency, on a continuous basis; and (3) be suitable for equitable application on a variety of power plant configurations.

The option of lb/TBtu steam output accounts only for boiler efficiency, ignores both the turbine cycle efficiency and the effects of energy consumption internal to the plant, and provides minimal opportunities for promoting energy efficiency at the units. The EPA has found that the second output-based format option of lb/MWh is preferable as it accounts for all aspects of efficiency and provides opportunity for promoting energy efficiency for the units

ler efficiency, ignores both the turbine cycle efficiency and the effects of energy consumption internal to the plant, and provides minimal opportunities for promoting energy efficiency at the units. The EPA has found that the second output-based format option of lb/MWh is preferable as it accounts for all aspects of efficiency and provides opportunity for promoting energy efficiency for the units.

The format of lb/MWh can be measured in two ways: net and gross energy output. The net plant energy output provides the owners/operators with all possible opportunities for promoting energy efficiency and can easily accommodate both electrical and thermal (process steam) outputs. The disadvantage of a net plant energy output is that implementation could require significant and costly additional monitoring and reporting systems because the energy output that is used for internal components (and not sent to the grid) cannot be accounted for by simply installing another meter. The gross plant energy output, on the other hand, represents the energy generated before any internal energy consumption and losses are considered. Rules based on this format do not have the disadvantages of the net-based format mentioned above.

Based on this analysis, an emission limit format based on mass of emissions per gross plant energy output is selected for the proposed output-based standard. Because electrical output at all power plants is typically measured directly in MWe, a format in “lb/MWh gross” is determined to be the most appropriate for the proposed rule. The EPA, however, requests comments on the selected format of “lb/MWh gross” because a format of “lb/MWh net” may be more productive in encouraging overall energy efficiency at electric utility plants.

Compliance with the output-based emission limit would require continuous measurement of plant operating parameters associated with the mass rate of emissions and gross energy outputs

roposed rule. The EPA, however, requests comments on the selected format of “lb/MWh gross” because a format of “lb/MWh net” may be more productive in encouraging overall energy efficiency at electric utility plants.

Compliance with the output-based emission limit would require continuous measurement of plant operating parameters associated with the mass rate of emissions and gross energy outputs. In the case of cogeneration plants where process steam is an output product, means would have to be provided to measure the process steam flow conditions and to determine the useful heat energy portion of the process steam that is interchangeable with electrical output.

Instrumentation already exists in power plants to conduct these measurements since the instrumentation is required to support current emission regulations and normal plant operation. Consequently, compliance with the output-based emission limit is not expected to require any additional instrumentation. Therefore, no additional instrumentation is required for conventional utility applications (particularly for new sources) to comply with the output-based emission limit. However, additional signal input wiring and programming is expected to be required to convert the above measurements into the compliance format (lb/MWh gross).

To use an output-based standard for cogeneration units ( i.e., units which use steam to both generate electricity and as a process input), the energy content of the process steam must also be considered in determining compliance with the output-based standard. The EPA has determined that existing plant monitoring and energy calculation curves are available and can be easily programmed to determine the steam's equivalent electrical energy component. This component can then be added to the plant's actual gross electrical output to arrive at the plant's total gross energy output

t also be considered in determining compliance with the output-based standard. The EPA has determined that existing plant monitoring and energy calculation curves are available and can be easily programmed to determine the steam's equivalent electrical energy component. This component can then be added to the plant's actual gross electrical output to arrive at the plant's total gross energy output.

Since all the reported data obtained throughout the development of the revised standards are in the current format of lb/TBtu heat input, EPA applied an efficiency factor to the current format to develop the output-based limits. The efficiency factor approach was selected because the alternative of converting all the reported data in the database to an output-basis would require extensive data gathering and analyses. Applying a baseline efficiency would essentially convert the selected heat input-based level to an output-based emission limit.

The output-based standard must be referenced to a baseline efficiency. Most existing electric utility steam generating plants fall in the range of 24 to 35 percent efficiency. However, newer units operate around 35 percent efficiency; therefore, 35 percent was selected as the baseline efficiency for new units; 32 percent was selected as the baseline efficiency for existing units. The EPA requests comment on: (1) Whether 35 percent is an appropriate baseline efficiency, (2) how often the baseline efficiency should be reviewed and revised in order to account for future improvements in electric generation technology, and (3) the specific methodology or methodologies appropriate and verifiable for determining the gross energy output.

The efficiency of Utility Units usually is expressed in terms of heat rate, which is the ratio of heat input, based on HHV of the fuel, to the energy ( i.e., electrical) output

be reviewed and revised in order to account for future improvements in electric generation technology, and (3) the specific methodology or methodologies appropriate and verifiable for determining the gross energy output.

The efficiency of Utility Units usually is expressed in terms of heat rate, which is the ratio of heat input, based on HHV of the fuel, to the energy ( i.e., electrical) output. The heat rate of a utility steam generating unit operating at 32 percent efficiency is 11 joules per watt hour (J/Wh) (10,667 Btu per kilowatt hour (kWh)); at 35 percent efficiency, the values are 10 J/Wh (9,833 Btu/kWh).

Determination of the gross efficiency of a cogeneration unit includes the gross electrical output and the useful work achieved by the energy ( i.e., steam) delivered to an industrial process. Under a Federal Energy Regulatory Commission (FERC) regulation, the efficiency of cogeneration units is determined from “* * * the useful power output plus one-half the useful thermal output * * *,” 18 CFR part 292, section 205. Therefore, to determine the process steam energy contribution to net plant output, a 50 percent credit of the process steam heat was selected. This approach is consistent with the approach taken in the most recent subpart Da revision to the NO X standard.

The proposed section 112 MACT rule does not include a specific methodology or methodologies for determining the unit gross output. The EPA would specify such methods in the final rule.

The proposed format for Hg also includes the use of a 12-month rolling average in determining compliance. The EPA considers use of an averaging period to be appropriate because Hg is not an acute health hazard in the context of its emission from Utility Units. Rather, it is a persistent bioaccumulative HAP that lends itself to monitoring over a longer-term period. Several periods could be used for this purpose, including 12-month rolling, quarterly, and yearly

olling average in determining compliance. The EPA considers use of an averaging period to be appropriate because Hg is not an acute health hazard in the context of its emission from Utility Units. Rather, it is a persistent bioaccumulative HAP that lends itself to monitoring over a longer-term period. Several periods could be used for this purpose, including 12-month rolling, quarterly, and yearly. Electric Utility Units already monitor their fuel use on a monthly basis for reporting to the DOE. Therefore, EPA is proposing to base the Hg standard on a 12-month rolling average period.

The EPA requests comment on all aspects of the analyses and conclusions set forth above, including (1) whether 32 and 35 percent are appropriate baseline efficiencies; (2) how often the baseline efficiency should be reviewed and revised in order to account for future improvements in electric generation technology; (3) whether the output-based standard option in the proposed rule will promote energy efficiency improvements; (4) the specific methodology or methodologies appropriate and verifiable for determining the gross output of a steam generating unit; and (5) whether a fixed percentage credit of 50 percent is representative of the useful heat in varying quality of process steam flows.

3. How Did EPA Determine the Proposed MACT Floor for Existing Units?

All standards established pursuant to the process set forth in section 112(d) of the CAA must reflect the maximum degree of reduction in emissions of HAP that is determined to be achievable by the industry source category. For existing sources, MACT cannot be less stringent than the average emission limitation achieved by the best-performing 12 percent of existing sources for categories and subcategories with 30 or more sources (excluding certain sources as specified by the CAA). This level of control is known as the MACT floor

in emissions of HAP that is determined to be achievable by the industry source category. For existing sources, MACT cannot be less stringent than the average emission limitation achieved by the best-performing 12 percent of existing sources for categories and subcategories with 30 or more sources (excluding certain sources as specified by the CAA). This level of control is known as the MACT floor. Because the MACT floor represents the level of reduction in HAP emissions that is actually achieved by the best-performing sources in the source category, EPA may not consider cost and other impacts in determining the MACT floor.

This section describes the process used by EPA to determine the MACT floors for each of the subcategories included in the coal- and oil-fired electric utility source category. The MACT floor determination process for this source category was complicated by the many ranks/grades of fossil fuels used in the industry and the capability of the air pollution control technologies currently used in the industry to reduce Hg and Ni emissions.

The initial step in developing a MACT floor or floors for a source category is determining whether subcategorization is appropriate. A discussion of EPA's analysis and conclusions concerning subcategorization of coal-fired units is set forth above.

One potential approach for establishing MACT floors for the subcategories is to require all of the sources in a category to implement precombustion pollution prevention measures. The precombustion techniques include fuel substitution, process changes, and work practices. As discussed in detail below, EPA has

nges, and work practices. As discussed in detail below, EPA has

Did EPA consider the use of precombustion measures in establishing the MACT floor? The EPA first considered the feasibility of fuel substitution from several perspectives: (1) Switching to other fuels used in the same subcategory ( e.g. , a “lower” Hg content bituminous coal); (2) switching to fuels used in another subcategory ( e.g. , firing bituminous coal instead of lignite coal); or (3) switching to natural gas. The EPA considered several aspects of fuel switching in evaluating these alternatives. These aspects included whether switching fuels would achieve lower Hg and Ni emissions, whether fuel switching could be technically achieved considering the existing design characteristics of electric Utility Units, and the availability of various types of fuel.

For coal-fired units, the first aspect considered was fuel switching either to a better (or lower Hg-containing) seam of coal used within a subcategory or used in another subcategory. The question of whether switching between coals is a viable option arises from the variation in Hg content and other key attributes in different seams of coal. The data indicate that, although one seam may have less Hg than another, it may be higher in other chemical constituents of concern. The EPA has no data on which to determine the “best” seam, or rank, of coal on which to base such a requirement. Further, even if a “better/best” seam could be identified, changing to a specific or different seam of coal would essentially determine the area or even mine from which the coal could be produced. The fuel substitution issue then becomes dependent on the regional differences in coal characteristics and the subsequent feasibility of placing a burden on units that are located further from the better/best seams. The EPA feels that the intent of the CAA is to develop standards that, to the greatest extent reasonably possible, are consistent across the industry and avoid actions that create regional disparities

ution issue then becomes dependent on the regional differences in coal characteristics and the subsequent feasibility of placing a burden on units that are located further from the better/best seams. The EPA feels that the intent of the CAA is to develop standards that, to the greatest extent reasonably possible, are consistent across the industry and avoid actions that create regional disparities. The EPA further feels that requiring all plants to combust coal from a specific seam is not a viable long-term solution because the supply of coal from that seam would be rapidly depleted. Finally, EPA has determined (as stated earlier) that the existing Utility Units were designed based on the availability of certain coal ranks and has found that, in some instances, the units were actually co-located with a particular coal source.

Another perceived use of alternate ranks or seams of coal is to use clean coal. The term “clean coal” generally refers to a fuel that is lower in sulfur and/or ash content. Data gathered by EPA indicate that within specific coal ranks, the Hg content can vary significantly and that lower sulfur content does not necessarily mean lower Hg content.

Certain physical characteristics of coal-fired units also limit the effectiveness of prevention measures. A unit may require extensive changes to the coal handling and feeding system ( e.g. , a stoker using bituminous coal as fuel would need to be redesigned) in order to burn a different rank of coal. Additionally, existing burners and combustion chamber designs are generally not capable of handling different coal ranks, and generally cannot accommodate increases or decreases in the coal volume and shape. For example, burners are designed partially on the hardness of the coal; changing coal ranks could result in a harder coal and increased wear on the burners. The size of the burner and combustion chamber are based, in part, on the heating value of the coal rank; lower rank coals require larger systems for the same amount of heat input

ccommodate increases or decreases in the coal volume and shape. For example, burners are designed partially on the hardness of the coal; changing coal ranks could result in a harder coal and increased wear on the burners. The size of the burner and combustion chamber are based, in part, on the heating value of the coal rank; lower rank coals require larger systems for the same amount of heat input. Design changes to allow different coal use may, in some cases, reduce the capacity and efficiency of the unit. Reduced efficiency results in a lack of effective energy usage and may result in less complete combustion and, thus, an increase in emissions.

Another factor supporting EPA's conclusion that precombustion measures are not a viable emissions reductions approach for all units in the category is the lack of available alternative types of fuel for a given unit. Natural gas pipelines are not available in all regions of the U.S. Even where pipelines provide access to natural gas, supplies of natural gas may not be available in adequate quantities for utilities. For example, it is common practice in large metropolitan areas during winter months (or periods of peak demand) to prioritize natural gas usage for residential areas before industrial areas ( i.e. , natural gas curtailments). Requiring an EPA-regulated utility unit to switch to natural gas would place an even greater strain on natural gas resources, and, in some circumstances, the change would interfere with a unit's ability to run at full capacity. For these reasons, EPA decided that fuel switching is not an appropriate criterion for identifying the MACT floor level of control for existing coal-fired units.

With regard to process changes, EPA found that Hg and Ni emissions of concern from coal- and oil-fired units are primarily dependent upon the composition of the fuel and, to a lesser extent, the combustion process. Consequently, process changes ( i.e

ons, EPA decided that fuel switching is not an appropriate criterion for identifying the MACT floor level of control for existing coal-fired units.

With regard to process changes, EPA found that Hg and Ni emissions of concern from coal- and oil-fired units are primarily dependent upon the composi

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