[Federal Register Volume 69, Number 20 (Friday, January 30, 2004)]
[Proposed Rules]
[Pages 4652-4752]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 04-1539]




[[Page 4651]]

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Part IV





Environmental Protection Agency





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40 CFR Parts 60 and 63




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; 
Proposed Rule

  Federal Register / Vol. 69, No. 20 / Friday, January 30, 2004 / 
Proposed Rules  

[[Page 4652]]


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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.

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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). 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.
    The added benefit of this cap-and-trade approach is that it 
dovetails well with the sulfur dioxide (SO2) and nitrogen 
oxides (NOX) 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 SO2 and NOX emissions from 
the power sector. The advantage of regulating Hg at the same time and 
using the same regulatory mechanism as for SO2 and 
NOX is that significant Hg emissions reductions can and will 
be achieved by the air pollution controls designed and installed to 
reduce SO2 and NOX. In other words, significant 
Hg emissions reductions can be obtained as a ``co-benefit'' of 
controlling emissions of SO2 and NOX. Thus, the 
coordinated regulation of Hg, SO2, and NOX 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.
    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/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, [email protected].

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

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                                    NAICS      Examples of potentially
            Category              code \1\       regulated entities
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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. To determine whether your 
facility, company, business, organization, etc., is regulated by this 
action, you should examine the applicability criteria in Sec. 63.9981 
of the proposed rule or Sec.Sec. 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/.
    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.
    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.
    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

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comment due to technical difficulties and cannot contact you for 
clarification, EPA may not be able to consider your comment.
    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. 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 [email protected], 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).
    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.
    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. 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. 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

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Existing Sources: Electric Utility Steam Generating Units
    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. 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?

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).)
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    \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).
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    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.
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    \2\ A stationary source that is not a major source is an ``area 
source.'' CAA section 112(a)(2).
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    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?
    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

[[Page 4656]]

summarized its conclusions with regard to the HAP in the Utility RTC.
    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.
    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). 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\
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    \4\ Subsequent to issuance of the December 2000 Notice, EPA also 
conducted additional modeling for HCl, chlorine (Cl2), 
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).
    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. (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 x 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. 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.

[[Page 4657]]

    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. 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.
    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. 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?

    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

[[Page 4658]]

on oral exposure of methylmercury as it is the route of primary 
interest for human exposures. Methylmercury is a well-established human 
neurotoxin although, as with many chemicals, the scientific community 
is divided on the specific dose and frequency of exposure required to 
elicit adverse effects. According to the NAS, chronic low-dose prenatal 
methylmercury exposure has been associated with poor performance on 
neurobehavioral tests in children, including those tests that measure 
attention, visual-spacial ability, verbal memory, language ability, 
fine motor skills, and intelligence. Furthermore, it has been 
hypothesized that there is an association between methylmercury 
exposure and an increased risk of coronary disease in adults; however, 
this hypothesis warrants further study as the few studies currently 
available present conflicting results. (NEJOM; 2002; Yoshizawa, 2002; 
Guallar, 2002; Salonen, 1999; Salonen, 1995; Bolger, 2003).
    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. 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. 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. 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. The EPA 
has classified Ni carbonyl as a Group B2, probable human carcinogen 
based on lung tumors in animals. (see

[[Page 4659]]

http://www.epa.gov/ttn/atw/hlthef/nickel.html).
    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 x 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. 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.
    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. 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\
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    \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.
    Our December 2000 finding stated that it was necessary to regulate 
HAP

[[Page 4660]]

emissions from coal- and oil-fired Utility Units under section 112 
``because the implementation of other requirements under the CAA will 
not adequately address the serious public health and environmental 
hazards arising from such emissions identified in the [U]tility RTC and 
confirmed by the NAS study, and which section 112 is intended to 
address.'' 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.
    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. 
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). 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).
    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

[[Page 4661]]

same form as all other sources, despite the lack of any health-based 
finding that regulation of all HAP is appropriate or necessary. 
Furthermore, and as discussed elsewhere in this notice, such an 
interpretation would impose regulatory mandates with no discernable 
benefit to public health. The EPA is not inclined to impose costly 
regulatory mandates with no discernable public health benefit in the 
absence of clear direction by Congress that EPA must do so.
    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).
    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.
    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.
    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).
    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. Because 
Congress directed EPA to develop control strategies that would be 
alternatives to the usual section 112(d) MACT

[[Page 4662]]

standard, it is reasonable to conclude that Congress authorized EPA to 
implement such alternatives.
    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., 
NOX, SO2, 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.''
    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.
    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 SO2 program, the Acid Rain 
NOX program, the NOX 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. 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. 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
------------------------------------------------------------------------
                                                Hg (lb/         Hg (10-6
                  Unit type                      TBtu)           lb/MWh)
                                                  \1\               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.


[[Page 4663]]


 Table 2.--Emission Limits for Existing Oil-Fired Electric Utility Steam
                            Generating Units
------------------------------------------------------------------------
                                        Ni (lb/                 Ni (lb/
              Unit type                 TBtu) 1                 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
------------------------------------------------------------------------
                                                               Hg (10-6
                          Unit type                            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
------------------------------------------------------------------------
                                                                Ni (lb/
                          Unit type                             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. 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. 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 Sec. 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.
    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 Sec. 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 Sec. 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. The owner/operator would use the procedures outlined in Sec. 
63.10009 of the proposed rule to convert the concentration output of

[[Page 4664]]

Method 29 to an emission rate format in lb/TBtu or lb/MWh.
    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 Sec. 
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. 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?
    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. 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

[[Page 4665]]

emission characteristics due to their different fuels. The electric 
utility industry generally uses coal-fired units as base-loaded units 
(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. 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.
    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).
    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.
    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 SO2 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

[[Page 4666]]

characteristic that all conventional boilers have in common is that 
they inject PC and primary air through a burner where ignition of the 
PC occurs, which in turn creates an individual flame. Conventional 
boilers fire through many such burners mounted in the furnace walls.
    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.
    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.
    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.
    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.
    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

[[Page 4667]]

exclusively or to alternate between oil and natural gas at a single 
boiler is usually based on economics or fuel availability (including 
seasonal availability). The ASTM classifies oils by ``grade,'' a term 
which relates to the amount of refinement that the oil undergoes. The 
level of refinement directly affects the Ni and carbon content of the 
oil and other related parameters such as sulfur content, heating value, 
and specific gravity. The most refined fuel oil used by the oil-fired 
electric utility industry is known as No. 2 fuel oil (also known as 
distillate oil or medium domestic fuel oil). The least refined fuel oil 
used by the oil-fired electric utility industry is known as No. 6 fuel 
oil (also known as residual oil or Bunker C oil). By comparison, No. 2 
fuel oil is lower in Ni, sulfur, ash content, and heating value but 
higher in carbon content than No. 6 fuel oil. Only a handful of boilers 
(8 of 218) fire No. 2 distillate fuel oil exclusively. (2001 EIA data) 
However, 28 out of 218 boilers fire No. 2 distillate fuel oil and No. 6 
(residual) fuel oil in the same boiler (either simultaneously or at 
separate times).
    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. 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.
    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 NOX, 
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. 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.
    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.

[[Page 4668]]

    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.
    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. 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 NOX 
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. 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. 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

[[Page 4669]]

determined that none of these approaches are viable for all of the 
units in the coal- and oil-fired electric utility source category.
    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. 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. 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., changes to unit design/
operation) would be ineffective in reducing these fuel-related Hg and 
Ni emissions. The EPA did not identify any process changes or work 
practices that would be appropriate criteria for identifying the MACT 
floor level of control for existing coal- or oil-fired units.
    In general, electric Utility Units are designed for efficient 
combustion. Facilities have an economic incentive to ensure that fuel 
is not wasted and that the combustion device operates properly and is 
appropriately maintained. In fact, historical data show that the 
average heat rate (i.e., heat energy required to produce 1 kWh of 
electricity) declined by 11-fold between 1899 and the mid-1960s, mainly 
because of the desire to run efficient plants. The EPA was also unable 
to identify any uniform requirements or set of work practices that 
would meaningfully reflect the use of GCP or that could be meaningfully 
implemented across any subcategory of units. Therefore, EPA has not 
found combustion practice requirements useful in determining the MACT 
floor for existing coal- or oil-fired units. However, EPA's inability 
to establish a combustion practice requirement as part of the MACT 
floor for existing units does not reduce the incentive for owners/
operators to operate their units at top efficiency.
    The EPA requests comments and emissions information regarding 
whether there are any uniform GCP for controlling Hg and Ni that would 
be appropriate for minimizing Hg and Ni emissions from any subcategory 
of electric Utility Units.
4. How Did EPA Derive the MACT Floor for Each Subcategory?
    As noted above, the EPA has determined that coal rank and resulting 
system design characteristics warrant subcategorization within coal-
fired units. Once EPA determined that precombustion techniques were not 
helpful in determining the MACT floor for the entire source category, 
the next step was to develop a MACT floor for each subcategory based on 
the control technology used by the top-performing units (i.e., 
equipment based), and the level of emissions reductions (i.e., emission 
limitation based) that the top units in each subcategory demonstrated.

[[Page 4670]]

    The EPA had data from an evaluation of the Hg control performance 
of various emission control technologies that are either currently in 
use on coal-fired units (designed for pollutants other than Hg) or that 
could be applied to such units for Hg control. According to the 
available data, none of the existing control systems were specifically 
designed to remove Hg; however, most of the controls removed Hg to some 
degree. The most prevalent control technology used in the industry was 
the ESP, which was designed to control PM. Fabric filters or the 
combination of spray dryer adsorbers (SDA) and fabric filters were, 
however, found to be the most effective control technology for Hg 
removal generally.
    Unfortunately, the best Hg control technology scenarios were not 
consistent with regard to the extent to which they removed Hg. For 
these reasons, EPA decided to address Hg under the proposed rule using 
an emission limitation-based approach as opposed to a control 
equipment-based approach.
    As a result of the preceding evaluations, EPA concluded that the 
most appropriate approach for determining MACT floors for existing 
coal- and oil-fired units was to rank the emission test results from 
units within each subcategory from lowest to highest and calculate a 
MACT floor emission limitation by taking the numerical average of the 
test results from the best-performing 12 percent (or equivalent) of 
affected sources. The MACT floor database consisted of all pollutants 
described in the 132 test reports, including multiple runs if they were 
available. Units were ranked based on the subcategorization scheme 
described elsewhere in this preamble, and then ranked from lowest to 
highest by Hg emission rates within each subcategory. For oil-fired 
units, the ranking process was based on the Ni emission rates.
5. How Did EPA Account for Variability?
    In establishing the MACT floor(s) for existing sources in a 
particular category or subcategory of sources, section 112(d)(3) of the 
CAA calls for EPA to determine the average level of emission limitation 
actually being achieved by the best-performing existing sources in that 
category or subcategory. For combustion sources such as Utility Units, 
variability in both the Hg or Ni content of the fuel combusted and the 
performance of a particular control device have a significant impact on 
the determination of the level of emission limitation actually being 
achieved. As a result, it is essential that EPA be able to identify and 
quantify the level of variability arising from these sources. This is 
borne out by the test report data EPA obtained through the ICR. That 
data, which EPA is confident are representative of the industry, shows 
a significant degree of variability, even within a given subcategory. 
The EPA, therefore, decided it was necessary to develop a methodology 
to address the multiple sources of the observed variability in order to 
assure that an emission limitation value could be derived that was 
representative of what was actually being achieved by the best-
performing units under all conditions expected to be encountered by 
those units. The origins of variability and approaches available for 
addressing the variability found in the test data are described below.
    Variability is inherent whenever measurements are made or whenever 
mechanical processes operate. Variability in emission test data may 
arise from one or more of the following areas: (1) The emission test 
method(s); (2) the analytical method(s); (3) the design of the unit and 
control device(s); (4) the operation of the unit and control device(s); 
(5) the amount of the constituent being tested in the fuel; and, (6) 
composition of the constituents in the fuel and/or stack gases.
    Test and analytical method variability can be quantified by 
statistical analysis of the results of a series of tests. The results 
can be analyzed to establish confidence intervals within which the true 
value of a test result is presumed to lie. Confidence intervals can be 
estimated for multiple-run series of tests based on the differences 
found from one test run to the next, with only the upper confidence 
interval having meaning (signifying the chance of the standard being 
exceeded).
    When testing is done at more than one unit, similar confidence 
intervals can be established to account for the variability from unit-
to-unit. One can combine the test-to-test and unit-to-unit variability 
into a single factor that can be applied to reported test values to 
give an upper limit for the likely true value. One can also estimate 
the combined factor for any desired confidence level.
    Another source of variability is the time interval during which the 
test is being conducted. Testing for a short time may not reveal the 
range of emissions that would be found over extended time periods. 
Normal changes in operating conditions or in fuel characteristics may 
affect emission levels over time. For example, an increase in the Hg or 
Ni content of the fuel being fired in a unit may tend to increase the 
Hg or Ni emission rate from the associated stack, even where the 
control efficiency of the APCD remains constant. Mercury emission rates 
may also change with unit loads due to changes in the gas flow rate 
through APCD downstream from the unit which may affect APCD 
effectiveness.
    Variability in control efficiency or emission rates may be 
addressed in a number of ways, depending on the circumstances existing 
within the source category. For example, different test run results can 
be analyzed statistically to arrive at an upper limit that represents 
the highest likely value for each test planned for use in setting 
emission limits. The poorest-performing (worst-case) unit in the top 12 
percent of each subcategory can be reviewed to determine the causes of 
poor performance. A factor, which when applied to each of the test 
runs, can more accurately reflect performance over the full range of 
operating conditions can then be developed. This results in emission 
values that would not likely be exceeded over long time periods. 
Another approach is to look only at the performance of control devices 
used by sources in the top 12 percent and then use that information to 
determine likely emissions reductions for different devices operating 
on different units firing different fuels. The range in emissions 
reductions derived in this manner could then be used to set upper 
limits of expected control performance (i.e., to identify the best 
performance that can be expected under the worst conditions); then, 
these limits could be used, as above, to set emission limitations for 
each subcategory. A third approach is to identify correlations between 
constituents of concern and other, perhaps more easily measured, 
constituents that can be used to develop algorithms that incorporate 
variability.
    In the context of developing a MACT standard, the issue of how to 
appropriately address variability arises in deriving the MACT floor 
level of control. In order to determine the average emission limitation 
actually being achieved by the best-performing sources in a category or 
subcategory, EPA must determine how those sources will perform over the 
full range of operating conditions they can reasonably be anticipated 
to encounter. Addressing variability in the MACT floor calculation 
requires that all of the origins of variability be assessed and 
quantified into factors that can be incorporated into the emission 
limitation calculations for each subcategory's floor. In this way, the 
actual performance of each of the floor units over the full range of 
operating conditions can be derived. The result of

[[Page 4671]]

this approach is that the measured emission rate for each unit used for 
floor calculations is increased to account for the variability found 
from statistical analysis, worst-case analysis, or control device 
performance analysis. The performance of each unit in the top 12 
percent of its subcategory would be adjusted to reflect the uncertainty 
associated with the various origins of variability, and the average 
emission rate for these units would be used as the floor emission 
limitation.
    In trying to address the apparent sources of variability in the 
emissions test data, EPA tried to obtain data that reflected as many 
different plant configurations as would be found in the entire industry 
profile and, through the ICR, required tests to be conducted at units 
believed to be representative of the various plant configurations and 
operating conditions found within the source category. The tests and 
measurements, typically a three-run series of manual samples taken over 
1 or 2 days of testing, are limited by the emission test method's 
accuracy and precision, by the short duration of the test, and by 
differences from one run to the next and one unit to the next. 
Together, these factors bring into question the accuracy of the results 
of the tests as a measure of a particular units performance over time. 
The EPA has evaluated the total population of test results to determine 
a valid test method variability factor for each type of control device 
as well a worst-case fuel variability factor. The EPA determined that 
it was necessary to evaluate the total population of test results to 
ensure that the resulting variability factors were an accurate 
predictor of the impacts of variability on the performance of the floor 
facilities. The variability factors were then applied in MACT floor 
emission limitation calculations, as appropriate. Applying these 
variability factors to the identified performance of the floor 
facilities, EPA has developed proposed emission limits for Hg for coal-
fired Utility Units and for Ni for oil-fired Utility Units. Information 
contained in the docket provides a detailed description of the analysis 
of the variability issues, including the methods available and used to 
address the variability in test data used for the proposed rule.
    How did EPA derive the proposed MACT floor emission limitations for 
existing sources? In order to determine the MACT floor emission limits 
for existing units, EPA examined the population database of existing 
sources. Available emissions test data were divided according to the 
subcategorization scheme described elsewhere in this preamble; first 
coal- and oil-fired, then the five subcategories of coal-fired units. 
The EPA examined the existing emission test data to determine the 
individual numerical average of the test results from the best-
performing 12 percent (or equivalent) of each subcategory for Hg or Ni. 
The EPA then applied the potential uncertainty and variability factors 
to derive the MACT floor limits. All test data were provided to EPA in 
an input-based format (lb/TBtu). Therefore, EPA conducted all MACT 
floor calculations using the input-based format and then converted the 
input-based format into an output-based format (lb/MWh) as a compliance 
option, according to the approach described elsewhere in this preamble. 
The discussion below describes the development of the emission 
limitation for each subcategory in the electric utility source 
category.
    The EPA initiated the evaluation of the units within each 
subcategory by ranking them from lowest to highest based on emission 
rates representing the outlet Hg or Ni concentration of the stack 
tests. This initial evaluation of the test report data indicated that 
no specific control technology or combination of technologies could be 
credited with the better performance; however, the evaluation indicated 
that fabric filter technology did provide a degree of Hg removal and 
that ESP units also provided a degree of removal, although to a less 
consistent and lower degree than did fabric filter units. The EPA 
further investigated the apparent inconsistency of Hg removal and found 
that the level of removal of Hg was dependent on the speciated form of 
Hg as presented to the control device. This phenomenon was further 
evaluated using the entire database of coal-fired units to determine if 
the variations in the control device performances could be correlated 
to the speciated form of the Hg presented to the APCD. This evaluation 
encompassed an evaluation of existing coal-fired units from the ICR 
data that provided Hg speciation data, Hg-in-coal data, and pre- and 
post-last-control unit emissions test data. The data indicated that 
where Hg was presented to the control device in particulate-bound form, 
both fabric filter and ESP devices provided a degree of control, with 
fabric filters generally performing better than ESP units. Where Hg was 
presented to the control device in an elemental form, the performance 
of the various control devices was highly variable. Part of the 
variation is believed to be attributable to the form of Hg in the flue 
gas, such as chlorine compounds. However, part of the variation is not 
understood at this time, thus the data are inconclusive. Testing has 
shown that the proportion and type of speciated Hg presented to an APCD 
is not consistent; however, as stated above, the data do indicate that 
PM controls are reasonably effective where particulate-bound Hg is 
present. This variation of the proportions of speciated Hg within the 
flue gas between units provided further explanation for the observed 
removal characteristics for different units using the same control 
technology. Further evaluation of Hg speciation indicated that 
different coal ranks tend to speciate to a predominantly similar 
proportion of speciated forms of Hg, thus further supporting the 
rationale for the subcategorization of coal-fired units based on coal 
rank.
    The EPA found, for the reasons indicated above, that although 
variable, fabric filter and ESP control technologies were reasonable 
and viable technologies on which to base the MACT floor level of 
control. The EPA then evaluated performance of the various fabric 
filter- and ESP-equipped units to determine what criteria would most 
effectively reflect the performance. The EPA considered using the 
percent efficiency of the control device, the percent reduction, and 
outlet concentration as viable criteria to demonstrate performance of 
the technology. However, the evaluation of these performance criteria 
proved problematic. The ICR Hg data were based on stack test data for 
the last control device at each utility unit tested. The emissions were 
measured in milligrams of Hg per volume of test solution used in the 
Ontario-Hydro method. Using the duct or stack flue-gas flow volume and 
the heat input to the unit being tested, the measured quantity of Hg 
was converted and reported in units of lb/TBtu. In reviewing the data, 
EPA found that the inlet measurement showed deficiencies due to the 
flow rate and short duct runs available for testing before the control 
device, and that these values were suspect as being reliable 
representations of actual inlet concentrations. The EPA, therefore, 
determined that evaluation of control device efficiency values based on 
unreliable inlet concentration data would not be justified. The EPA 
determined, however, that the outlet concentration data were reliable 
based on the method used and the fact that only one measurement was 
needed for the determination of the value. Another option was then to 
determine Hg reduction efficiency across the system.

[[Page 4672]]

This option would also address EPA's desire to promote, and give credit 
for, coal preparation practices that remove Hg before firing (i.e., 
coal washing or beneficiation). However, this option requires tracking 
the Hg concentrations in coal from receipt to stack, and not just 
before and after the control device(s) and could be difficult to 
implement. The EPA believes that an emission rate format would allow 
for the use of precombustion Hg removal processes. As a result, EPA 
believes that the most credible data element available that quantified 
performance would be the emission rates as provided in the stack test 
reports.
    The emission limitation for Hg emissions from existing coal-fired 
units was determined by analyzing the available Hg emissions data in 
each subcategory. The data were obtained from the ICR noted earlier and 
included data for Hg emissions, and Hg-in-coal and Cl-in-coal data for 
1999. The MACT floor calculations were based on the average performance 
of the top 12 percent of units in the individual subcategories of 
bituminous coal, subbituminous coal, lignite coal, coal refuse, and 
IGCC (coal gas).
    The variability of Hg emissions from coal-fired units is 
significantly influenced by the variability over time in the 
composition of the coal burned as fuel (i.e., differences in Hg 
content, Cl content, and heat content of coal). The differing physical 
and chemical properties of Hg-containing compounds in the flue gas 
result in significant differences in the feasibility and effectiveness 
of controls for removing the compounds from flue gas. The effectiveness 
of control devices at removing Hg depends to a large extent on the 
species of Hg in the flue gas. As a general matter, all of the control 
devices currently installed on Utility Units are most effective at 
removing Hg in the oxidized form (e.g., Hg\++\). Thus, which Hg species 
are present in the flue gas impacts the amount of Hg that will be 
captured by control devices and how much Hg will be released in stack 
emissions. Importantly, studies have shown that the Cl content of the 
coal has a significant impact on which Hg compounds are contained in 
the flue gas. Generally, the higher the Cl content relative to the Hg 
content, the greater the percentage of oxidized Hg (ionic or Hg\++\) 
contained in the flue gas. When combined with other relevant data, such 
as coal Hg content, the Cl content of coal can thus be used to predict 
a particular control device's ability to effectively reduce Hg 
emissions.
    The data results from a multi-variable study EPA performed on the 
ICR data demonstrate the significance of coal Cl content to Hg 
emissions controllability. The higher the Cl:Hg ratio, the more likely 
the formation of mercuric chloride (Hg\++\) that is more readily 
captured by existing control devices. This Cl:Hg ratio is independent 
of the coal rank as an indicator of Hg controllability.
    In summary, the coal Cl content is one of the primary determinants 
of which Hg-containing compounds will be present, and in what amounts, 
in the flue gas of an individual utility unit. The differing physical 
and chemical properties of Hg-containing compounds in the flue gas 
result in significant differences in the feasibility and effectiveness 
of controls for removing the compounds from flue gas.
    The EPA determined that the stack tests in the ICR database alone 
are insufficient to estimate the effect of fuel variability over time 
on the emissions of the best-performing facilities. The ICR database 
contains extensive data on variation in coal composition recorded over 
the course of a year. Therefore, to link fuel composition data to Hg 
emissions data, EPA developed a methodology using correlation equations 
to represent the relationship between the fraction of Hg removed and Cl 
concentration for each of the control configurations used by the best-
performing units. The correlation equations provide a mechanism for 
predicting the performance of each of the control devices installed on 
floor units when the unit is combusting any of the coals received by 
that unit during 1999. The steps used to develop these correlation 
equations are set forth below.
    The units in each of the five subcategories were sorted in 
ascending order of stack-tested Hg emission factor, measured in units 
of lb/TBtu (as adjusted by a method that normalizes Hg emissions to 
coal heat content (F-factor Adjustment)). Accordingly, the top 
performing units of each subcategory were selected for further 
analysis.
    The control configuration of each of the best-performing units 
(i.e., the floor units) was identified. The Hg removal fraction and 
test coal Cl concentrations were obtained from the ICR database for 
each of the units in the database that have one of the identified 
control configurations. It was necessary to look at all units employing 
the identified control configurations to ensure that the statistical 
r\2\ values of the subsequently derived correlation equations were 
sufficiently high to conclude that the correlation equations could 
accurately predict the Hg removal efficiency of a particular control 
device in operation on one of the floor units.\6\ Finally, a 
correlation equation was derived for each identified control 
configuration by fitting a mathematical expression to the Hg removal 
fractions and corresponding Cl concentrations obtained from the ICR 
stack test database. The correlation equations thus derived can be 
applied to any control device for which the Hg control efficiency, when 
the unit being controlled is burning a coal with an identified Cl:Hg 
ratio, is known to predict the control efficiency of that device when a 
coal with a different Cl:Hg ratio is burned.
---------------------------------------------------------------------------

    \6\ The r\2\ measures the strength of the relationship between 
any two variables in the sense that it provides the proportionate 
reduction in the sum of squares of vertical deviations obtained 
using a least squares approach. The largest value r\2\ can attain is 
1, which occurs when the residual sum of squares is equal to zero 
(i.e., all the data points lie on the curve), while the smallest 
value that r\2\ may take is 0, which means there is no improvement 
in predictive power using the independent variable. In our example, 
the two variables of concern in effecting Hg reductions are the Hg 
and Cl content of coal. Thus, the closer r\2\ comes to 1, the 
stronger the relationship between these two variables, and 
reductions in Hg emissions, for any given coal sample; and, on the 
other hand, the closer r\2\ comes to 0, the more likely there is 
little or no relationship between the two variables, and reductions 
in Hg emissions, for a given coal sample.
---------------------------------------------------------------------------

    In selecting the format of the correlation equation, care was taken 
that the mathematical expression accurately reflected the physical and 
chemical process by which Cl contributes to the controllability of 
stack Hg emissions. The correlation equation is based on the assumption 
that the rate of conversion of Hg to mercuric chloride (an oxidized 
form) is proportional to the Cl concentration in the coal, irrespective 
of coal rank. With this expression, the maximum removal fraction is 
limited to 1, because the exponent term is always nonnegative, 
regardless of the Cl concentration. This corresponds to the real-world 
limitation that no more than 100 percent of the Hg in flue gas can be 
removed (i.e., there cannot be negative Hg emissions). As the coal Cl 
concentration drops to zero, the Hg removal fraction does not approach 
zero because some Hg removal is achieved even without reaction with Cl. 
The purpose of deriving a correlation equation for each control 
configuration used by the top performing units was to provide a 
numerical means of predicting the fraction of Hg removed for the best-
performing sources over the entire range of fuel variability 
experienced by each of those sources over the course of a year. 
Correlation equations were derived for each control configuration, but 
were only used to predict Hg removal if they

[[Page 4673]]

were found to have acceptable explanatory power.
    To determine whether the explanatory power of each correlation 
equation warranted its use on a larger range of ICR coal composition 
data, each correlation equation was validated against the ICR stack 
test data. For each of the Cl concentrations in the ICR stack test 
database for 1999, the Hg removal fraction was calculated by using the 
correlation equation with parameters selected to give the best fit to 
the data. A correlation coefficient was then calculated to evaluate the 
accuracy of the fit.
    For each of the best-performing units, unit-specific coal 
composition data for a one-year period were extracted from the ICR 
database to find the coal heat content, Hg content and Cl content. For 
each set of coal composition data from the ICR database, the controlled 
Hg emissions were calculated by multiplying uncontrolled Hg emissions 
by (1-Hg removal fraction). For each of the best-performing sources, 
this process was repeated for each set of measured coal composition 
values, yielding a range of controlled Hg emission levels for that unit 
over time.
    The test coal composition data from the ICR database (heat and Hg 
content) was used to calculate the uncontrolled Hg emission level. The 
Hg removal fraction was calculated in one of the following two ways:
    (1) Where the correlation equation was found to have sufficient 
explanatory power, it was used to estimate the Hg removal fraction 
based on coal Cl composition data from the ICR data base. This approach 
accounted for variations in the Hg, Cl, and heat content of fuel.
    (2) Where the correlation equation was a poor fit, the Hg removal 
fraction was based on the average Hg removal fraction observed in the 
ICR stack tests of that unit. This latter approach yielded a constant 
removal fraction based upon the source test, and had the effect of 
reducing the variability of predicted Hg emissions. Under this 
approach, the measured impact of fuel variability was limited to the 
effect of variations in Hg and heat content, while variations in Cl 
concentration were not explicitly considered.
    For each of the best-performing units, the calculated controlled Hg 
emissions, calculated in accordance with the procedures outlined above, 
were then sorted from smallest to largest to obtain a cumulative 
frequency distribution (CFD). The 97.5th percentile value of this 
distribution (i.e., an emission rate that is expected to be exceeded 
only 2.5 percent of the time) was determined to represent the operation 
of the unit under conditions reasonably expected to occur at the unit.
    It is necessary also to account for inter-unit variability among 
the top performers. The analysis of within-unit variability considered 
only the top units in each subcategory. A focus on within-unit 
variability alone is not expected to capture the full range of 
emissions variability among the best-performing sources. The EPA 
accounted for this variability by calculating a 97.5 percent upper 
confidence level for the mean by use of the student t-statistic.
    The EPA calculated the emission limitation for Hg for the 
subcategories of bituminous-fired, subbituminous-fired, lignite-fired, 
IGCC, and coal refuse-fired units as follows.
    For bituminous-fired units, EPA had data from 32 units. Because 
this subcategory (i.e., nationwide population) included more than 30 
units, EPA determined that the top 12 percent of the units in the 
subcategory would be composed of 12 percent of the number of units for 
which EPA had data (i.e, 4 units). The EPA determined the top four 
units from a ranking of units based on their emission rates from the 
stack test reports. The emission rates from these units ranged from 
0.1062 lb/TBtu to 0.1316 lb/TBtu, with an average of 0.118 lb/TBtu. 
After applying variability as described above and rounding to 2 
significant figures, EPA determined the inlet-based emission limitation 
to be 2.0 lb/TBtu. Using the conversion described elsewhere in this 
preamble (and based on 32 percent net efficiency), the inlet-based 
emission limitation of 2.0 lb/TBtu was converted to 21 x 
10-6 lb/MWh as the outlet-based emission limitation.
    For subbituminous-fired units, EPA had data from 32 units. Because 
this subcategory (i.e., nationwide population) included more than 30 
units, EPA determined that the top 12 percent of the units in the 
subcategory would be composed of 12 percent of the units for which EPA 
had test data (i.e., 4 units). The EPA determined the top units from 
the ranking of the units based on their emission rates from the stack 
test reports. The emission rates from these units ranged from 0.4606 
lb/TBtu to 1.207 lb/TBtu, with an average of 0.738 lb/TBtu. After 
applying variability as described above and rounding to 2 significant 
figures, EPA determined the inlet-based emission limitation to be 5.8 
lb/TBtu. Using the conversion described elsewhere in this preamble (and 
based on 32 percent net efficiency), the inlet-based emission 
limitation of 5.8 lb/TBtu was converted to 61 x 10-6 lb/MWh 
as the outlet-based emission limitation.
    For lignite-fired units, EPA had data from 12 units. Because this 
subcategory (i.e., nationwide population) consisted of fewer than 30 
units, EPA determined that the top performers must include the top 5 
units. The emission rates from these units ranged from 3.977 lb/TBtu to 
6.902 lb/TBtu, with an average of 5.032 lb/TBtu. After applying 
variability as described above and rounding to 2 significant figures, 
EPA determined the inlet-based emission limitation to be 9.2 lb/TBtu. 
Using the conversion described elsewhere in this preamble (and based on 
32 percent net efficiency), the inlet-based emission limitation of 9.2 
lb/TBtu was converted to 98 x 10-6 lb/MWh as the outlet-
based emission limitation.
    For IGCC units, EPA had data on two units. Because this subcategory 
(i.e., nationwide population) included less than 30 units, EPA 
determined that all available units would be included and were ranked 
based on their emission rates from the stack test reports. The emission 
rates from these units ranged from 5.334 lb/TBtu to 5.471 lb/TBtu, with 
an average of 5.403 lb/TBtu. The EPA applied the variability factors 
and, with rounding to two significant figures, determined the IGCC 
input-based emission limitation to be 19 lb/TBtu. Using the conversion 
described elsewhere in this preamble (and based on 32 percent net 
efficiency), the inlet-based emission limitation of 19 lb/TBtu was 
converted to 200 x 10-6 lb/MWh as the outlet-based emission 
limitation.
    For coal refuse-fired units, EPA had data from two units. Because 
this subcategory (i.e., nationwide population) included fewer than 30 
units, EPA used all units for the calculation based on their emission 
rates from the stack test reports. The emission rates from these units 
ranged from 0.0816 lb/TBtu to 0.0936 lb/TBtu, with an average of 0.0876 
lb/TBtu. The EPA applied the variability factors as described above and 
with rounding to two significant digits, determined the input-based 
emission limitation to be 0.38 lb/TBtu. Using the conversion described 
elsewhere in this preamble (and based on 32 percent net efficiency), 
the inlet-based emission limitation of 0.38 lb/TBtu was converted to 
4.1 x 10-6 lb/MWh as the outlet-based emission limitation.
    The EPA believes that the Hg emission limitations derived above, 
using the test data adjusted for appropriate variability, provide a 
reasonable estimate of the actual performance of the MACT floor units 
under all conditions expected to be encountered over time.
    Some have argued that the experience gained from regulation of 
Municipal

[[Page 4674]]

Waste Combustors and Health, Medical and Infectious Waste Incinerators 
in the early 1990s indicates that coal-fired power plants should be 
able to achieve 90 percent Hg emission reductions (see ``Out of Control 
and Close to Home: Mercury Pollution from Power Plants.'' Environmental 
Defense. 2003). The EPA expects that some Utility Units can achieve 
such high reduction rates, depending on factors such as the Hg and Cl 
content of different coals, as outlined above. However, there are 
important technical differences between Utility Units and municipal 
waste combustors and health, medical and infectious waste incinerators. 
Consequently, EPA believes 90 percent emission reductions cannot be 
achieved across all Utility Units in the proposed section 112 time 
frame. First, the percentage of emissions that is elemental Hg is much 
larger in coal-fired boilers than in the waste combustors and 
incinerators (e.g., 50 percent versus 2-20 percent, as stated in EPA's 
Mercury Study Report to Congress). Second, Hg emissions from the waste 
combustors and incinerators can be reduced effectively through waste 
separation techniques, which remove Hg-containing items from the 
incoming waste stream (e.g., batteries). Application of similar 
measures at coal-fired Utility Units, such as effective pre-combustion 
Hg removal, is not widely feasible at this time, though some innovative 
techniques are under development. Third, the Hg emissions at the waste 
combustors and incinerators often occur as infrequent, high-
concentration ``spikes,'' which are more easily controlled than highly 
diluted Hg in the flue gas found at coal-fired Utility Units. The 
technical differences between Utility Units and municipal waste 
combustors and health, medical and infectious waste incinerators need 
to be recognized (see ``Mercury Emissions from Coal-Fired Power Plants: 
The Case for Regulatory Action,'' NESCAUM, 2003).
    Are there other approaches to addressing variability? The approach 
selected by EPA for addressing variability is not the only approach 
that could be appropriate for evaluating emissions from the best-
performing units. The Department of Energy (DOE) has conducted a 
similar analysis to that described above, but with one significant 
difference. (DOE, 2003.) In calculating a MACT ``floor'' rate, DOE 
considered that variability at a best-performing unit could be based on 
assuming that the unit could switch to a coal not previously burned at 
the unit during the one-year period covered by the ICR, but having the 
same rank as the coal used at the best-performing unit. Because the 
alternative coals were of the same rank and not precluded from use by 
regulation or permit, DOE concluded that the combination of emission 
algorithms, unit-specific stack tests, and ICR coal data from other 
units constituted relevant emission estimates under worst conditions at 
the best-performing units.
    The essence of the DOE analysis was to average at a plant level the 
Hg and Cl contents of all coals, by rank, in the ICR data base. Then, 
DOE adjusted the performance test results at the lowest emitting units 
in the ICR data base by assuming that they burn a coal similar to the 
97.5th percent worst plant annual average coal. For bituminous coal 
units, the coal Cl resulted in the greatest variability in emissions. 
For subbituminous coals, the coal Hg content was more critical than Cl 
content. The DOE found that most lignite-fired power plants were 
directly associated with a single mine, and decided that assuming a 
switch to coals from other mines was not reasonably justified. 
Therefore, for lignite units, DOE would recommend using the approach 
presented earlier by EPA. In addition, for bituminous coals, DOE found 
that many of the lowest Cl bituminous coals are produced in the western 
U.S. and are unlikely to be used in eastern power plants, where the 
bulk of bituminous coal is burned. Those western coals were excluded 
from the variability analysis.
    Using this approach, DOE found that an appropriate MACT floor rate 
for bituminous coal was 2.6 lb/TBtu heat input. The rate for 
subbituminous coals was 5.4 lb/TBtu heat input. The EPA seeks comment 
on alternative approaches to addressing source emission variability, 
such as DOE's. In particular, we ask for comment on the relevance of 
Cement Kiln Recycling Coalition to the DOE approach.
    How did EPA address blended coals? The EPA recognizes that many 
Utility Units burn more than one rank of coal, either at the same time 
(i.e., blending) or at separate times during a year (i.e., seasonally). 
Further, EPA is aware that several units burn a supplementary fuel 
(e.g., petroleum coke, tire-derived fuel (TDF), etc.) in addition to a 
primary coal fuel. The EPA recognizes this practice and acknowledges 
the effect that coal blending (or use of supplementary fuels) will have 
on Hg emissions. Because this rule does not apply to the non-regulated 
supplementary fuels, the rule does not provide an emission limitation 
for those fuels. The EPA believes that the most appropriate means to 
address the blending scenarios is through the compliance demonstration.
    The EPA has identified several blending scenarios that might occur 
in the industry; blending two or more ranks of coal, blending one rank 
of coal with a supplementary (non-regulated fuel), or blending multiple 
ranks of coal with a supplementary (non-regulated) fuel.
    There are two potential methods for addressing the blending 
scenarios where two or more ranks of coal are fired. One approach to 
address blended coal would be to classify a unit based on the 
predominate coal it burns. For example, if 90 percent of the coal 
burned for the compliance period were bituminous, the unit would be 
classified as bituminous and would have to meet the Hg emission 
limitation for bituminous coal. Although this approach is desirable 
from a simplicity standpoint, EPA believes that this approach is not 
equitable nor reflective of actual practice in the industry. Therefore, 
EPA is proposing a second, potentially more equitable, approach 
involving development of a weighted Hg emission limit based on the 
proportion of energy output (in Btu) contributed by each coal rank 
burned during the compliance period and the coal's subcategory Hg 
emission limitation. The weighted emission limit would, in effect, be a 
blended emission limitation based on the Hg emission limitations of the 
subcategories of the coals burned.
    The other scenarios discussed above involve blending a regulated 
fuel (e.g., coal or coal refuse) with a supplementary, non-regulated 
fuel (e.g., petroleum coke, TDF, etc.). The application of the same 
methods would be appropriate for units that burn a regulated fuel with 
supplementary, non-regulated fuels; however, there would be no 
adjustment to the Hg emission limitation with regard to the 
supplementary, non-regulated fuel.
    The weighted Hg emission limitation would be developed based on the 
proportions of energy output (Btu) contributed by only the regulated 
fuels. For example, if the unit burned bituminous, subbituminous, and 
petroleum coke during the compliance period, and where 40 percent of 
the Btu output was attributable to the bituminous, 40 percent to the 
subbituminous, and 20 percent to the petroleum coke, the blended Hg 
emission limitation would be based on the bituminous and subbituminous 
emission limitations in a 50/50 ratio. The compliance calculation would 
include the energy output (Btu) of all fuels burned (including the 
supplementary fuel), the emissions

[[Page 4675]]

considered would include all Hg emission measured by the CEMS, and the 
unit would comply with the blended Hg emission limitation. The 
compliance demonstration outlined in Sec. 63.9990(a)(6) of the proposed 
rule provides the calculation of the blended Hg emission limitation 
applicable under this approach.
    How did EPA address Ni from oil-fired units? The proposed emission 
limit for Ni from existing oil-fired units was determined by analyzing 
the emissions data available. The data were obtained from the Utility 
RTC which provided information indicating that Ni was the pollutant of 
concern due to its high level of emissions from oil-fired units and the 
potential health effects arising from exposure to it. The EPA examined 
available test data and found that units equipped with ESP units (for 
PM control) can effectively reduce Ni. The controls currently in use on 
electric utility oil-fired units to address PM were installed as a 
result of requirements to address criteria pollutants under other 
regulations. The data available to EPA indicate that the Ni is present 
in flue gas streams in varying concentrations, yet mostly in 
particulate form. The Utility RTC emissions test data support the 
conclusion that the same control techniques used to control the fly-ash 
PM will also indiscriminately control Ni and that the effective removal 
of PM indicates removal of Ni, for a given control device. Therefore, 
EPA believes that ESP technology represents the MACT floor for Ni for 
the proposed rule. The EPA has determined that the proposed emission 
limitation for the oil-fired units should reflect the performance that 
would be expected over time for a well designed and operated ESP.
    The EPA determined the value of the Ni emission limitation by 
ranking the stack test emission rates for Ni of the 17 units for which 
EPA had data. The top 12 percent of the units, or 2 units, were 
controlled by ESP and the range of emission rates was 29.97 to 357.16 
with an average of 125.06 lb/TBtu. After applying variability as 
described above and rounding to 2 significant figures, EPA determined 
the inlet-based emission limitation to be 210 lb/TBtu. The output-based 
Ni emission limitation was determined to be 0.002 lb/MWh after 
conversion using 32 percent net efficiency. The EPA believes that these 
emission limits are a reasonable estimate of the actual performance of 
the MACT floor unit in reducing Ni on an ongoing basis.
    The Agency is sensitive to the fact that some sources burn fuels 
containing very little Ni and that compliance with the Ni emission 
limitation could be burdensome in cases where the potential Ni 
emissions would be very low. Therefore, EPA is considering an 
alternative Ni-in-oil emission limit which would be equivalent to the 
main standard. An existing source would be able to choose to comply 
with the alternative Ni-in-oil emission limitation instead of the Ni 
emission limitation (either input- or output-based) to meet the 
proposed rule. The alternate Ni-in-oil emission limitation would be 
based on a correlation between the Ni constituent concentration in the 
oil burned and the expected Ni emissions in the flue gas. Data 
available to EPA does not provide a consistent correlation methodology 
for determination of an appropriate Ni constituent level in oil. The 
EPA is soliciting comment on the usefulness of such an alternative Ni-
in-oil limit and the availability of any correlation methodology and 
data for determining a Ni concentration level in oil that could be 
shown to be equivalent to the proposed emission limitation.
    The EPA solicits comments on these approaches and on others that 
might present a better method for addressing variability in development 
of the emission limitations.
    How did EPA address dual-fired units? The EPA is aware that an oil-
fired unit may fire oil at certain times of the year and natural gas at 
other times, as well as blends of residual oil and distillate oil. This 
blending of fuels is conducted for many reasons, most of which are 
economically driven with regard to the availability of fuels and the 
price, and may be seasonal in nature. As stated elsewhere in this 
preamble, EPA considers a unit to be an oil-fired unit if (1) it is 
equipped to fire oil and/or natural gas, and (2) it fires oil in 
amounts greater than or equal to 2 percent of its annual fuel 
consumption. This 2 percent value is intended to represent that amount 
of oil that a true natural gas-fired unit might use strictly for start-
up purposes on an annual basis.
    As stated earlier for coal blending, EPA does not intend to address 
the fuel blending scenarios with specific emission limitations, but 
rather address the issue during the compliance demonstration.
    In the proposed rule, units that burn distillate oil exclusively 
would be exempt from the requirements of the rule and natural gas-fired 
units would be excluded from the definition of an affected source. 
Therefore, the requirements of the proposed rule would apply to units 
that fire residual oil in any proportion with another oil, and to units 
that fire residual oil at 98 percent or greater of its annual fuel 
consumption, where the supplementary fuel is natural gas. The blending 
scenarios that might occur for oil-fired units include the co-firing of 
residual oil with distillate oil, and the firing of residual oil and 
natural gas at different times. The EPA believes that a cutoff of 2 
percent fuel oil-firing would separate those units that are 
``fundamentally'' natural gas-fired but, for start-up or other 
operational needs, periodically burn fuel oil.
    Under the proposed rule, a unit that burns residual oil exclusively 
would be required to meet the oil-fired Ni emission limitations. For 
units that burn exclusively distillate oil, the unit would be exempted 
from meeting the Ni emission limitation requirement. For units that 
blend residual oil with distillate oil, the unit would be required to 
meet the Ni emission limitations in the proposed rule, and would 
include all Btus or MWh generated from the use of the distillate oil in 
the compliance demonstration calculation. Likewise, a unit that burns 
residual oil during certain periods and natural gas during certain 
periods would include the natural gas-fired contributions (Btu or MWh) 
in the compliance calculation.
    Although EPA has not identified any other supplementary fuels 
burned in the oil-fired industry, we are aware that such a scenario may 
exist or might occur in the future. For the purposes of the proposed 
rule, EPA intends that where any supplementary fuel is co-fired with 
residual oil, the Btus or MWh contributed by the supplementary fuel be 
accounted for in the compliance calculation, and that the unit would be 
required to meet the Ni emission limitation for existing oil-fired 
units.
    The EPA solicits comment on whether the 2 percent breakpoint is a 
reasonable basis for allowing those units that use oil only for startup 
purposes to be exempted from regulation under the proposed rule.
6. How Did EPA Consider Beyond-the-Floor Options for Existing Units?
    The EPA considered available regulatory options (i.e., technologies 
or work practices) that were more stringent than the MACT floor level 
of control for each of the different subcategories. Except for IGCC, we 
have not identified technologies or work practices that provide a 
viable basis for establishing standards beyond-the-floor. Described 
below are the candidate technologies and work practices that we 
considered in our analyses. We ask for comment on these technologies 
and other control techniques that could provide

[[Page 4676]]

consistently lower levels of emissions of Hg and Ni than those 
demonstrated by the MACT floor level of control. Additional information 
on the beyond-the-floor analyses for existing units is available in the 
document titled, ``Beyond the Floor Analysis for Existing and New Coal- 
and Oil-Fired Electric Utility Steam Generating Units NESHAP'' which 
can be found in the docket.
    Coal-fired units. Conventional PM controls (ESP and fabric filters) 
generally do not remove the vapor-phase Hg0 from coal-fired 
unit emissions. This is because these controls do not capture gaseous 
pollutants. Two technologies that possibly could be used to further 
reduce the amount of vapor-phase Hg emitted from utilities are sorbent 
injection and selective catalytic reduction (SCR).
    Sorbent injection. Due to their multiple internal pores and high 
specific surface area, sorbents have the potential to improve the 
removal of Hg (mostly through the enhanced capture of elemental Hg; 
sorbents will also remove Hg++) as well as other gaseous 
pollutants that are carried with combustion fine particulates in all 
coal-fired subcategories (except IGCC). The extent of the potential Hg 
removal is dependent on: (1) Efficient distribution of the sorbent 
(e.g., activated carbon) in the flue gas; (2) the amount of sorbent 
needed to achieve a specific level of Hg removal which will vary 
depending on the fuel being burned; (3) the amount of Cl present in the 
fuel; and (4) the type of PM control device (e.g., at a given sorbent 
feed rate, a fabric filter provides more Hg control than an ESP because 
of the additional adsorption that occurs on the bags of the fabric 
filter because of the increased gas contact time).
    Sorbents can be introduced by two basic methods: by channeling flue 
gas through a bed of sorbent or by direct sorbent injection. Sorbent 
bed designs consist of fixed-sorbent filter beds, moving beds, or 
fluidized sorbent filter beds. With direct sorbent injection, after 
sorbent is introduced into the flue gas, it adsorbs Hg and other 
contaminants and is captured downstream in an existing or sorbent-
specific PM control device. At this time, the types of sorbent that may 
be viable for use in sorbent injection include two basic types of 
activated carbon (AC; regular and impregnated), as well as other carbon 
(mixed with other sorbents) and non-carbon sorbents.
    Activated carbon is a specialized form of carbon produced by 
pyrolyzing coal or various hard, vegetative materials (e.g., wood) to 
remove volatile material. The resulting char then undergoes a steam or 
chemical activation process to produce an AC that contains multiple 
internal pores and has a very high specific surface area. With this 
internal pore structure, the AC can adsorb a broad range of 
contaminants. Some studies have shown good to excellent Hg removal with 
the injection of AC (particularly on bituminous-fired units); however, 
other studies have not shown good Hg removal (particularly on 
subbituminous- and lignite-fired units). The Hg removal performance of 
AC injection seems to be highly dependent on coal rank and composition 
(i.e., Hg and Cl content of the coal) and specific utility plant 
configuration (e.g., sequencing of APCD equipment). Further, little 
long-term data is available.
    Chemically-impregnated AC is AC that has been supplemented with 
chemicals to improve its Hg removal. The Hg in the flue gas reacts with 
the chemical that is bound to the AC, and the resulting compound is 
removed by the PM control device. Typical impregnants for AC are Cl, 
sulfur, and iodide. Chemically-impregnated AC have shown enhanced Hg 
removal over regular AC. Chemically-impregnated AC require smaller 
rates of carbon injection than does regular AC for equivalent Hg 
removals. The required carbon-to-mercury mass ratio may be reduced by a 
factor of from 3 to 10 with the chemically-impregnated AC. The cost per 
mass unit of impregnated AC may, however, be significantly greater than 
that of unmodified AC.
    Other commercially available sorbent materials are 
SorbalitTM (a mixture of lime with additives and 3 to 5 
percent AC) and Darco FGD (an AC derived from lignite). Zeolites 
comprise another category of sorbent. There are naturally occurring 
mineral zeolites, in addition to commercially available synthetic 
zeolites. Both types contain large surface areas and have a good 
potential for Hg removal.
    Although AC, chemically-impregnated AC, and other sorbents show 
potential for improving Hg removal by conventional PM and 
SO2 controls, this technology is not currently available on 
a commercial basis and has not been installed, except on a 
demonstration basis, on any electric utility unit in the U.S. to date. 
Further, no long-term (e.g., longer than a few days) data are available 
to indicate the performance of this technology on all representative 
coal ranks or on a significant number of different power plant 
configurations. Therefore, we do not believe these technologies provide 
a viable basis for going beyond-the-floor.
    Selective catalytic reduction. Although designed as a 
NOX control technology, SCR has been shown in recent 
emissions testing to have the ability to transform certain species of 
Hg into other speciated forms that are easier for conventional PM and 
SO2 controls to capture. The effect can be seen most 
prominently when an SCR is installed between the PM control device and 
a wet FGD control device on a unit that is already controlled by such 
technologies. The Hg which would (in the absence of the SCR) tend to 
remain as Hg0 is oxidized, and this highly soluble 
Hg++ is then removed by the wet FGD. This Hg reduction 
effect has been observed in limited stack testing on bituminous coal-
fired units. Results on subbituminous coal-fired units have not been 
uniformly successful. To EPA's knowledge, no commercial-scale, lignite-
fired, SCR-equipped unit has been tested to date, though it is entirely 
possible that greater Hg removal would result when applied to a 
lignite-fired unit. Similarly, SCR has not been tested on all types of 
coal sources.
    The EPA requests comments on whether sorbent injection or SCR 
should be considered as viable beyond-the-floor options for existing 
coal-fired units. Our preliminary determination is that sorbent 
injection has not been sufficiently demonstrated in practice nor have 
long-term economic considerations been evaluated to allow sorbent 
injection to be considered viable as a beyond-the-floor option. With 
regard to the use of SCR, the EPA has inadequate information on which 
to base a beyond-the-floor standard. The EPA is aware that research 
continues on ways to improve Hg capture by PM controls and sorbent 
injection and on the development of novel Hg capture techniques. 
Therefore, EPA also requests comments on whether other control 
techniques have been demonstrated to consistently achieve emission 
levels lower than levels on similar sources achieving the proposed MACT 
floor level of control. Comments should include information on 
emissions, control efficiencies, reliability, current demonstrated 
applications, and costs, including retrofit costs.
    IGCC units. The EPA believes the best potential way of reducing Hg 
emissions from existing IGCC units is to remove Hg from the syngas 
before combustion. An existing industrial IGCC unit has demonstrated a 
process, using sulfur-impregnated AC carbon beds, that has proven to 
yield 90 to 95 percent Hg removal from the coal syngas. (Rutkowski, 
2002) This technology could potentially be adapted to the

[[Page 4677]]

electric utility IGCC units. The EPA believes this to be a potentially 
viable option for IGCC units.
    We considered using sorbent bed technology as beyond-the-floor for 
existing IGCC units but, because of concerns about the costs involved 
and because existing IGCC units utilize older technology, have decided 
not to pursue this option. The EPA is, however, proposing that the use 
of a sorbent bed to remove Hg from coal gas be considered as the 
beyond-the-floor option for new IGCC units. The EPA requests comments 
on whether the use of this or other control techniques have been 
demonstrated to consistently achieve emission levels that are lower 
than levels from similar sources achieving the proposed existing MACT 
floor level of control. Comments should include information on 
emissions, control efficiencies, reliability, current demonstrated 
applications, and costs, including retrofit costs.
    Coal refuse-fired units. All of the 13 coal refuse-fired units 
existing in 1999 use FBC; 10 of these 13 units inject limestone as a 
sorbent for SO2 control, and 4 units are equipped with SCR 
for NOX control. The only two coal refuse-fired units on 
which performance tests were conducted in response to the ICR are the 
MACT floor facilities for the coal refuse-fired subcategory.
    The EPA knows of no technologies that could be used as beyond-the-
floor options for coal refuse units. However, the EPA requests comments 
on whether existing coal refuse-fired units could use any control 
techniques that have been demonstrated to consistently achieve emission 
levels that are lower than levels for similar sources achieving the 
proposed existing MACT floor level of control. Comments should include 
information on emissions, control efficiencies, reliability, current 
demonstrated applications, and costs, including retrofit costs.
    Oil-fired units. The only emission control technology that EPA is 
aware of to consider as a beyond-the-floor option for existing oil-
fired units is fabric filtration. Fabric filters have been shown in 
pilot-scale testing to be more effective at reducing Ni emissions than 
an ESP. However, the use of fabric filters on oil-fired units is also 
known to be problematic due to the prevalence of the ``sticky'' PM 
emitted from such units which sticks to the fabric and creates a fire 
safety hazard. No existing oil-fired units are known to employ fabric 
filters as their PM control. Because of this, EPA does not consider 
fabric filters to be a viable beyond-the-floor option for oil-fired 
units.
    The EPA requests comments on whether fabric filters should be 
considered as a beyond-the-floor option for existing oil-fired units. 
The EPA also requests comments on whether other control techniques have 
been demonstrated to consistently achieve Ni emission levels that are 
lower than levels for similar sources achieving the proposed MACT floor 
level of control. Comments should include information on emissions, 
control efficiencies, reliability, current demonstrated applications, 
and costs, including retrofit costs.
7. Should EPA Consider Different Subcategories for Coal- and Oil-Fired 
Utility Units?
    Although EPA has proposed subcategorizing coal-fired units into 
five subcategories (bituminous coal, subbituminous coal, lignite coal, 
coal refuse, and IGCC), another possible option is to subcategorize 
coal-fired units into four subcategories (bituminous and subbituminous 
coals, lignite coal, coal refuse, and IGCC). This second option is 
claimed by some industry sources to allow greater fuel choice 
flexibility. Approximately 23 percent of the coal-fired units in 1999 
fired a blend of coal ranks or coals and other fuels. The majority of 
blended coal-fired units in the U.S. combust a blended coal composed of 
bituminous and subbituminous coal, either through direct blending or 
through independently combusting each coal at some period during the 
year. A standard that would subcategorize bituminous and subbituminous 
together would allow easier emissions permitting and flexibility 
because most units do not keep the ratio of the coals blended constant.
    Although the above subcategorization scheme is not included in this 
proposal, the EPA specifically requests comments on whether additional 
or different subcategories should be considered. Comments should 
include detailed information regarding why a new or different 
subcategory is appropriate (based on the available data or adequate 
data submitted with the comment), how EPA should define any additional/
different subcategories, how EPA should account for varied or changing 
fuel mixtures, and how EPA should use the available data to determine 
the MACT floor for any new or different categories.
8. How Did EPA Determine the Proposed MACT Floor for New Units?
    For new sources, the CAA requires that the MACT floor be based on 
the emission control achieved in practice by the best-controlled 
similar source, as determined by EPA. The MACT standard is subsequently 
based on any combination of measures or techniques that are ascertained 
to have contributed to that level of control (e.g., pollution 
prevention alternatives, capture and control technologies, operational 
limitations, work practices) unless a more stringent level of control 
is required based on the above-the-floor analysis. Because the MACT 
floor represents the level of reduction in HAP emissions that is 
actually demonstrated by the best-controlled similar source, EPA may 
not consider cost and other impacts in determining the floor.
    In order to develop a MACT floor for new coal- and oil-fired units, 
EPA used the same data described above for existing sources. With 
regard to Hg and Ni emissions from new units, EPA believes that the 
character and levels of Hg and Ni emitted by new coal- and oil-fired 
units will be similar to those emitted by existing coal- and oil-fired 
units because the source of Hg and Ni is primarily related to the fuel. 
The EPA has no data or information that indicate that this situation 
will change in the future, particularly because EPA anticipates the use 
of primarily the same fossil fuel sources for new units as are being 
used for existing units.
    The EPA is aware that the industry has some ability during the 
designing of new units to choose coal or oil that would minimize 
emissions of Hg and Ni and recognizes that the MACT standard for new 
units should, to the extent possible, encourage the industry in that 
direction. The type, grades, and ranks of coal and grades of oil 
available for future use in new units will not likely change, and the 
availability and economics of the fuel choice for these units will 
likely still be a dominating factor in the design of new units. Future 
technology may, however, allow for better efficiencies in the units 
and, potentially, the use of a wider range of fossil fuels for a given 
locale or region.
    The EPA does believe that Hg from coal-fired units and Ni from oil-
fired units will remain a concern and that regulation of emissions of 
Hg and Ni is warranted for new coal- and oil-fired units under the 
proposed rule.
    As was the case for existing units, in developing a MACT strategy 
for new units, EPA considered several prevention measures as an 
alternative to the application of Hg and Ni control technology. These 
measures were the same precombustion techniques evaluated for existing 
units, which included fuel substitution, process changes, and work 
practices.
    The EPA first considered the feasibility of fuel substitution from

[[Page 4678]]

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. The EPA recognizes that an owner/operator, in designing a 
new unit, would be able to choose a perceived better coal rank (between 
subcategories) or a perceived better coal seam within a rank (within 
the subcategory) based on known issues of Hg and other pollutant 
control and would be able design the new unit to that fuel's 
characteristics. However, the economics of fuel availability would 
still be a determining factor as to what fuel was chosen, particularly 
with regard to new units co-located with existing units.
    With regard to a possible EPA requirement for new sources to burn 
natural gas, EPA believes that availability and economics again would 
determine whether a source would chose to burn natural gas and that 
such a requirement would be unduly restrictive given the owner/
operator's inability to control access to, or availability of, natural 
gas. For these reasons, EPA decided that mandated fuel type is not an 
appropriate criterion for identifying the MACT level of control for new 
coal-fired units. In any event, we do not believe that we can or should 
prescribe a given fuel type because of the implications on electricity 
reliability, energy security, etc.
    With regard to process design alternatives and GCP, EPA believes, 
as discussed elsewhere in this preamble for existing sources, industry 
has a strong economic incentive to pursue improvement in combustion and 
plant efficiencies and that the trends in design and technology 
development will continue in the direction of improvement in 
efficiencies such that imposition of regulatory incentives based on the 
existing knowledge base would be not only unnecessary but potentially 
restrictive. In addition. we do not have the data necessary to 
establish such a standard.
    As with existing units, EPA therefore determined that precombustion 
techniques were not viable for application in the MACT standard for new 
coal- or oil-fired units.
    Once EPA had determined that pollution prevention alternatives 
would not be appropriate for the new coal- or oil-fired MACT 
development, EPA then evaluated the control technology used by the top 
performing unit (i.e., equipment based), and the level of emissions 
reductions (i.e., emission limitation based) that the top unit in each 
subcategory demonstrated.
    The EPA used the same data available for existing units which 
provided an evaluation of the Hg control performance of various 
emission control technologies that are either currently in use on coal-
fired units (designed for pollutants other than Hg) or that could be 
applied to such units for Hg control. The EPA decided to address Hg for 
new units using an emission limitation-based approach.
    As was discussed in MACT floor development for existing sources, 
EPA is confident that the data available were obtained from units 
representative of the industry; however, EPA did believe that some 
adjustments to the data were justified in light of the variability in 
test method and in Hg-in-fuel that was discussed previously with regard 
to existing units. Although it was necessary to address the variability 
issues, the use of one data set (i.e., the best unit vs. the top units) 
negated the applicability of the unit-to-unit variability issue. 
Otherwise, the variability issues were addressed in the same manner as 
was discussed above for existing units.
    The MACT floor for new units is based on the emission control 
achieved in practice by the best-performing similar source. As noted 
earlier, EPA believes it reasonable to subcategorize new sources in the 
same manner as has been done for existing sources. In order to develop 
an emission limitation for new coal- and oil-fired units, EPA ranked 
the existing coal- and oil-fired units from lowest emitting to highest 
within each subcategory based on Hg or Ni emission rates from the stack 
test data. The EPA then took the numerical performance value from the 
best-performing unit (or equivalent).
    The EPA then applied the potential uncertainty and variability in 
the emission test reports and worst-case Hg in fuel variability (if 
applicable) to derive the Hg emission limitation values for new units.
    Because test data were provided to EPA based on an input-based 
format (lb/TBtu), EPA conducted the emission limitation calculations 
using the input-based format and then converted the input-based format 
into an output-based format (lb/MWh) according to the approach 
described elsewhere in this preamble for the proposed rule. The 
discussion below describes the development of the emission limitation 
for each subcategory and each regulated pollutant for coal- and oil-
fired units.
    Mercury from new coal-fired units. The emission limit for Hg 
emissions from new coal-fired units was determined by analyzing the 
available Hg emissions data in each subcategory. The data were obtained 
from the ICR and included data for Hg emissions and Hg- and Cl-in-coal 
data from all coal-fired units for 1999. The MACT emission limitation 
calculation was based on the performance of the best similar source in 
the individual subcategories of bituminous coal, subbituminous coal, 
lignite coal, coal refuse, and IGCC (coal gas).
    This performance value was adjusted for variability by using an 
approach consisting of a combination of the statistical analysis of the 
emissions test data and the application of a factor representing the 
ratio of the Hg-in-coal during the stack testing to the highest Hg-in-
coal reported for the unit during 1999 (ICR test). The variability 
approach used for adjusting the new unit's Hg emissions data was 
modified to a simplified version of the existing unit's variability 
factor that reflected the removal of the unit-to-unit variability 
issue. The worst-case Hg-in-coal issue was addressed in the same manner 
as the existing units, based on the Hg- and Cl-in-coal data for the 
individual unit. The EPA chose the same confidence interval (97.5 
percent) as was used for existing units, for the reasons discussed in 
that section.
    For bituminous-fired units, the best-controlled unit was controlled 
with a fabric filter, and the Hg emission factor was 0.132 lb/TBtu. 
This value was adjusted for variability as described above, converted 
to the output-based format using the 35 percent efficiency factor, with 
a resulting output-based Hg emission limitation for new bituminous-
fired units of 6.0 x 10-6 lb/MWh.
    For subbituminous-fired units, the best-controlled unit was also 
controlled with a fabric filter, and the Hg emission factor was 0.663 
lb/TBtu. This value was adjusted for variability as described above, 
converted to the output-based format using the 35 percent efficiency 
factor, with a resulting output-based Hg emission limitation for new 
subbituminous-fired units of 20 x 10-6 lb/MWh.
    For lignite-fired units, the best controlled unit was controlled 
with an ESP, and the Hg emission factor was 6.902 lb/TBtu. This value 
was adjusted for variability as described above and converted to the 
output-based format using the 35 percent efficiency factor, with a 
resulting output-based Hg emission limitation for new lignite-fired 
units of 62 x 10-6 lb/MWh.

[[Page 4679]]

    For IGCC units, the best-controlled unit was uncontrolled, and the 
Hg emission factor was 5.471 lb/TBtu. This value was adjusted for 
variability as described above and converted to the output-based format 
using the 35 percent efficiency factor, with a resulting output-based 
Hg emission limitation for new IGCC units of 200 x 10-6 lb/
MWh. However, EPA believes that a 90 percent reduction in Hg emissions 
is possible from new IGCC units based on the use of carbon bed 
technology. Therefore, EPA is proposing an output-based Hg emission 
limitation for new lignite-fired units of 20 x 10-6 lb/MWh 
as a possible beyond-the-floor level of control for new IGCC units.
    For coal refuse-fired units, the best-controlled unit was 
controlled with a fabric filter, and the Hg emission factor was 0.094 
lb/TBtu. This value was adjusted for variability as described above and 
converted to the output-based format using the 35 percent efficiency 
factor, with a resulting output-based Hg emission limitation for new 
coal refuse-fired units of 1.1 x 10-6 lb/MWh.
    The EPA believes that these Hg emission limitations, based on the 
best-performing unit with associated variability applied, are a 
reasonable estimate of the actual performance of the MACT floor unit on 
an ongoing basis.
    Blended coals. The EPA recognizes that new Utility Units may still 
be designed to burn more than one rank of coal, either at the same time 
(i.e., blending) or at separate times during a period of time (i.e., 
seasonally). The EPA finds no reason to address blended coals 
differently for new units than has been proposed for existing units. 
Therefore, the method of addressing blended coals with regard to the Hg 
emission limit calculation will remain the same for new units as is 
proposed for existing units. Further, EPA believes that consistency in 
the compliance method would be appropriate, because many utility 
owners/operators will at some point be addressing compliance for both 
new and existing units at the same facility.
    Nickel from new oil-fired units. The proposed emission limit for Ni 
from existing oil-fired units was determined by analyzing the emissions 
data available. The data were obtained from the Utility RTC which 
provided information indicating that Ni was the pollutant of concern 
due to its high level of emissions from oil-fired units and the 
potential health effects resulting from exposure to it. The EPA 
examined available test data and found that ESP-equipped units can 
effectively reduce Ni. The Ni average concentration from the emission 
data of the best-controlled oil-fired unit was used to determine the 
emission limitation for new oil-fired units. The best oil-fired unit Ni 
emission value from the stack test data was 0.0046 lb/TBtu. This 
emission factor was then adjusted for uncertainty by applying 
variability factors as described above for existing units, with a 
resulting input-based Ni emission limit of 76 lb/TBtu. The EPA then 
converted the input-based value using the 35 percent net efficiency 
factor to derive the output-based value for the proposed rule. The 
resulting proposed Ni emission limitation for new oil-fired units is 
0.0007 lb/MWh. The EPA believes that this emission limitation is a 
reasonable estimate of the actual performance of the MACT floor unit on 
an ongoing basis.
    The EPA is also considering development of an alternative Ni-in-oil 
limit for new oil-fired units. The EPA solicits comment as to the 
usefulness of such a limit and any available data or methodology to 
determine a Ni constituent level in oil that would be equivalent to the 
proposed Ni emission limitation.
    Dual-fired units. The EPA is aware that new oil-fired units may be 
designed and built to fire a combination of oil grades and/or natural 
gas, as are existing units. The EPA believes that the reasons for 
burning natural gas and/or any grade of oil will continue to be based 
on economics or availability of fuel (i.e., seasonal considerations). 
Therefore, EPA intends to address new oil-fired units that burn a 
combination of oil grades and/or natural gas in the same manner as 
existing units.
    The method and rationale for determining the MACT floor for 
existing and new units is presented in detail in the document titled 
``MACT Floor Analysis for Coal- and Oil-Fired Electric Utility Steam 
Generating Units NESHAP'' which can be found in the docket.
9. How Did EPA Consider Beyond-the-Floor for New Units?
    Once the MACT floor determinations were done for new units in each 
subcategory (by fuel type), EPA considered various regulatory options 
more stringent than the MACT floor level of control (i.e., additional 
technologies or work practices that could result in lower emissions) 
for the different subcategories.
    Due to the technical complexities of controlling metal HAP 
emissions from the sources affected by this rule, however, EPA has not 
been able to determine whether identified potential beyond-the-floor 
options are available and demonstrated. Consequently, EPA is describing 
the possible beyond-the-floor options of which the Agency is aware for 
new units and requests comment on these technologies and other control 
techniques that have been demonstrated to provide consistently lower 
levels of emissions than those achieved by the proposed new unit MACT 
floor level of control.
    The following are possible beyond-the-floor control options for new 
units that EPA is considering for the proposed rule.
    Coal-fired units. As is explained for existing coal-fired units 
elsewhere in this preamble, two technologies that possibly could be 
used to further reduce the amount of vapor-phase Hg emitted from 
utilities are sorbent injection and SCR. As explained elsewhere in this 
preamble, however, sorbent injection is not currently available on a 
commercial basis and has not been demonstrated on a utility unit 
operating at full capacity over an extended period of time. As also 
discussed previously, SCR has not shown the same change-in-speciation 
effect on Hg emissions on all types of coal sources.
    The EPA requests comments on whether sorbent injection or SCR 
should be considered as a beyond-the-floor option for new coal-fired 
units and whether these units could use any other control techniques 
that have been demonstrated to consistently achieve emission levels 
that are lower than those from similar sources achieving the proposed 
MACT floor level of control. Comments should include information on 
emissions, control efficiencies, reliability, current demonstrated 
applications, and costs.
    IGCC units. Because of their design, IGCC units have no external 
APCD controls. Therefore, as is explained for existing IGCC units 
elsewhere in this preamble, the best potential way of improving Hg 
removal from IGCC units is to remove the Hg from the syngas before 
combustion. Based on published information regarding the industrial 
IGCC unit noted earlier, EPA believes that a 90 percent reduction in Hg 
emissions is possible from new IGCC units based on the use of carbon 
bed technology. Therefore, EPA is proposing this 90 percent Hg 
reduction as a beyond-the-floor level for new IGCC units.
    The EPA requests comment on whether such use of a sorbent bed to 
remove Hg from coal syngas is an appropriate beyond-the-floor option. 
Comments should include information on emissions, control efficiencies, 
reliability, current demonstrated applications, and costs.

[[Page 4680]]

    Coal refuse-fired units. Because existing units utilizing 100 
percent coal refuse, all of which utilize FBC technology, have 
demonstrated the best Hg control of any emission-tested electric 
utility unit in the industry, EPA requests comments on whether there 
are any additional control techniques that have been demonstrated and 
can be applied to refuse coal-fired units to consistently achieve 
emission levels that are lower than those of similar sources achieving 
the proposed new MACT floor level of control. Comments should include 
information on emissions, control efficiencies, reliability, current 
demonstrated applications, and costs.
    Oil-fired units. There has not been a new oil-fired unit 
constructed in the U.S. since 1981. If a new oil-fired unit is 
constructed, the only technology that might offer emissions control 
better than the proposed new unit MACT limits is the use of fabric 
filtration, which, as is discussed for existing sources elsewhere in 
this preamble, EPA does not consider to be a viable control option for 
oil-fired units.
    The EPA requests comments on whether the use of fabric filters 
should be considered as a beyond-the-floor option for new oil-fired 
units and whether these or other control techniques could be used to 
consistently achieve emission levels that are lower than those from 
similar sources achieving the proposed new MACT floor level of control. 
Comments should include information on emissions, emissions reductions, 
reliability, current demonstrated applications, and costs.
    Additional information on the beyond-the-floor analyses for new 
units is available in the document titled, ``Beyond the Floor Analysis 
for Existing and New Coal- and Oil-Fired Electric Utility Steam 
Generating Units NESHAP'' which can be found in the docket.
10. How Did EPA Select the Proposed Testing and Monitoring 
Requirements?
    The CAA requires EPA to develop regulations that ensure initial and 
continuous compliance. Testing and monitoring requirements allow EPA to 
determine whether an affected source is operating in compliance with an 
applicable emission limitation/standard. This section discusses how EPA 
selected the proposed testing and monitoring requirements used to 
determine compliance with the Hg emission limits for coal-fired units 
and the Ni emission limits for oil-fired units that are specified in 
the proposed rule.
    Mercury testing and monitoring requirements. The proposed rule 
would establish Hg emission limits for coal-fired units. The format 
selected for these Hg emission limits is a 12-month rolling average Hg 
emission level expressed in units of lb/TBtu or lb/MWh. Therefore, 
appropriate testing or monitoring requirements for determining the 
amount of Hg emitted from an affected unit throughout the compliance 
averaging period must be included in the rule.
    The most direct means of demonstrating compliance with an emission 
limit is by the use of a CEMS that measures the pollutant of concern. 
The EPA considers other testing or monitoring options when acceptable 
CEMS are not available for the intended application or when the impacts 
of including such CEMS requirements in the proposed rule are considered 
by EPA to be unreasonable. In determining whether to require the use of 
other testing or monitoring options in lieu of CEMS, it is often 
necessary for EPA to balance more reasonable costs against the quality 
or accuracy of the actual emissions data collected.
    There are several approaches to Hg monitoring that EPA has 
identified for possible use in this rule to determine compliance with 
the proposed Hg emission limits. One option is to use a CEMS that 
combines both automated sampling and analytical functions in a single 
system to provide continuous, real-time Hg emission data. Mercury CEMS 
are currently available from several manufacturers. These Hg CEMS are 
similar to most other types of instruments used for continuous 
monitoring of pollutants from combustion processes, in that the 
combustion gas sample is first extracted from the stack and then 
transferred to an analyzer for analysis. In general, the Hg CEMS now 
available can be distinguished by the Hg measurement detection 
principle used (e.g., atomic adsorption, atomic fluorescence, x-ray 
fluorescence). Capital costs for a Hg CEMS are currently estimated to 
range from approximately $95,000 to $135,000, depending on the 
manufacturer and model selected. The annual costs to operate and 
maintain a Hg CEMS are estimated to range from $45,000 to $65,000, 
again depending on the manufacturer and model selected.
    A second option is to use a long-term sampling method that collects 
a cumulative Hg sample by continuously passing a low-flow sample stream 
of the combustion process flue gas through a Hg trapping medium (e.g., 
an activated carbon tube). This sampling tube is then periodically 
removed (e.g., after a day or up to 1 month) and replaced with a tube 
filled with fresh trapping medium. The removed sampling tube is then 
sent to a laboratory where the trapping medium is analyzed for its Hg 
content. This method, like using a Hg CEMS, is capable of providing 
data on the Hg emissions from a combustion process on a continuous 
basis, but unlike a Hg CEMS, the data are not reported on a real-time 
basis. Using the long-term sampling method, the Hg collected in the 
sampling tube is integrated over a much longer sampling period (i.e., 1 
to 7 days for the AC tube versus less than 15 minutes for the CEMS). 
The capital cost for a gas metering system and Hg trapping medium is 
estimated to be approximately $18,000. The annual costs for periodic 
sampling tube replacement and for the laboratory Hg analysis range from 
approximately $65,000 to $125,000 depending upon quality assurance and 
quality control (QA/QC) requirements and frequency of sample tube 
replacement.
    Finally, a third monitoring option is to use one of the manual 
stack test methods available for measuring Hg emissions from combustion 
processes on an intermittent basis. The existing voluntary consensus 
stack test method ASTM Method D6784-02 (commonly known as the Ontario-
Hydro method) is currently the method of choice for measuring Hg 
species in the flue gas from Utility Units. Another method for 
measuring total (i.e., not speciated) Hg is EPA Reference Method 29. 
This method involves a technician extracting a representative flue gas 
sample over a relatively short period of time (e.g., a few hours) using 
a sampling train consisting of a nozzle and probe, a filter to collect 
particulate matter, and a liquid solution and/or reagent to capture 
gas-phase Hg. After sampling, the filter and sorption media are 
prepared and analyzed for Hg in a laboratory. These test methods could 
be applied to a Hg monitoring program at electric utility plants by 
performing a manual stack test using ASTM Method D6784-02 or EPA 
Reference Method 29 at some specified periodic interval throughout the 
compliance averaging period (e.g., perform a stack test daily, weekly, 
biweekly, monthly). The cost to conduct a single ASTM Method D6784-02 
typically ranges from $15,000 to $17,000 depending on site conditions. 
Annual costs will depend on the frequency with which the stack test is 
required to be performed during the compliance averaging period. For 
example, if the test is required once per week, the total annual cost 
would be as much as $780,000 (52 tests in a 12-month period at $15,000 
per test).
    The EPA evaluated each of the above Hg monitoring options with 
respect to

[[Page 4681]]

its suitability for the measurement of the Hg emission data needed for 
determining compliance with the 12-month rolling average Hg emission 
limit. The EPA rejected from further consideration the third option, 
intermittent monitoring using manual stack test methods. Use of this 
monitoring approach would place significantly higher labor requirements 
and monitoring costs on facility owners/operators than the other two 
options in order to perform an adequate number of source tests 
throughout the compliance averaging period to demonstrate with 
reasonable confidence that the applicable Hg emission limit value was 
being achieved.
    Both of the remaining two options would provide the necessary data 
to calculate the total Hg emissions from an affected source for each 
12-month compliance averaging period. While the CEMS would provide 
these data on a real-time basis, EPA concluded that having real-time 
data is not mandatory for determining compliance with an emission limit 
based on a 12-month rolling average. Total Hg emissions from an 
affected source by month are needed to compute the rolling 12-month 
average Hg emission value. With regular scheduled replacement and 
timely analysis of sampling tubes, total monthly Hg emissions can 
readily be obtained using the long-term sampling method.
    The EPA then compared the costs of applying the Hg CEMS and long-
term monitoring options to Utility Units. While the CEMS have 
significantly higher capital costs, the automated analyses directly by 
the instrument eliminates the need and cost for separate analyses of 
the collected sampling tubes in a laboratory required by the long-term 
sampling method. Overall, EPA determined that the total costs of using 
either monitoring method to determine compliance would be similar for a 
given site. Selection of which monitoring method should be used at the 
site will depend on site-specific conditions and owner/operator 
preferences. Because both monitoring methods will collect the Hg 
emission data necessary to determine compliance with the proposed Hg 
emission limit and the costs of either option are reasonable, EPA 
decided to allow the owner/operator flexibility under the proposed rule 
to choose to use either Hg CEMS or long-term sampling monitoring as 
best suits their site conditions and preferences.
    An owner/operator electing to use a CEMS to comply with the rule 
would be allowed to use any CEMS that meets the requirements in 
``Performance Specification 12A, Specifications and Test Procedures for 
Total Vapor-phase Mercury Continuous Monitoring Systems in Stationary 
Sources'' (PS-12A). This performance specification is proposed as part 
of this rulemaking and we request comment on continuous monitoring of 
Hg emissions according to the requirements in the proposed performance 
specification.
    Those owners/operators electing to use long-term Hg monitoring 
would be required to follow the requirements in Method 324, 
``Determination of Vapor Phase Flue Gas Mercury Emissions from 
Stationary Sources Using Dry Sorbent Trap Sampling'' when it is 
promulgated. Method 324 is proposed as part of this rulemaking to be 
added to 40 CFR part 63, appendix A. We request comments on the 
requirements in proposed Method 324 for Hg measurement using long-term 
sampling. The owner/operator would use the procedures outlined in Sec. 
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.
    Continuous compliance requirements are required under every NESHAP 
so that EPA can determine whether an affected source remains in 
compliance with the applicable emission limitation/standard following 
the initial compliance determination. In the case of the proposed 
Utility NESHAP, the format for the Hg emission limit is a 12-month 
rolling average limit. The same monitoring requirements used to 
establish initial compliance of an affected electric utility unit with 
the applicable Hg emission limit at the end of the first 12-month 
period following the facility's compliance date serve to demonstrate 
continuous compliance with the Hg emission limit with the computation 
of each new 12-month rolling average value each month thereafter. Thus, 
no additional continuous compliance Hg monitoring requirements beyond 
those previously discussed are required for the proposed rule.
    The EPA is concerned about monitoring costs for Utility Units with 
low Hg emissions rates, and does not desire to adopt a monitoring 
scheme where the costs are disproportionate to the costs of compliance 
with the MACT emissions limitations. For these units (e.g., those 
emitting under 25 pounds per year) the EPA may consider reduced 
monitoring frequencies and lower cost monitoring requirements, since 
the need for accuracy is reduced for such units. For example, the EPA 
is concerned about the merits of requiring an expenditure of $100,000 
per year to monitor releases when the costs of substantive compliance 
is far less. The Agency requests comments and related data upon which 
to establish an alternate reporting scheme.
    Nickel testing and monitoring requirements. The proposed rule would 
establish Ni emission limits for oil-fired units. The EPA selected a 
different format for the Ni emission limits than is proposed for the Hg 
emission limits. The Ni emission limits are maximum allowable emission 
limits not to be exceeded, expressed in lb/TBtu or lb/MWh.
    The EPA selected the proposed testing requirements to determine 
compliance with the Ni emission limits under the NESHAP to be 
consistent with existing procedures used for the electric utility 
industry. Method 29 in appendix A to 40 CFR part 60 is an EPA reference 
test method that has been developed and validated for the measurement 
of Ni emissions from stationary sources. For sampling and analysis of 
the gas stream, the following EPA reference methods would be used with 
Method 29: Method 1 to select the sampling port location and the number 
of traverse points; Method 2 to measure the volumetric flow rate; 
Method 3 for gas analysis; and Method 4 to determine stack gas 
moisture. Method 19 specifies the procedure for collecting the 
necessary fuel data to be used with the Method 29 Ni measurements from 
the source test to compute the Ni emission rate expressed in units of 
lb/TBtu.
    As an alternative under the proposed rule, an owner/operator of an 
existing source could choose to comply with the applicable Ni emission 
limit expressed in lb/MWh. The owner/operator would use the procedures 
outlined in Sec. 63.10009 of the proposed rule to convert the 
concentration output of Method 29 to the output-based emission rate 
format.
    To address the need for continuous compliance requirements for the 
proposed Ni emission limits, EPA considered the availability and 
feasibility of a number of Ni monitoring options ranging from direct 
monitoring of Ni emissions, to process parameter monitoring, to control 
device parameter monitoring. Monitors for continuously measuring Ni 
emissions have not been demonstrated in the U.S. for the purpose of 
determining compliance. Therefore, EPA did not consider further the use 
of continuous monitors for Ni for the proposed rule.
    Another option used in other NESHAP for demonstrating continuous 
compliance is to monitor appropriate process and/or control equipment 
operating parameters. These parameters are established during the 
initial, and

[[Page 4682]]

any subsequent, stack test. Process parameters were not selected as 
indicators for Ni emissions from Utility Units because a direct 
correlation does not exist between combustion or electricity production 
parameters and Ni emission rates from a given unit.
    Monitoring of PM control device operating parameters is used in 
other NESHAP established for combustion processes and other source 
categories that include PM emission limits. The EPA decided to also use 
this continuous monitoring approach to demonstrate continuous 
compliance with the applicable Ni emission limits set forth in the 
proposed rule. The selected operating parameters for the PM control 
device used by oil-fired Utility Units (e.g., ESP) are reliable 
indicators of control device performance. The EPA believes that 
reasonable assurance of compliance with the emission limits proposed 
for this NESHAP can be achieved through appropriate monitoring and 
inspection of the operation of the APCD that have been demonstrated by 
an initial performance test to achieve the applicable Ni emission 
limits under the rule.
    Compliance calculations. For 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. This consideration is accomplished by taking the net 
efficiency of a cogeneration unit into account. Under a Federal Energy 
Regulatory Commission regulation, the efficiency of cogeneration units 
is determined from the useful power output plus one-half the useful 
thermal output (18 CFR 292.205). To account for the process steam 
energy contribution to net plant output, a 50-percent credit of the 
process steam heat is necessary. Such a credit would, EPA believes, 
provide an incentive for cogeneration.
    Therefore, owners/operators of cogeneration units subject to the 
proposed rule would need to monitor the portion of their net plant 
output that is process steam so that they can take the 50-percent 
credit of the energy portion of their process steam net output. For 
example, a cogeneration unit subject to the rule measures its net 
electrical output over a compliance period, as 30,000 MWh. During the 
same period the unit burns coal that provides 750 billion Btu input to 
its furnace/boiler, and emits 0.2 lb Hg. Using equivalents found in 40 
CFR 60 for electric utilities (i.e., 250 million Btu/hr input to a 
boiler is equivalent to 73 MWe input to the boiler; 73 MWe input to the 
boiler is equivalent to 25 MWe output from the boiler; therefore, 250 
million Btu input to the boiler is equivalent to 25 MWe output from the 
boiler) the 50-percent credit could be found as follows. The net output 
calculation would be 750 billion Btu x (25 MWe output/250 million Btu/
hr input) = 75,000 MWh equivalent electrical output from the boiler 
over the compliance period. Of this amount, 30,000 MWh was produced as 
electricity sent to the grid, leaving 45,000 MWh as the energy 
converted to steam for process use. Half of this amount is 22,500 MWh. 
The unit's Hg CEM records a total of 0.2 lb Hg over the same compliance 
period. The adjusted Hg emission rate is then: 0.2 lb Hg/(30,000 MWh + 
22,500 MWh) = 3.8 x 10-\6\ lb Hg/MWh.
11. How Did EPA Determine Compliance Dates for the Proposed Rule?
    Section 112(i) of the CAA specifies the dates by which affected 
sources must comply with the emission standards. New or reconstructed 
units must be in compliance with the proposed rule immediately upon 
startup or [DATE THE FINAL RULE IS PUBLISHED IN THE Federal Register], 
whichever is later, except that if the final rule is more stringent 
than the proposal, a new source that commences construction before the 
final rule is promulgated may comply with the proposed rule for 3 years 
before complying with the final rule. Existing sources must be in 
compliance with the final rule 3 years after the effective date of the 
final rule. Existing sources may seek a permit granting an additional 
one year to comply if such time is necessary for the installation of 
controls.
    We anticipate that a substantial number of sources would have to 
install control technologies to meet the limits of the proposed 
standard, if the CAA section 112 MACT rule is finalized. We also 
believe that such construction could be constrained by the potential 
impacts on electricity reliability, delays in obtaining permits, and 
other factors (including potential labor and equipment shortages). 
Thus, we anticipate that a substantial number of units will seek the 1-
year extension which could unduly burden State and local permitting 
authorities. Therefore, EPA is soliciting comment on whether a 1-year 
extension should be granted for facilities required to install controls 
in order to comply with the proposed CAA section 112 MACT rule, should 
it be finalized.
12. How Did EPA Select the Proposed Recordkeeping and Reporting 
Requirements?
    Under section 114(a) of the CAA, EPA may require owners/operators 
of affected sources subject to a NESHAP to maintain records as well as 
prepare and submit notifications and reports to the EPA. In addition, 
section 504(a) of the CAA mandates that sources required to obtain a 
title V permit submit a report setting forth the results of any 
required monitoring no less often than every 6 months. The general 
recordkeeping, notification, and reporting requirements for all NESHAP 
are specified in 40 CFR 63.9 and 40 CFR 63.10 of the General 
Provisions, if incorporated into the proposed rule. The recordkeeping, 
notification, and reporting requirements for the proposed rule were 
selected to include all of the applicable records, notifications, and 
reports specified by the General Provisions requirements. Additional 
requirements were included in the proposed rule that are necessary to 
ensure that a given affected source is complying with the emission 
limits from the correct subcategory.
    The proposed rule would also require that the owner/operator keep 
monthly records for each affected source listing the type of fuel 
burned, the total fuel usage, and the fuel heating value. Additional 
recordkeeping would be required for those owners/operators electing to 
comply with a fuel blending emission limit. The owner/operator would be 
required to maintain records of all compliance calculations and 
supporting information.
13. Will EPA Allow for Facility-Wide Averaging?
    The proposed rule contains provisions allowing the owner/operator 
of a coal-fired affected unit to demonstrate compliance through the 
averaging of Hg emissions from multiple affected units located at a 
common, contiguous facility site. Consistent with EPA policy on 
regulatory flexibility, this provision is intended to provide a 
facility with the benefit of operational flexibility while still 
meeting the proposed emission limitations and achieving the required 
emissions reductions. This averaging provision effectively allows the 
owner/operator to average the emissions from multiple (two or more) 
coal-fired affected units and comply with one applicable facility-wide 
emission limitation.
    The proposed rule would require that any coal-fired affected unit 
included in the facility's averaging regime be a regulated unit under 
the proposed rule (i.e., coal-fired Utility Units only, and

[[Page 4683]]

not combined with sources regulated by other rules, such as IB units).
    The averaging provision may be applied to meet the proposed 
emission limitations for Hg from coal-fired units. An important aspect 
of this provision is that the emissions measurements for the averaging 
calculations are taken after the last control device. Affected units 
that share a common control device are inherently averaged by the 
standard compliance calculations provided in Sec. 63.10009 of the 
proposed rule. It is the intention of EPA to provide additional 
flexibility to average all coal-fired units at one facility into one 
averaged emission limit. In accordance with that intent, the initial 
and continuous compliance demonstration under this averaging provision 
would be to determine the emission rate applicable to all affected 
units (which may be individual or blended) according to requirements 
under Sec. 63.10009 and then use those limits to calculate a limit for 
the emissions averaging group according to Sec. 63.99991 of the 
proposed rule.
    The owner/operator would be required to limit Hg emissions from the 
group of all affected units being averaged to an overall Hg emission 
limit (emissions-averaged emission limit, AvEL) during each 12-month 
compliance period. The owner/operator would be required to use the AvEL 
determined in accordance with Sec. 63.99991 of the proposed rule 
throughout the 12-month compliance period and may not switch between 
compliance with individual subcategory emission limits and an AvEL. The 
format of the AvEL (lb/MWh or lb/TBtu) would also be required to remain 
constant throughout the 12-month compliance period. The owner/operator 
would keep all records as required by sections 63.10031 and 63.10032 of 
the proposed rule. The owner/operator would be required to submit 
information on the affected units which comprise each AvEL group for 
which the owner/operator used a calculated AvEL; the emission limits 
(including format) that would be averaged (i.e., Hg); the units that 
will be averaged together; and the calculation of the AvEL with which 
the averaged units will comply. The owner/operator may implement 
emissions averaging at any time after the effective date with 
submission of the averaging plan. The owner/operator must revise the 
plan to change an emissions averaging group. The owner/operator must 
certify in each semiannual compliance report that the AvEL group of 
affected units was in compliance with the emission limitation.
    The EPA solicits comment on the emissions averaging provision, 
particularly on the usefulness of the provision and its specific 
applicability requirements.

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?

    Today, EPA proposes revising the regulatory finding that it 
published on December 20, 2000 (65 FR 79825) pursuant to section 
112(n)(1)(A) of the CAA. The EPA is proposing such a revision based on 
its review of the December 2000 finding, the Utility RTC underlying 
that finding, and the provisions of the CAA. For the reasons discussed 
below, EPA proposes to find that regulation of coal- and oil-fired 
Utility Units under section 112 is not ``appropriate and necessary'' 
within the meaning of section 112(n)(1)(A). As a consequence, EPA also 
proposes to delete such units from the CAA section 112(c) list. The EPA 
does not propose revising its December 2000 conclusion with regard to 
HAP emissions from natural-gas fired electric utility steam, however, 
as it continues to believe that regulation of such units is not 
appropriate and necessary.
    What was EPA's December 2000 ``necessary'' finding? Was EPA's 
December 2000 ``necessary'' finding overbroad? As noted above, in 
December 2000, EPA concluded that it was

``necessary to regulate HAP emissions from coal- and oil-fired 
electric utility steam generating units under section 112 of the CAA 
because the implementation of other requirements under the CAA will 
not adequately address the serious public health and environmental 
hazards arising from such emissions.'' (65 FR 79830)

    Upon further review of the record and the December 2000 notice, EPA 
believes that this finding is over-broad in two respects.
    First, the ``necessary'' finding might be interpreted to suggest 
that all HAP emissions from coal- and oil-fired Utility Units pose 
``serious public health * * * hazards.'' (65 FR 79830) Upon further 
review of the record, EPA recognizes that it could not reasonably have 
reached such a conclusion based on the record before it in December 
2000. That record supports only a finding that emissions of Hg and Ni 
warrant regulation. Nothing in the Study or the information EPA 
obtained following that study even arguably supports the proposition 
that EPA should address HAP emissions from Utility Units other than 
emissions of Hg and Ni.
    Second, the ``necessary'' finding states that emissions of HAP from 
Utility Units result in ``serious * * * environmental hazards.'' (See 
65 FR 79830.) (emphasis added.) After re-examining the record, EPA 
recognizes that this conclusion also cannot be supported by the record. 
As an initial matter, the Utility RTC, consistent with CAA section 
112(n)(1)(A), focused solely on hazards to public health, not the 
environment. In fact, the Study expressly states that the ecological 
impacts associated with HAP from Utility Units were not examined 
because such impacts were beyond the scope of the Study mandated by CAA 
section 112(n)(1)(A)) (ES at 27). The only information in the record 
concerning the effects of HAP on the environment was for Hg, and that 
information was obtained after completion of the Utility RTC. Thus, 
given the record before the Agency in December 2000, the most EPA could 
have intended to state in the December 2000 ``necessary'' finding is it 
is necessary to regulate Hg from coal-fired Utility Units and Ni from 
oil-fired Utility Units because the implementation of other 
requirements under the CAA will not adequately address the serious 
public health hazards arising from such emissions or the environmental 
hazards associated with Hg. Moreover, as explained below, EPA has 
recently re-analyzed this ``necessary'' determination and the premise 
underlying that determination.
    Does other CAA authority exist to address emissions of Hg and Ni 
from coal- and oil-fired Utility Units? The EPA continues to believe 
that emissions of Hg from coal-fired Utility Units and emissions of Ni 
from oil-fired units pose hazards to public health, that coal-fired 
Utility Units are the largest domestic source of Hg emissions, and that 
oil-fired units are the primary source of Ni emissions. These findings 
support a determination that it is appropriate to regulate emissions of 
Hg and Ni from Utility Units.
    We have had an opportunity to re-assess the ``necessary'' finding 
made in December 2000. Today, we propose to revise that finding 
because, after examining the scope of available authorities under the 
CAA, we have determined that there is, in fact, another viable 
statutory mechanism that would adequately address Hg and Ni emissions 
from coal- and oil-fired Utility Units. That authority is CAA section 
111.
    The scope of existing authorities under the CAA. The EPA interprets 
the language of CAA section 112(n)(1)(A)

[[Page 4684]]

and the limited legislative history relating to that provision as 
indicating Congress' intent that Utility Units be regulated under 
section 112 only if the other authorities of the CAA, once implemented, 
would not adequately address those HAP emissions from Utility Units 
that warrant regulation. This interpretation is supported by the first 
sentence of section 112(n)(1)(A), which requires EPA to conduct a study 
that focuses on the hazards to public health that would exist following 
implementation of the other authorities of the CAA. It is further 
evidenced by the final sentence of section 112(n)(1)(A), which calls 
for regulation of Utility Units under section 112 only if, based on the 
results of the Study, EPA determines that it is both appropriate and 
necessary to regulate such units. Finally, the remarks made by 
Congressman Oxley, a member of the conference committee, concerning the 
Conference Report on the CAA Amendments of 1990, confirm that Congress 
sought to regulate under section 112 ``only those units [Utility Units] 
that * * * (the Administrator) determines--after taking into account 
compliance with all other provisions of the act * * *--have been 
demonstrated to cause a significant threat of serious adverse effects 
on public health.'' \7\ (136 Cong. Rec. E3670, 3671 & H12911, 12934 
(daily ed. Nov. 2, 1990) (Statement of Congressman Oxley)
---------------------------------------------------------------------------

    \7\ Congressman Oxley further noted that regulation under CAA 
section 112 should be imposed ``only if warranted by the scientific 
evidence.'' 136 Cong. Rec. E3670, 3671 & H12911, 12934 (daily ed. 
No. 2, 1990) (Statement of Congressman Oxley).
---------------------------------------------------------------------------

    Based on the foregoing, EPA believes if we make a determination 
under section 112(n)(1)(A) that it is appropriate to regulate Utility 
Units, we are not compelled to regulate Utility Units under section 112 
if other authorities in the CAA exist to adequately address health 
hazards that occur as a result of HAP emissions. The EPA believes that 
this is a reasonable interpretation of the term ``necessary'' in CAA 
section 112(n)(1)(A), and that it is wholly consistent with its 
interpretation of the term in December 2000. (See 65 FR 79830. ``It is 
necessary to regulate * * * under section 112 of the CAA because the 
implementation of other requirements under the CAA will not adequately 
address the serious public health and environmental hazards arising 
from such emissions * * *'')
    Since December 2000, EPA has had the opportunity to conduct a more 
thorough review of the available authorities under the CAA. Based on 
that review, EPA has identified a provision of the CAA that it believes 
can be employed to adequately address the hazards to public health 
resulting from Hg and Ni emissions from Utility Units. That provision 
is CAA section 111, which authorizes EPA to develop standards of 
performance for new and existing sources of air pollutants that cause, 
or contribute significantly to, air pollution which may reasonably be 
anticipated to endanger public health or welfare.
    The EPA based its ``necessary'' finding in December 2000 solely on 
its belief, at the time, that there were no other authorities under the 
CAA that would adequately address Hg and Ni emissions from coal- and 
oil-fired Utility Units. Now that we have re-examined the scope of 
existing authorities under the CAA and identified a viable statutory 
mechanism other than section 112, we propose to revise the December 
2000 ``necessary'' finding accordingly. We specifically propose to find 
that regulation of coal- and oil-fired Utility Units under section 112 
is not necessary because CAA section 111, once implemented, would 
adequately address the public health hazards posed by Utility Unit 
emissions of Hg and Ni.\8\
---------------------------------------------------------------------------

    \8\ The EPA examined various provisions of the CAA, including 
section 111, prior to issuing its December 2000 regulatory finding. 
(Utility RTC.) At that time, we did not believe that any other 
provisions of the CAA would adequately address the health hazards of 
concern associated with Hg and Ni emissions. Now, after re-analyzing 
the provisions of the CAA, we recognize that CAA section 111 is a 
viable statutory mechanism that would adequately address Hg and Ni 
emissions from coal- and oil-fired units. The premise underlying our 
December 2000 ``necessary'' finding, therefore, lacks foundation. 
Nothing precludes EPA from revisiting its December 2000 
``necessary'' determination, particularly, where, as here, the basis 
for that determination involved the scope of existing statutory 
provisions and those provisions have not changed substantively since 
1990.
---------------------------------------------------------------------------

    We further believe that CAA section 111, once implemented, would 
adequately address any environmental effects associated with Hg 
emissions from Utility Units, as documented in the record. We recognize 
that the plain language of CAA section 112(n)(1)(A) requires an 
examination solely of hazards to public health associated with HAP 
emissions, not of hazards to the environment. Nevertheless, in this 
case, and given that the December 2000 finding addresses both the 
health and environmental effects of Hg, we believe that our section 111 
proposal would adequately address both of those effects.
    Regulation under CAA section 111. Overview. The two relevant 
provisions of section 111 are section 111(b), which applies to new 
sources, and section 111(d), which applies to existing sources. As 
explained below, EPA believes that these provisions authorize the 
establishment of standards of performance both for Hg emissions from 
new and existing coal-fired Utility Units and for Ni emissions from new 
and existing oil-fired units, and that such standards, once finalized, 
would adequately address the health hazards resulting from Hg and Ni 
emissions. Indeed, through this notice, EPA proposes such standards of 
performance. We explain below why the proposed standards adequately 
address any public health hazards resulting from Hg and Ni emissions 
from Utility Units and the environmental effects associated with Hg 
emissions.
    Regulation under section 111(b). Pursuant to CAA section 
111(b)(1)(A), EPA has established a list of stationary source 
categories. The EPA is to include a source category on the section 
111(b) list if it determines that such category causes, or contributes 
significantly to, air pollution which may reasonably be anticipated to 
endanger public health or welfare. Section 111(b) further requires EPA 
to establish federal standards of performance for new sources within 
each listed source category.
    The EPA included Utility Units on the section 111(b) list of 
stationary sources in 1979. (44 FR 33580; June 11, 1979.) The EPA has 
also previously promulgated federal standards of performance for such 
units for pollutants like NOX, PM, and SO2. (See 
subpart Da of 40 CFR part 60.)
    Nothing in section 111(b) precludes EPA from promulgating 
additional standards of performance for other pollutants emitted from 
new Utility Units. Indeed, where, as here, EPA has determined that 
emissions of Hg and Ni from coal- and oil-fired Utility Units warrant 
regulation, the establishment of Federal standards of performance under 
section 111(b) is appropriate.
    Moreover, nothing in CAA section 111 or section 112 indicates that 
Congress sought to regulate HAP exclusively under section 112. Rather, 
the language of sections 112(c)(6), 112(d)(7) and 112(n)(1)(A) supports 
the conclusion that HAP emissions could be regulated under other 
provisions of the CAA. There is nothing in the legislative history to 
suggest that Congress sought to preclude EPA from regulating HAP under 
other sections of the Act. We, therefore, believe that CAA section 
111(b), as amended in 1990, constitutes a viable and appropriate 
statutory authority by which to regulate Hg emissions from new coal-
fired Utility Units and Ni emissions from new oil-fired units.

[[Page 4685]]

    Regulation under section 111(d). CAA section 111(d), unlike section 
111(b), specifically references CAA section 112. The import of that 
reference is not clear, however, because Public Law 101-549, which is 
the 1990 amendments to the CAA, contains two different and conflicting 
amendments to section 111(d). To understand this conflict, it is useful 
to start with the language of section 111(d) as contained in the 1977 
Amendments to the CAA.
    In 1977, section 111(d)(1) read as follows:

    The Administrator shall prescribe regulations which shall 
establish a procedure similar to that provided by section 7410 of 
this title under which each State shall submit to the Administrator 
a plan which (A) establishes standards of performance for any 
existing source for any air pollutant (i) for which air quality 
criteria have not been issued or which is not included on a list 
published under section 7408(a) or 7412(b)(1)(A) of this title, but 
(ii) to which a standard of performance under this section would 
apply if such existing source were a new source. * * *

This language provides that standards of performance should not be 
established under section 111(d) with respect to any pollutants that 
are listed as hazardous air pollutants under section 112(b)(1)(A) of 
the 1977 CAA.
    In the 1990 Amendments to the CAA, two different and conflicting 
amendments to section 111(d) were enacted. Presumably, Congress did not 
realize that it had passed two different amendments to the same 
statutory provision. The first amendment, which is the House amendment, 
is contained in section 108(g) of Public Law 101-549. That section 
amends section 111(d)(1)(A)(i) of the 1977 CAA by striking the words 
``or 112(b)(1)(A)'' from the 1977 CAA and inserting in its place the 
following phrase: ``or emitted from a source category which is 
regulated under section 112.'' The second amendment to section 111(d), 
which is the Senate amendment, is labeled a ``conforming amendment'' 
and is set forth in section 302 of Public Law 101-549. That section 
amends CAA section 111(d)(1) of the 1977 CAA by striking the reference 
to ``112(b)(1)(A)'' and inserting in its place ``112(b).''
    These two amendments are reflected in parentheses in the Statutes 
at Large as follows:

    The Administrator shall prescribe regulations which shall 
establish a procedure similar to that provided by section 7410 of 
this title under which each State shall submit to the Administrator 
a plan which (A) establishes standards of performance for any 
existing source for any air pollutant (i) for which air quality 
criteria have not been issued or which is not included on a list 
published under section 7408(a) (or emitted from a source category 
which is regulated under section 112) (or 112(b)), but (ii) to which 
a standard of performance under this section would apply if such 
existing source were a new source. * * *

EPA recognizes that the United States Code does not contain the 
parenthetical reference to the Senate amendment in section 302 of 
Public Law 101-549; the codifier's notes to this section state that the 
Senate amendment ``could not be executed'' because of the other 
amendment to section 111(d) contained in the same Act. The United 
States Code does not control here, however. The Statutes at Large 
constitute the legal evidence of the laws, where, as here, title 42 of 
the United States Code, which contains the CAA, has not been enacted 
into positive law. See 1 U.S.C. 204(a); United States v. Welden, 377 
U.S. 95, 98 n.4 (1964); Washington-Dulles Transportation Ltd. v. 
Metropolitan Washington Airports Auth., 263 F.3d 371, 378 (4th Cir. 
2001).
    A literal reading of the House amendment, as contained in the 
Statutes at Large, is that a standard of performance under CAA section 
111(d) cannot be established for any air pollutant that is emitted from 
a source category regulated under section 112. Under this reading, EPA 
could not regulate, under CAA section 111(d), HAP and non-HAP emissions 
that are emitted from a source category regulated under section 112. A 
literal reading of the Senate amendment is that a standard of 
performance under section 111(d) cannot be established for any HAP that 
is listed in section 112(b)(1), regardless of what categories of 
sources of that pollutant are regulated under section 112. The House 
and Senate amendments conflict in that they provide different standards 
as to the scope of EPA's authority to regulate under section 111(d).
    Over the years, EPA has identified other conflicting provisions of 
the CAA. See, e.g., Citizens to Save Spencer County v. EPA, 600 F.2d 
844 (D.C. Cir. 1979). Consistent with principles of statutory 
construction, the Agency has always sought to harmonize such 
conflicting provisions, where possible, and to adopt a reading that 
gives some effect to both provisions. The first step in this process 
involves an evaluation of what Congress intended by each amendment. 
This step is difficult here because of the absence of legislative 
history directly addressing the amendments. For that reason, we focus 
on the plain language of the amendments.
    The Senate language reflects the Senate's intent to retain the pre-
1990 approach of precluding regulation under CAA section 111(d) for any 
HAP that is listed under section 112(b). The Senate's intent is further 
demonstrated by the fact that the amendment itself it labeled a 
``conforming amendment,'' which is generally a non-substantive 
amendment. By contrast, the House amendment was not a conforming 
amendment. Rather, the House changed the focus of CAA section 111(d) 
and sought to preclude only regulation of pollutants emitted from a 
source category that is actually regulated under section 112. One 
reasonable interpretation is that the House amendment reflects a desire 
to change the pre-1990 approach and to expand EPA's authority as to the 
scope of pollutants that could be regulated under section 111(d). One 
possible reason for this change is that the House did not want to 
preclude EPA from regulating under section 111(d) those pollutants 
emitted from source categories which were not actually being regulated 
under section 112. Such a reading of the House language would authorize 
EPA to regulate under section 111(d) existing area sources which EPA 
determined did not meet the statutory criterion set forth in section 
112(c)(3), as well as existing Utility Units.
    One way to harmonize the Senate and House amendments is to 
interpret them as follows: Where a source category is being regulated 
under section 112, a section 111(d) standard of performance cannot be 
established to address any HAP listed under 112(b) that may be emitted 
from that particular source category. Thus, if EPA is regulating source 
category X under section 112, section 111(d) could not be used to 
regulate HAP emissions from that particular source category.
    We believe that this is a reasonable interpretation as it gives 
some effect to both amendments. First, it gives effect to the Senate's 
desire to focus on HAP listed under section 112(b), rather than 
applying the section 111(d) exclusion to non-HAP emitted from a source 
category regulated under section 112, which a literal reading of the 
House amendment would do. Second, it gives effect to the House's 
apparent desire to increase the scope of EPA's authority under section 
111(d) and to avoid duplicative regulation of HAP for a particular 
source category. We recognize that our proposed reconciliation of the 
amendments does not give full effect to the House's language, because a 
literal reading of the House language would mean that EPA could not 
regulate both HAP and non-HAP from a source category regulated under 
section 112. Such a reading would be inconsistent with the general 
thrust of the 1990

[[Page 4686]]

amendments, which, on balance, reflects Congress's desire to require 
EPA to regulate more substances, not to eliminate EPA's ability to 
regulate large categories of pollutants like non-HAP. Furthermore, EPA 
has historically regulated non-HAP under section 111(d), even where 
those non-HAP were emitted from a source category actually regulated 
under section 112. See, e.g., 40 CFR 62 1100 (California State Plan for 
Control of Fluoride Emissions from Existing Facilities at Phosphate 
Fertilizer Plants). We do not believe that Congress sought to eliminate 
regulation for a large category of sources in the 1990 Amendments and 
our proposed interpretation avoids this result.
    Finally, we believe that the proper inquiry for assessing whether 
to revise the December 2000 ``necessary'' finding is whether CAA 
section 111(d) constituted a viable statutory authority by which to 
address Hg and Ni emissions from existing coal- and oil-fired Utility 
Units as of 1998, the date on which EPA completed the Utility RTC. The 
answer, we believe, is yes. At that time, Utility Units were not listed 
under section 112, which consistent with our proposed interpretation of 
the conflicting amendments would allow us to regulate HAP from existing 
sources of such units under CAA section 111(d). The EPA, therefore, 
believes that it has the authority, and that it had the authority in 
1998 when it completed the Utility RTC, to regulate Hg emissions from 
existing coal-fired Utility Units and Ni emissions from existing oil-
fired units pursuant to section 111(d).
    Adequacy of regulation under section 111. Adequacy of regulatory 
methods. The EPA proposes to conclude that section 111 offers adequate 
regulatory authority to control Hg and Ni emissions from both existing 
and new coal- and oil-fired Utility Units. For existing sources, 
subsection (d) of section 111 authorizes EPA to promulgate ``standards 
of performance'' that States must include in SIP-like plans applicable 
to those sources. The term ``standard of performance'' is defined in 
section 111(a)(1) as--

a standard for emissions of air pollutants which reflects the degree 
of emission limitation achievable through the application of the 
best system of emission reduction which (taking into account the 
cost of achieving such reduction and any non-air quality health and 
environmental impact and energy requirements) the Administrator 
determines has been adequately demonstrated.\9\
---------------------------------------------------------------------------

    \9\ The term, ``standard of performance'' is also defined in 
section 302(l), although there may be uncertainty about whether that 
defintion applies to the term as used under section 111. For 
purposes of this discussion, the section 302(l) defintion is not 
material.

    The EPA believes that the gravamen of this definition is the 
phrase, ``best system of emission reduction.'' While the parenthetical 
following this phrase obligates EPA to consider the factors specified 
in that parenthetical, the term ``best system'' is not defined, and 
implicitly accords broad discretion to the Administrator, which 
includes the demonstration of such systems. The term ``system'' implies 
a broad set of controls, and the term ``best'' confers upon the 
Administrator the authority to promulgate regulations requiring 
controls that he considers superior. Moreover, except that the 
parenthetical phrase in the definition mandates consideration of 
certain factors, the definition provides no other explicit constraints 
in determining the ``best system.'' Therefore, EPA believes that in 
developing the ``best system of emission reduction,'' the Administrator 
must consider cost, non-air quality health and environmental factors, 
as well as energy requirements; and that he is authorized to consider, 
at his discretion, human health and environmental impacts, air quality 
impacts, timing and feasibility of control factors, and other factors.
    This broad authority conferred on the Administrator means that 
section 111 constitutes an adequate mechanism for regulating Hg 
emissions from coal-fired Utility Units, and Ni from oil-fired units. 
Because the Administrator may consider a broad range of factors in 
developing standards of performance under section 111, the 
Administrator has the authority to develop control levels to address 
the emissions of Hg and Ni that warrant regulation.
    Specifically, as described elsewhere in this notice, EPA is 
proposing today standards of performance for regulating Hg and Ni 
emissions from certain sources. In the case of Ni, EPA is proposing 
emission rate requirements to address emissions from oil-fired Utility 
Units. The basis for these standards of performance is discussed 
elsewhere in today's notice.
    In the case of Hg, EPA is proposing a ``cap-and-trade'' program for 
emissions of Hg from existing Utility Units. Mercury emissions, on a 
nationwide basis would, in effect, be capped at a specified level. This 
cap assures permanent reductions in Hg emissions, which an emissions 
rate control requirement cannot, in-and-of-itself, assure. States would 
be allocated specified amounts of Hg allowances--that is authorizations 
to emit a unit of Hg--which the States would then allocate to their 
Utility Units. The Utility Units would be permitted to emit Hg up to 
the amount of their allowances. The trading feature of this program 
would allow Utility Units to purchase or sell allowances, and adjust 
their emissions accordingly.
    The basis for the 2010 and 2018 caps is discussed elsewhere in 
today's notice. Moreover, the authorization to trade allows 
implementation of the emissions cap in the most cost-effective manner. 
Thus, the cap provides health protection by limiting overall emissions, 
but in a cost-effective manner.
    The EPA recognizes, however, that the overall cap level may not 
eliminate the risk of unacceptable adverse health effects of Hg 
emissions. Moreover, a cap-and-trade program raises the possibility 
that any particular utility may opt to purchase allowances, instead of 
implementing controls, and that this may result in continued Hg 
emissions at the previous, uncontrolled levels from that Utility Unit. 
These emissions may have adverse health impacts within the local area. 
The EPA recognized this issue in its initial 112(n) finding, when it 
stated:

    There is considerable interest in an approach to mercury 
regulation for power plants that would incorporate economic 
incentives such as emissions trading. Such an approach can reduce 
the cost of pollution controls by allowing for least-cost solutions 
among a universe of facilities that face different control costs. 
Trading also can allow for a greater level of control overall 
because it offers the opportunity for greater efficiency in 
achieving control. The EPA, however, recognizes and shares concerns 
about the local impacts of mercury emissions and any regulatory 
scheme for mercury that incorporates trading or other approaches 
that involve economic incentives must be constructed in a way that 
assures that communities near the sources of emissions are 
adequately protected. Thus, in developing a standard for utilities, 
the EPA should consider the legal potential for, and the economic 
effects of, incorporating a trading regime under section 112 in a 
manner that protects local populations.

(Regulatory Finding on the Emissions of Hazardous Air Pollutants From 
Electric Utility Steam Generating Units, FR 65 at 79830 and 65 FR 
79831).
    To assure that the overall cap level, and the pattern of Hg 
emissions resulting from the trading program, will be adequately 
protective, EPA proposes today to couple this program with an 
evaluation of whether Hg emissions remaining after compliance with the 
cap-and-trade requirements would cause unacceptable adverse health 
effects. That is, after implementation of the control requirements by 
2010 and by 2018, EPA will evaluate the emission levels, attendant 
health risks, and

[[Page 4687]]

available control mechanisms and determine whether the actual 
reductions achieved under this program significantly differ from the 
outcome predicted by our current analysis. The EPA retains the 
authority to revise its conclusions as to what constitutes the ``best 
system'' of emissions reductions for existing sources, and, therefore, 
to revise the standard of performance, to require additional reductions 
or controls to address such risks, based on information that would 
justify selection of a tighter regulatory regime.
    Similarly, EPA intends to evaluate whether, following 
implementation of the controls on Ni emissions from existing oil-fired 
units, adverse health effects might remain from Ni emissions. As 
described above, EPA retains authority under section 111(d) to 
promulgate additional requirements on Ni emissions to address those 
health effects.
    The EPA believes that these overall standards of performance for 
existing Utility Unit sources of Hg and Ni coupled with authority to 
evaluate remaining health risks and conduct further rulemaking, 
adequately address all health effects from Hg emissions that warrant 
regulation from existing coal-fired Utility Units and Ni emissions from 
existing oil-fired units as well as the environmental effects of Hg.
    As to new sources, section 111(b)(1)(B) authorizes EPA to 
promulgate ``standards of performance'' directly regulating new 
sources. The section 111(a)(1) definition of ``standard of 
performance'' applies to these regulations, and thereby authorizes EPA 
to consider the same range of factors described above, including, for 
example, human health and environmental factors as well as 
technological and feasibility factors. Upon consideration of these 
factors, EPA proposes a technology-based set of controls for Hg 
emissions from new coal-fired Utility Units and Ni emissions from new 
oil-fired units. The basis for these controls is discussed elsewhere in 
today's notice. Further, section 111(b) provides adequate authority for 
EPA (i) to evaluate whether, following compliance with the new source 
standards, remaining Hg and/or Ni emissions result in unacceptable 
adverse health impacts; and, if so, (ii) to revise the standards of 
performance to include additional restrictions for those emissions. As 
a result, for new sources of both Hg and Ni emissions, as in the case 
of existing sources, section 111 provides regulatory authority that 
will adequately address all adverse health (and environmental) effects 
of concern.
    Time for implementation. Why does regulation under section 111 
adequately address the hazards of concern to public health associated 
with Hg and Ni emissions? This action is one part of a broader effort 
to issue a coordinated set of emissions limitations for the power 
sector. Today's rule would establish a mechanism by which Hg emissions 
from new and existing 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 covered 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 adequately protect human health and the environment.
    The added benefit of this approach is that it dovetails well with 
the SO2 and NOX IAQR published elsewhere in 
today's Federal Register. This rule would establish a broadly-
applicable cap and trade program that would significantly limit 
SO2 and NOX emissions from the power sector. The 
advantage of regulating Hg at the same time and using the same 
mechanism as SO2 and NOX is that significant Hg 
emissions reductions can and will be achieved by the air pollution 
controls designed and installed to reduce SO2 and 
NOX. In other words, Hg is reduced as a ``co-benefit'' of 
controlling SO2 and NOX. Thus, the coordinated 
regulation of Hg, SO2, and NOX allows Hg 
reductions to be achieved in a particularly efficient and cost 
effective manner.
    In theory, the ``co-benefit'' argument could work in both 
directions: controlling Hg also controls SO2 and 
NOX; controlling SO2 and NOX also 
controls Hg. In deciding how regulatory deadlines influence how 
investments in controls are sequenced, it makes much more sense to lead 
with SO2 and NOX controls, which are well 
established, than to lead with Hg controls, which are only at the 
beginning stages of commercialization. Overly ambitious Hg mandates in 
the near-term could actually hamper innovation toward more effective 
and less costly technologies. The quantified health benefits of 
NOX and SO2 are also larger and more certain.
    The cap and trade approach to regulating Hg emissions offers 
certain other advantages over the unit-by-unit or facility-by-facility 
approach that we have traditionally employed under section 112. For 
example, a cap and trade system establishes fixed emissions caps that 
cannot be exceeded, even when existing plants are expanded and new 
plants are constructed. Thus, the cap provides absolute certainty with 
regard to national emissions. In contrast, a section 112 rule would 
limit the emissions of individual units or facilities, but would not 
limit overall emissions to the environment from the sector.
    Another advantage of concurrently regulating Hg and SO2 
is derived from the fact that companies will have the opportunity under 
the SO2 cap to generate extra allowances by achieving early 
reductions. For example, the first phase SO2 cap under the 
transport rule becomes effective in 2010. Prior to that year, companies 
have an incentive to achieve greater SO2 reductions than 
needed to meet the current Acid Rain cap because the excess allowances 
they generate can be ``banked'' and either later sold on the market or 
used to demonstrate compliance in 2010 and beyond at the facility that 
generated the excess allowances. In either case, there will be earlier 
health and environmental benefits because reductions are achieved 
sooner than they otherwise would be. These benefits extend to Hg 
emissions because, as explained above, we expect companies to meet the 
Hg cap by way of the controls they install for SO2 and 
NOX. Consequently, the incentive to achieve early reductions 
for SO2 effectively assures early reductions for Hg.
    Several additional technical and policy considerations strongly 
favor a cap-and-trade system. The objective of Hg control, as we 
understand it today, is not advanced as effectively under the 
prescriptive traditional MACT approach under section 112(d) for the 
regulation of HAP. The MACT approach calls for two phases of 
regulation: the first based on the concept of ``maximum achievable 
control technology''; the second, to occur 8 years later, based on a 
``residual health-risk determination.'' The second phase itself 
involves a complex, two-step framework: one step to determine a 
``safe'' or ``acceptable risk'' level, considering only public health 
factors, and the second to set an emission standard that provides an 
``ample margin of safety'' to protect public health, considering 
relevant factors in addition to health, such as costs, economic 
impacts, technical feasibility, uncertainties and other factors.
    First, a cap-and-trade approach sets a specific limit or cap on 
allowable emissions. Under a traditional section 112(d) MACT approach, 
standards are

[[Page 4688]]

based on rates of emissions per unit of input or of production, for 
example, pounds per million Btu. Variations in production or 
differences in input mix will result in fluctuations in Hg emissions. 
Thus, with shifts in coal use and with growth in the economy, Hg 
emissions would likely substantially exceed the overall emission level 
achieved when the MACT limits are initially met.
    Second, a trading approach is better suited to stimulating 
development and adoption of new technologies. A cap-and-trade system 
provides a market incentive for the development and use of cost-
effective technology to reduce Hg emissions. A MACT approach provides 
no such market incentive, so plants do not have an incentive to reduce 
emissions below the required level. Additionally, the ability to bank 
unused allowances for future use leads to early reductions of Hg 
emissions. A trading approach is forward-looking in its assessment of 
technology, in that it provides a continuous incentive for firms to 
innovate and develop more cost-effective technologies to reduce Hg 
emissions.
    The traditional section 112(d) MACT approach is designed to promote 
the use of proven control technologies by requiring all sources in a 
category to achieve the degree of emission control already accomplished 
by the average of the best 12 percent of sources in the category. 
However, such a MACT approach will not stimulate innovation in Hg 
control technology as well as a cap-and-trade approach because it does 
not reward reductions beyond the required levels.
    Indeed, a traditional 112(d) MACT approach even could inhibit 
innovation. Section 112(d) does provide legal authority to go ``beyond-
the-floor'' to require control strategies more stringent than the MACT 
floor, but the science, engineering and economics of Hg control have 
not progressed enough to support the technical determination that would 
be needed to support a section 112(d) standard that goes beyond the 
MACT floor. Once MACT-level controls are installed, there is little 
incentive for firms to develop even more effective technologies. In 
addition, the MACT deadline is so tight (2007 with only 1 year of 
possible extension) that affected firms would be unlikely to risk both 
capital and non-compliance in order to use more innovative approaches 
to Hg control.
    Moreover, a trading approach could spur the development of cost-
effective break-through technologies to control national and local Hg 
emissions. Such innovations would allow the U.S. to play a leadership 
role in the reduction of global Hg emissions as well. This is a crucial 
advantage of a trading approach to ultimately help remedy the problems 
posed by Hg emissions.
    Third, from a capital planning perspective, a trading approach 
permits utilities to make a much more rational investment in emissions 
control than a traditional MACT approach. We now understand that 
utility investments in reducing criteria air pollutants (particulate 
matter, sulfur dioxide and oxides of nitrogen) provide a ``co-benefit'' 
for Hg control because some forms of Hg (especially those that are 
deposited nearest plants) are controlled by the same technologies used 
to control criteria pollutants. The exact size of this co-benefit is 
not known. In any event, given the likelihood of co-benefits, it makes 
good economic sense for utilities to coordinate control of criteria air 
pollutants--especially those needed to achieve the new air quality 
standards for fine particulate matter and ozone--with their capital 
investments aimed at reducing Hg emissions. The statutory deadlines for 
a Hg MACT rule do not permit this rational sequence of investments.
    Thus, the Agency has carefully considered sections 112(d), 111, and 
112(n) to determine which is more appropriate for application to Hg 
emissions from coal-fired Utility Units. The scientific, engineering, 
economic, and environmental considerations all weigh heavily in favor 
of a trading-based approach.

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?

    In light of our revised interpretation of the scope of existing 
authority under the CAA, we have re-examined the results of the Utility 
RTC, focusing on the non-Hg and non-Ni HAP emissions from coal- and 
oil-fired Utility Units. The Study indicates that there are no non-Hg 
or non-Ni HAP emissions from Utility Units that warrant regulation.
    We do recognize that in December 2000, we stated that arsenic and a 
few other metals, such as chromium, Ni and cadmium, were of potential 
concern for carcinogenic effects (65 FR 79827). We continue to believe, 
as stated above, that the record supports a distinction between the 
treatment of Ni emissions from oil-fired Utility Units and the 
emissions of other non-Hg metallic HAP. Such a distinction is warranted 
based on the relative magnitude of Ni that is emitted from oil-fired 
utility units on an annual basis and the scope and number of adverse 
health effects associated with such emissions. Thus, although we 
recognize that uncertainties do exist with regard to the data and 
information we have obtained to date for non-Hg metallic HAP, including 
Ni, we believe that the nature of the uncertainties associated with the 
non-Hg, non-Ni metallic HAP are so great that regulation of such 
pollutants is not appropriate at this time since those pollutants do 
not pose a hazard to public health that warrants regulation. The EPA 
does intend, however, to continue to study these pollutants in the 
future. The EPA also intends to continue to study dioxins, HCl, and HF 
in the future, but, at this time, the Study and the information EPA has 
obtained since the Study reveal no public health hazards reasonably 
anticipated to occur as a result of these HAP emissions from Utility 
Units such that they warrant regulation.\10\
---------------------------------------------------------------------------

    \10\ As noted above, after the December 2000 finding, EPA 
conducted additional modeling that confirmed the Utility RTC's 
conclusion that acid gas HAP, such as HCl, HF, and Cl, pose no 
hazards to public health that warrant regulation. Furthermore, since 
December 2000, EPA has not obtained any new information that would 
cause it to modify its conclusion concerning the lack of health 
effects that warrant regulation associated with HAP other than Hg 
and Ni.
---------------------------------------------------------------------------

    Therefore, we believe that emissions of non-Hg and non-Ni HAP 
emissions from coal- and oil-fired Utility Units do not warrant 
regulation. We recognize that we based our appropriateness finding in 
December 2000, in part, on the existence of available control options 
that would reduce HAP emissions, including Hg, from Utility Units. See 
65 FR 79830. The focus on available technologies was, however, a 
subsidiary rationale and one that was included only after we had 
determined that emissions of particular HAP from coal- and oil-fired 
Utility Units posed significant hazards to public health and the 
environment and that those hazards could only be addressed under CAA 
section 112. See 65 FR 79830.
    As discussed above, we believe that any health effects resulting 
from Hg and Ni emissions from Utility Units can and will be addressed 
adequately pursuant to CAA section 111. Thus, while control strategies 
may exist to control the remaining HAP emitted from coal- and oil-fired 
Utility Units (i.e., HAP other than Hg and Ni), we do not believe that 
it is appropriate to regulate such HAP under section 112 where we have 
not determined that emissions of such HAP from Utility Units pose 
health hazards that warrant regulation. This conclusion is consistent 
with CAA section 112(n)(1)(A), in which Congress called for EPA to 
focus on the health effects of

[[Page 4689]]

HAP from Utility Units following imposition of the other requirements 
of the CAA.
    Moreover, even if in the future EPA finds that HAP emissions from 
Utility Units other than Hg and Ni emissions warrant regulation, EPA 
believes that CAA section 111 could be used to adequately address those 
hazards. Thus, EPA proposes to find that it is not only inappropriate 
to regulate coal- and oil-fired Utility Units under section 112 for HAP 
emissions other than Hg and Ni, but that it is not necessary to do so.

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)?

    In CAA section 112, Congress established a framework by which 
source categories could be listed, and once listed, emission standards 
developed for the listed source categories. The criteria and basis for 
listing a source category under section 112 differ depending on the 
sources at issue. (See generally CAA section 112(c) (discussing major 
and area sources).) In particular, for Utility Units, it only would be 
possible for EPA to list Utility Units under section 112(c) if it first 
made the section 112(n)(1)(A) finding that it was both appropriate and 
necessary to regulate such units under section 112, after EPA reviewed 
the results of its section 112(n)(1)(A) study concerning health effects 
and alternative control strategies.
    In its December 2000 notice EPA took this additional step and after 
finding it was appropriate and necessary to regulate Utility Units 
under section 112, went on to list coal- and oil-fired Utility Units 
under section 112(c)(65 FR 79831).
    As explained above, EPA has conducted a thorough re-analysis of the 
provisions of the CAA and determined that CAA section 111 is a viable 
statutory mechanism that would adequately address Hg and Ni emissions 
from coal- and oil-fired Utility Units. Therefore, EPA believes that 
the premise underlying its December 2000 ``necessary'' finding, that no 
other authority exists under the CAA to adequately address the public 
health hazards associated with Hg and Ni emissions, lacks foundation. 
The EPA also believes that it is not appropriate to regulate HAP other 
than Hg and Ni under section 112 because the Utility RTC reveals that 
there are no health hazards that warrant regulation associated with 
such HAP. Moreover, even if in the future EPA finds that there are HAP 
emissions (other than Hg and Ni) from Utility Units that pose hazards 
to public health and warrant regulation, EPA believes that CAA section 
111 would adequately address those hazards and, therefore, that 
regulation of such units under section 112 would not be necessary. For 
all of these reasons, EPA now believes that its initial decision to 
list coal- and oil-fired Utility Units under section 112(c) in December 
2000 was without proper foundation. The EPA, therefore, proposes to 
modify the section 112(c) list to delete coal- and oil-fired Utility 
Units as a source category. In light of EPA's interpretation and 
proposed use of its existing authority under the CAA and, in 
particular, CAA section 111, we propose to conclude that the statutory 
listing criteria were not met in December 2000.
    The EPAs proposed action here is wholly consistent with its 
historical interpretation of CAA section 112(c)(9), which is that the 
de-listing criteria in section 112(c)(9) apply only where the original 
listing of a source category was consistent with the statutory listing 
criteria. The failure to fully recognize the scope of existing 
statutory authority in December 2000, is analogous to those situations 
where EPA has listed a source category under section 112(c)(1), and 
later determined that it lacked a factual predicate for such listing 
and, therefore, delisted the source category without following the 
criteria of section 112(c)(9). The EPA has done this on several 
occasions. For example, in 1992, EPA listed asphalt concrete 
manufacturers as a major source category \11\ under section 112(c)(1), 
and then in 2002, delisted that category without following the 
statutory criteria in section 112(c)(9). The EPA did so because it 
determined that the initial criteria for listing had not been met since 
the sources in the asphalt concrete manufacturing category did not emit 
or have the potential to emit sufficient tons of hazardous air 
pollutants annually to satisfy the statutory definition of ``major 
source.'' See 67 FR 6521, 6522 (February 12, 2002); see also 63 FR 
7155, 7157 (February 12, 1998); 61 FR 28197, 28200 (June 4, 1996).
---------------------------------------------------------------------------

    \11\ Under the statute, a ``major source'' is any stationary 
source 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.
---------------------------------------------------------------------------

IV. Proposed Standards of Performance for Mercury and Nickel From New 
Stationary Sources and Emission Guidelines for Control of Mercury and 
Nickel From Existing Sources: Electric Utility Steam Generating Units

A. Background Information

1. What Is the Statutory Authority for The Proposed Section 111 
Rulemaking?
    Section 111(b) of the CAA requires EPA to promulgate standards of 
performance for emissions of air pollutants from new stationary 
sources. These standards are typically referred to as NSPS. Section 
111(d) requires the EPA to prescribe regulations that establish a 
procedure by which each State shall submit plans which establish 
standards of performance for existing sources for air pollutants for 
which air quality criteria have not been set but for which NSPS have 
been established.
2. What Criteria Are Used in the Development of NSPS?
    Section 111(a)(1) of the CAA requires that standards of performance 
reflect the

* * * degree of emission limitation achievable through application 
of the best system of emission reduction which (taking into account 
the cost of achieving such reduction and any non-air quality health 
and environmental impact and energy requirements) the Administrator 
determines has been adequately demonstrated.

    The reader is referred to our interpretation of standard of 
performance set forth above.

B. Proposed New Standards and Guidelines

1. What Source Category Is Affected by the Proposed Rulemaking?
    The subpart Da NSPS apply to Utility Units capable of firing more 
than 73 megawatts (MW) (250 million Btu/hour) heat input of fossil 
fuel. The current NSPS also apply to industrial cogeneration facilities 
that sell more than 25 MW of electrical output and more than one-third 
of their potential output capacity to any utility power distribution 
system.
2. What Pollutants Are Covered by the Proposed Rulemaking?
    The proposed rule would add Hg and Ni to the list of pollutants 
covered under subpart Da by establishing emission limits for new 
sources and guidelines for existing sources. New sources (and existing 
subpart Da facilities), however, remain subject to the applicable 
existing subpart Da emission limits for NOX, SO2, 
and PM. See 40 CFR part 60, subpart Da, Standards of Performance for 
Electric

[[Page 4690]]

Utility Steam Generating Units for which Construction is Commenced 
after September 18, 1978.
3. What Are the Affected Sources?
    Only those coal- and oil-fired Utility Units for which 
construction, modification, or reconstruction is commenced after 
January 30, 2004 would be affected by the proposed rule. Coal- and oil-
fired Utility Units existing at the time of this proposal would be 
affected facilities for purposes of the proposed section 111(d) 
guidelines described in this notice.
4. What Emission Limits Must I Meet?
    The following standards of performance for Hg are being proposed in 
today's notice for new coal-fired subpart Da units:

Bituminous units: 0.00075 nanograms per joule (ng/J) (0.0060 lb/
gigawatt-hour (GWh));
Subbituminous units: 0.0025 ng/J (0.020 lb/GWh);
Lignite units: 0.0078 ng/J (0.062 lb/GWh);
Waste coal units: 0.00087 ng/J (0.0011 lb/GWh);
IGCC units: 0.0025 ng/J (0.020 lb/GWh).

    The following standard of performance for Ni is being proposed for 
new oil-fired subpart Da units:

Ni: 0.010 (ng/J) (0.0008 lb/MWh).

    All of these standards are based on gross energy output.
    Compliance with the proposed standard of performance for Hg would 
be on a 12-month rolling average basis, as explained in section B.5 
below. This compliance period is appropriate given the nature of the 
health hazard presented by Hg (see section B.5 below). Compliance with 
the proposed standard of performance for Ni would be on a continuous 
basis.
5. What Are the 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. 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. Compliance with the proposed standard of 
performance for Hg 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.
    For new 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 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 section B.4 of the proposed rule.
    The owner/operator of a new 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 section B.4 of the proposed rule.
    Nickel emission limits. Compliance with the applicable proposed 
standard of performance for Ni would be determined by performance tests 
conducted according to the requirements in 40 CFR 60.8 and 40 CFR 60.11 
of the NSPS 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 pounds per trillion British thermal 
units (lb/TBtu) if complying with an input-based standard.
    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.
    The owner/operator of a new 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. The procedure for 
determining these Ni emission rates are given in Sec. 60.46a of the 
proposed rule.
6. What Are the 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 limits for oil-fired units. In addition, an 
annual performance test will be required for demonstrating compliance 
with the proposed standard of performance for Ni for oil-fired units. 
The annual performance test would be conducted in

[[Page 4691]]

the same manner as the initial compliance demonstration.
7. What Are the 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 60, 
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. The owner/operator would be required to submit 
notifications described in the General Provisions (40 CFR part 60, 
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 excess emissions reports of 
any deviations when any monitored parameters fell outside the range of 
values established during the performance test.

C. Rationale for the Proposed Subpart Da Standards

1. What Is the Rationale for the Proposed Subpart Da Hg and Ni 
Standards?
    In December 2000, EPA announced a finding that regulation of Hg 
emissions from coal-fired Utility Units and Ni emissions from oil-fired 
Utility Units under CAA section 112 was appropriate and necessary. As 
explained above, we are proposing today to revise that finding. We 
continue to believe, however, that the HAP of greatest concern from 
coal-fired units is Hg, with Ni being the HAP of greatest concern from 
oil-fired units. In December 2000, based on the record before the 
Agency, EPA estimated that coal-fired Utility Units in the U.S. emitted 
approximately 48 tons of Hg into the atmosphere in 1999, and that 
methylmercury, the end product of Hg deposited to water bodies, is a 
significant health hazard, particularly to sensitive subpopulations. 
The EPA also found that Hg emissions could in some cases be reduced 
through application of control technology. Finally, the record 
supporting the December 2000 action reveals that oil-fired Utility 
Units emitted approximately 322 tons of Ni in 1994.
    Today's action proposes standards under the regulatory authority of 
section 111(b), which will regulate Hg (from coal-fired units) and Ni 
(from oil-fired units) emissions from new units on which construction 
is commenced after today's date, and emissions guidelines under the 
authority of section 111(d), which will regulate Hg emissions from 
existing coal-fired Utility Units and Ni emissions from existing oil-
fired Utility Units.
    The source of Hg and Ni emissions from these units is the same at 
both new and existing steam generating units; therefore, in general, 
the control of these emissions would be the same as well. Throughout 
this preamble, where clear distinctions arise, the rationales for the 
EPA actions affecting new and existing units are discussed separately. 
Otherwise, the discussion applies to the proposed standards and 
emission guidelines.
2. What Is the Performance of Control Technology on Hg?
    Currently, there are no commercially available control technologies 
specifically designed for reducing Hg emissions. However, available 
data indicate that controls installed for reducing emissions of PM, 
SO2, and NOX are also effective in some cases in 
reducing Hg emissions from coal-fired Utility Units. The degree of 
removal, however, depends (in part) on the rank of coal being burned.
    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 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. 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, 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 generally is 
successful in identifying some common core characteristics that have 
implications for power 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.

[[Page 4692]]

    The rank of coal to be burned has an enormous 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 optimal 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 impact on 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, impact on boiler 
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.
    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 SO2 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.
    The flue gases resulting from the combustion of these different 
coal ranks can exhibit different Hg emissions characteristics. These Hg 
emissions characteristics consist of varying percentages of the three 
relevant forms (or species) of Hg (particulate-bound, oxidized (ionic), 
and elemental) that makeup the total Hg in the flue gas.
    Available source test data shows that combustion of bituminous coal 
results in Hg emissions that are composed of relatively more Hg\++\ 
compared to the other coal ranks. Combustion of bituminous coal 
produces the most particulate-bound Hg of any of the three major coal 
ranks combusted. Combustion of subbituminous coal results in emissions 
that are composed of relatively more elemental Hg (compared to 
bituminous coal), with little particulate-bound Hg (less than half that 
of bituminous coal emissions). Combustion of lignite coal also results 
in emissions that are composed of relatively more elemental Hg 
(compared to bituminous coal) with little particulate-bound Hg (also 
less than half that of bituminous coal emissions). Available data 
indicate that emissions from the combustion of coal refuse tends to 
result almost entirely in particulate-bound Hg (greater than 99 percent 
for both units tested in the 1999 EPA ICR). With few exceptions, 
particulate-bound Hg can be removed with PM controls, Hg\++\ can be 
removed with wet SO2 controls (FGD scrubbers), but elemental 
Hg usually shows little to no removal with any existing conventional 
type of APCD used on utility boilers. However, new technologies such as 
activated carbon adsorption show promise in removing elemental Hg.
    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, integrated 
gasification combined cycle (IGCC) units, and fluidized bed combustors 
(FBC).
    Conventional boilers, also known as pulverized coal (PC) boilers, 
have a number of firing configurations based on their burner placement. 
The basic characteristic that all conventional boilers have in common 
is that they inject PC and primary air through a burner where ignition 
of the PC occurs, which in turn creates an individual flame. 
Conventional boilers fire through many such burners mounted in the 
furnace walls.
    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 CO. The synthetic coal gas 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.

[[Page 4693]]

    Available information indicates that Hg emissions from coal-fired 
Utility Units are minimized in some cases through the use of PM 
controls coupled with an FGD system. For bituminous-fired units, use of 
a selective catalytic reduction (SCR) or selective noncatalytic 
reduction (SNCR) system may further enhance Hg removal. This does not 
appear to be the case for subbituminous- and lignite-fired units. The 
EPA believes the best potential way of reducing Hg emissions from IGCC 
units is to remove Hg from the syngas before combustion. An existing 
industrial IGCC unit has demonstrated a process, using sulfur-
impregnated AC carbon beds, that has proven to yield 90 to 95 percent 
Hg removal from the coal syngas. This technology could potentially be 
adapted to the electric utility IGCC units. The EPA believes this to be 
a viable option for IGCC units.
3. What Is the Performance of Control Technology on Ni?
    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 
exclusively or to alternate between oil and natural gas at a single 
boiler is usually based on economics or fuel availability (including 
seasonal availability). The ASTM classifies oils by ``grade,'' a term 
which relates to the amount of refinement that the oil undergoes. The 
level of refinement directly affects the Ni and carbon content of the 
oil and other related parameters such as sulfur content, heating value, 
and specific gravity. The most refined fuel oil used by the oil-fired 
electric utility industry is known as No. 2 fuel oil (also known as 
distillate oil or medium domestic fuel oil). The least refined fuel oil 
used by the oil-fired electric utility industry is known as No. 6 fuel 
oil (also known as residual oil or Bunker C oil). By comparison, No. 2 
fuel oil is lower in Ni, sulfur, ash content, and heating value but 
higher in carbon content than No. 6 fuel oil. Only a handful of boilers 
(8 of 218) fire No. 2 distillate fuel oil exclusively. (2001 EIA data) 
However, 28 out of 218 boilers fire No. 2 distillate fuel oil and No. 6 
(residual) fuel oil in the same boiler (either simultaneously or at 
separate times).
    The proposed standard of performance for Ni from new oil-fired 
units was determined by analyzing the emissions data available. The 
data were obtained from the Utility RTC which provided information 
indicating that Ni was the pollutant of concern due to its high level 
of emissions from oil-fired units and the potential health effects 
resulting from exposure to it. The EPA examined available test data and 
found that ESP-equipped units can effectively reduce Ni. The proposed 
standard of performance for Ni is based on the level of control 
demonstrated by the top performing existing units with regard to 
removal of Ni. The test data were converted to an output-based limit 
using an efficiency factor.
    The EPA is sensitive to the fact that some sources burn fuels 
containing very little Ni. Therefore, EPA solicits comment on a Ni-in-
oil limit that would be equivalent to the proposed stack value of 
0.0005 lb/MWh gross. With a limit on the amount of Ni in the oil, a new 
source could choose to comply with an alternate oil-content-based Ni 
emission limitation instead of the stack Ni emission limit to meet the 
proposed rule. Such an alternate Ni-in-oil limit could be useful where 
Ni constituent levels are low in the fuel.
    Dual-Fired (Oil/Natural Gas) Units. The EPA is aware that an oil-
fired unit may fire oil at certain times of the year and natural gas at 
other times. The choice of when to fire oil or natural gas is usually 
based on the economics or availability of fuel (i.e., seasonal 
considerations). The EPA considers a unit to be an oil-fired unit if 
(1) it is equipped to fire oil and/or natural gas, and (2) it fires oil 
in amounts greater than or equal to 2 percent of its annual fuel 
consumption. This 2 percent value is intended to represent that amount 
of oil that a true natural gas-fired unit might use strictly for start-
up purposes on an annual basis. The EPA solicits comment on whether 
this two percent breakpoint is a reasonable basis for allowing those 
units that use oil only for startup purposes to be exempted from 
regulation under the proposed rule.
4. What Is the Regulatory Approach?
    Subpart Da Hg emission standards. In selecting a regulatory 
approach for formulating emission standards to limit Hg emissions from 
new coal-fired steam generating units, the performance of the Hg 
control technologies discussed above were considered. The technical 
basis (i.e., BDT) selected for establishing Hg emission limits for new 
sources is the use of effective PM controls and wet or dry FGD systems 
on subbituminous-, lignite-, and waste coal-fired units and effective 
PM controls, wet or dry FGD systems, and SCR or SNCR on bituminous-
fired units, and activated carbon beds for IGCC units.
    Section 111(b)(2) of the CAA allows the Administrator to ``* * * 
distinguish among classes, types, and sizes within categories of new 
sources * * *'' in establishing standards when differences between 
given types of sources within a category lead to corresponding 
differences in the nature of emissions and the technical feasibility of 
applying emission control techniques. After examining a number of 
possible subcategorization options, EPA identified two basic ways to 
subcategorize coal-fired Utility Units, by coal rank or by process 
type.
    Subcategorization by coal rank. Subcategorization by individual 
coal rank addresses the differences in the characteristics of the Hg 
emissions (i.e., speciation of Hg) and the resulting ability to control 
Hg as well as accommodating the various design and control constraints 
resulting from the various coal ranks.
    Subcategorization by process type. Another option is to 
subcategorize by process type. Different process types could create 
potential emissions differences which lead to corresponding differences 
in the nature of emissions and the technical feasibility of applying 
emission control techniques. Although conventional-, stoker-, and 
cyclone-fired boilers use different firing techniques, the Hg emissions 
characteristics of these boilers are similar (given that common ranks 
of coal are fired) and, therefore, the units can be grouped together. 
Although these units fire a variety of coal ranks they have only 
combusted coal refuse in lesser amounts as a secondary fuel source.
    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.
    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.
    Based on the above discussion, the EPA is proposing to use five 
subcategories for establishing Hg limits based on a combination of coal 
rank and

[[Page 4694]]

process type in this rule (bituminous coal, subbituminous coal, lignite 
coal, coal refuse, and IGCC).
    The EPA's review of the available emission data shows that Hg 
emissions from new coal-fired units can be reduced to the following:

Bituminous units: 0.61 lb/TBtu heat input;
Subbituminous units: 2.0 lb/TBtu heat input;
Lignite units: 6.3 lb/TBtu heat input;
Waste coal units: 0.11 lb/TBtu heat input;
IGCC units: 2.0 lb/TBtu heat input.

    Mercury emissions from new oil- and gas-fired units are not covered 
by the proposed rule.
    Subpart Da Ni emission standards. In selecting a regulatory 
approach for formulating emission standards to limit Ni emissions from 
new oil-fired steam generating units, the performance on Ni of the PM 
control technologies discussed above were considered. The technical 
basis (i.e., BDT) selected for establishing Ni emission limits for new 
sources is the use of ESP units or oils low in Ni content.
    The EPA's review of the available emission data shows that Ni 
emissions from new oil-fired units can be reduced to 84 lb/TBtu heat 
input.
5. What Are the Subpart Da Hg and Ni Emission Standards?
    Based on available performance data analyses from the 1999 ICR for 
coal-fired Utility Units, the Administrator has concluded that the 
application of fabric filters or ESP units along with wet or dry FGD is 
considered to be the most effective Hg control technology for units 
firing subbituminous, lignite, or waste coals; and that the application 
of fabric filters or ESP units, wet or dry FGD systems, and SCR is 
considered to be the most effective Hg control technology for units 
firing bituminous coals. For IGCC units (regardless of coal rank 
fired), the Administrator has concluded that use of a carbon bed is 
considered to be the most effective Hg control technology. These 
controls represent the best system of emissions reductions (taking into 
consideration the cost of achieving such emissions reductions, any non-
air quality health and environmental impact, and energy requirements).
    Based on available performance data and cost analyses, the 
Administrator has concluded that the application of ESP units or oils 
containing a low Ni content is considered to be the most effective Ni 
control technology for oil-fired units. These controls represent the 
best system of emissions reductions (taking into consideration the cost 
of achieving such emissions reductions, any non-air quality health and 
environmental impact, and energy requirements).
6. How Did EPA Select the Format for the Proposed Standards?
    Based on the analyses and discussion presented earlier, EPA has 
selected an output-based format for the proposed new-source rule. The 
Administrator is proposing today Hg emission limits for new coal-fired 
Utility Units as follows:

Bituminous units: 0.0060 GWh gross;
Subbituminous units: 0.020 lb/GWh gross;
Lignite units: 0.062 lb/GWh gross;
Waste coal units: 0.0011 lb/GWh gross;
IGCC units: 0.020 lb/GWh gross.

    Based on the available performance data, cost analysis, and the 
above calculation, the Administrator is proposing today Ni emission 
limits for new oil-fired Utility Units as follows: 0.0008 lb/MWh gross.
7. How Did EPA Determine Testing and Monitoring Requirements for the 
Proposed Standards?
    The CAA requires EPA to develop regulations that ensure initial and 
continuous compliance. Testing and monitoring requirements allow EPA to 
determine whether an affected source is operating in compliance with an 
applicable emission limitation/standard. This section discusses how EPA 
selected the proposed testing and monitoring requirements used to 
determine compliance with the Hg and Ni emission limits that are 
specified in the proposed rule.
    Mercury testing and monitoring requirements. The proposed rule 
would establish Hg emission limits for coal-fired units. The format 
selected for these Hg emission limits is a 12-month rolling average Hg 
emission level expressed in units of lb/TBtu or lb/MWh. Therefore, 
appropriate testing or monitoring requirements for determining the 
amount of Hg emitted from an affected unit throughout the compliance 
averaging period must be included in the rule.
    The most direct means of demonstrating compliance with an emission 
limit is by the use of a CEMS that measures the pollutant of concern. 
The EPA considers other testing or monitoring options when acceptable 
CEMS are not available for the intended application or when the impacts 
of including such CEMS requirements in the proposed rule are considered 
by EPA to be unreasonable. In determining whether to require the use of 
other testing or monitoring options in lieu of CEMS, it is often 
necessary for EPA to balance more reasonable costs against the quality 
or accuracy of the actual emissions data collected.
    There are several approaches to Hg monitoring that EPA has 
identified for possible use in this rule to determine compliance with 
the proposed Hg emission limits. One option is to use a CEMS that 
combines both automated sampling and analytical functions in a single 
system to provide continuous, real-time Hg emission data. Mercury CEMS 
are currently available from several manufacturers. These Hg CEMS are 
similar to most other types of instruments used for continuous 
monitoring of pollutants from combustion processes, in that the 
combustion gas sample is first extracted from the stack and then 
transferred to an analyzer for analysis. In general, the Hg CEMS now 
available can be distinguished by the Hg measurement detection 
principle used (e.g., atomic adsorption, atomic fluorescence, x-ray 
fluorescence). Capital costs for a Hg CEMS are currently estimated to 
range from approximately $95,000 to $135,000, depending on the 
manufacturer and model selected. The annual costs to operate and 
maintain a Hg CEMS are estimated to range from $45,000 to $65,000, 
again depending on the manufacturer and model selected.
    A second option is to use a long-term sampling method that collects 
a cumulative Hg sample by continuously passing a low-flow sample stream 
of the combustion process flue gas through a Hg trapping medium (e.g., 
an activated carbon tube). This sampling tube is then periodically 
removed (e.g., after a day or up to 1 month) and replaced with a tube 
filled with fresh trapping medium. The removed sampling tube is then 
sent to a laboratory where the trapping medium is analyzed for its Hg 
content. This method, like using a Hg CEMS, is capable of providing 
data on the Hg emissions from a combustion process on a continuous 
basis, but unlike a Hg CEMS, the data are not reported on a real-time 
basis. Using the long-term sampling method, the Hg collected in the 
sampling tube is integrated over a much longer sampling period (i.e., 1 
to 7 days for the AC tube versus less than 15 minutes for the CEMS). 
The capital cost for a gas metering system and Hg trapping medium is 
estimated to be approximately $18,000. The annual costs for periodic 
sampling tube replacement and for the laboratory Hg analysis range from 
approximately $65,000 to $125,000 depending upon quality assurance and 
quality control (QA/QC) requirements and frequency of sample tube 
replacement.

[[Page 4695]]

    Finally, a third monitoring option is to use one of the manual 
stack test methods available for measuring Hg emissions from combustion 
processes on an intermittent basis. The existing voluntary consensus 
stack test method ASTM Method D6784-02 (commonly known as the Ontario-
Hydro method) is currently the method of choice for measuring Hg 
species in the flue gas from Utility Units. Another method for 
measuring total (i.e., not speciated) Hg is EPA Reference Method 29. 
This method involves a technician extracting a representative flue gas 
sample over a relatively short period of time (e.g., a few hours) using 
a sampling train consisting of a nozzle and probe, a filter to collect 
particulate matter, and a liquid solution and/or reagent to capture 
gas-phase Hg. After sampling, the filter and sorption media are 
prepared and analyzed for Hg in a laboratory. These test methods could 
be applied to a Hg monitoring program at electric utility plants by 
performing a manual stack test using ASTM Method D6784-02 or EPA 
Reference Method 29 at some specified periodic interval throughout the 
compliance averaging period (e.g., perform a stack test daily, weekly, 
biweekly, monthly). The cost to conduct a single ASTM Method D6784-02 
typically ranges from $15,000 to $17,000 depending on site conditions. 
Annual costs will depend on the frequency with which the stack test is 
required to be performed during the compliance averaging period. For 
example, if the test is required once per week, the total annual cost 
would be as much as $780,000 (52 tests in a 12-month period at $15,000 
per test).
    The EPA evaluated each of the above Hg monitoring options with 
respect to its suitability for the measurement of the Hg emission data 
needed for determining compliance with the 12-month rolling average Hg 
emission limit. The EPA rejected from further consideration the third 
option, intermittent monitoring using manual stack test methods. Use of 
this monitoring approach would place significantly higher labor 
requirements and monitoring costs on facility owners/operators than the 
other two options in order to perform an adequate number of source 
tests throughout the compliance averaging period to demonstrate with 
reasonable confidence that the applicable Hg emission limit value was 
being achieved.
    Both of the remaining two options would provide the necessary data 
to calculate the total Hg emissions from an affected source for each 
12-month compliance averaging period. While the CEMS would provide 
these data on a real-time basis, EPA concluded that having real-time 
data is not mandatory for determining compliance with an emission limit 
based on a 12-month rolling average. Total Hg emissions from an 
affected source by month are needed to compute the rolling 12-month 
average Hg emission value. With regular scheduled replacement and 
timely analysis of sampling tubes, total monthly Hg emissions can 
readily be obtained using the long-term sampling method.
    The EPA then compared the costs of applying the Hg CEMS and long-
term monitoring options to Utility Units. While the CEMS have 
significantly higher capital costs, the automated analyses directly by 
the instrument eliminates the need and cost for separate analyses of 
the collected sampling tubes in a laboratory required by the long-term 
sampling method. Overall, EPA determined that the total costs of using 
either monitoring method to determine compliance would be similar for a 
given site. Selection of which monitoring method should be used at the 
site will depend on site-specific conditions and owner/operator 
preferences. Because both monitoring methods will collect the Hg 
emission data necessary to determine compliance with the proposed Hg 
emission limit and the costs of either option are reasonable, EPA 
decided to allow the owner/operator flexibility under the proposed rule 
to choose to use either Hg CEMS or long-term sampling monitoring as 
best suits their site conditions and preferences.
    An owner/operator electing to use a CEMS to comply with the rule 
would be allowed to use any CEMS that meets the requirements in 
``Performance Specification 12A, Specifications and Test Procedures for 
Total Vapor-phase Mercury Continuous Monitoring Systems in Stationary 
Sources'' (PS-12A). This performance specification is proposed as part 
of this rulemaking and we request comment on continuous monitoring of 
Hg emissions according to the requirements in the proposed performance 
specification.
    Those owners/operators electing to use long-term Hg monitoring 
would be required to follow the requirements in Method 324, 
``Determination of Vapor Phase Flue Gas Mercury Emissions from 
Stationary Sources Using Dry Sorbent Trap Sampling'' when it is 
promulgated. Method 324 is proposed as part of this rulemaking to be 
added to 40 CFR part 60, appendix A. We request comments on the 
requirements in proposed Method 324 for Hg measurement using long-term 
sampling.
    Continuous compliance requirements are required under every NSPS so 
that EPA can determine whether an affected source remains in compliance 
with the applicable emission limitation/standard following the initial 
compliance determination. In the case of the proposed NSPS, the format 
for the Hg emission limit is a 12-month rolling average limit. The same 
monitoring requirements used to establish initial compliance of an 
affected electric utility unit with the applicable Hg emission limit at 
the end of the first 12-month period following the facility's 
compliance date serve to demonstrate continuous compliance with the Hg 
emission limit with the computation of each new 12-month rolling 
average value each month thereafter. Thus, no additional continuous 
compliance Hg monitoring requirements beyond those previously discussed 
are required for the proposed rule.
    The EPA is concerned about monitoring costs for units with low Hg 
emissions rates, and does not desire to adopt a monitoring scheme where 
the costs are disproportionate to the costs of compliance with the MACT 
emissions limitations. For these units (e.g., those emitting under 25 
pounds per year) the EPA may consider reduced monitoring frequencies 
and lower cost monitoring requirements, since the need for accuracy is 
reduced for such units. For example, the EPA is concerned about the 
merits of requiring an expenditure of $100,000 per year to monitor 
releases when the costs of substantive compliance is far less. The 
Agency requests comments and related data upon which to establish an 
alternate reporting scheme.
    Nickel testing and monitoring requirements. The proposed rule would 
establish Ni emission limits for oil-fired units. The EPA selected a 
different format for the Ni emission limits than is proposed for the Hg 
emission limits. The Ni emission limits are maximum allowable emission 
limits not to be exceeded, expressed in lb/TBtu or lb/MWh.
    The EPA selected the proposed testing requirements to determine 
compliance with the Ni emission limits to be consistent with existing 
procedures used for the electric utility industry. Method 29 in 
appendix A to 40 CFR part 60 is an EPA reference test method that has 
been developed and validated for the measurement of Ni emissions from 
stationary sources. For sampling and analysis of the gas stream, the 
following EPA reference methods would be used with Method 29: Method 1 
to select the sampling port location and the number of traverse points; 
Method

[[Page 4696]]

2 to measure the volumetric flow rate; Method 3 for gas analysis; and 
Method 4 to determine stack gas moisture. Method 19 specifies the 
procedure for collecting the necessary fuel data to be used with the 
Method 29 Ni measurements from the source test to compute the Ni 
emission rate expressed in units of lb/TBtu.
    As an alternative under the proposed rule, an owner/operator of an 
existing oil-fired source could choose to comply with the applicable Ni 
emission limit expressed in lb/MWh.
    To address the need for continuous compliance requirements for the 
proposed Ni emission limits, EPA considered the availability and 
feasibility of a number of Ni monitoring options ranging from direct 
monitoring of Ni emissions, to process parameter monitoring, to control 
device parameter monitoring. Monitors for continuously measuring Ni 
emissions have not been demonstrated in the U.S. for the purpose of 
determining compliance. Therefore, EPA did not consider further the use 
of any continuous monitoring for Ni for the proposed rule.
    Another option used in other NSPS for demonstrating continuous 
compliance is to monitor appropriate process and/or control equipment 
operating parameters. These parameters are established during the 
initial, and any subsequent, stack test. Process parameters were not 
selected as indicators for Ni emissions from Utility Units because a 
direct correlation does not exist between combustion or electricity 
production parameters and Ni emission rates from a given unit.
    Monitoring of PM control device operating parameters is used in 
other NSPS established for combustion processes and other source 
categories that include PM emission limits. The EPA decided to also use 
this continuous monitoring approach to demonstrate continuous 
compliance with the applicable Ni emission limits set forth in the 
proposed rule. The selected operating parameters for the PM control 
device used by oil-fired Utility Units (e.g., ESP) are reliable 
indicators of control device performance. The EPA believes that 
reasonable assurance of compliance with the emission limits proposed 
for this NSPS can be achieved through appropriate monitoring and 
inspection of the operation of the APCD that have been demonstrated by 
an initial performance test to achieve the applicable Ni emission 
limits under the rule.
    Compliance calculations. For 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. This consideration is accomplished by taking the net 
efficiency of a cogeneration unit into account. 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, 205). To determine 
the process steam energy contribution to net plant output, a 50 percent 
credit of the process steam heat is necessary.
    Therefore, owners/operators of cogeneration units subject to the 
proposed rule would need to monitor the portion of their net plant 
output that is process steam so that they can take the 50 percent 
credit of the energy portion of their process steam net output. For 
example, a cogeneration unit subject to the rule measures its net 
electrical output over a compliance period, as 30,000 MWh. During the 
same period the unit burns coal that provides 750 billion Btu input to 
its furnace/boiler, and emits 0.2 lb Hg. Using equivalents found in 40 
CFR part 60 for electric utilities (i.e., 250 million Btu/hr input to a 
boiler is equivalent to 73 MWe input to the boiler; 73 MWe input to the 
boiler is equivalent to 25 MWe output from the boiler; therefore, 250 
million Btu input to the boiler is equivalent to 25 MWe output from the 
boiler) the 50 percent credit could be found as follows. The net output 
calculation would be 750 billion Btu x (25 MWe output/250 million Btu/
hr input) = 75,000 MWh equivalent electrical output from the boiler 
over the compliance period. Of this amount, 30,000 MWh was produced as 
electricity sent to the grid, leaving 45,000 MWh as the energy 
converted to steam for process use. Half of this amount is 22,500 MWh. 
The unit's Hg CEM records a total of 0.2 lb Hg over the same compliance 
period. The adjusted Hg emission rate is then: 0.2 lb Hg/(30,000 MWh + 
22,500 MWh) = 3.8 x 10-6 lb Hg/MWh. Cogeneration units would 
have to account for the process steam portion of their emissions in the 
same manner for PM emissions as well.
8. How Did EPA Determine the Compliance Times for the Proposed 
Standards?
    New sources are required to be in compliance either upon start up 
or the effective date of this rule, whichever is later.
9. How Did EPA Determine the Required Records and Reports for the 
Proposed Standards?
    Under section 114(a) of the CAA, EPA may require owners/operators 
of affected sources subject to a NSPS to maintain records as well as 
prepare and submit notifications and reports to the EPA. In addition, 
section 504(a) of the CAA mandates that sources required to obtain a 
title V permit submit a report setting forth the results of any 
required monitoring no less often than every 6 months. The general 
recordkeeping, notification, and reporting requirements for all NSPS 
are specified in 40 CFR 60.7 and 40 CFR 60.19 of the General 
Provisions, if incorporated into the proposed rule. The recordkeeping, 
notification, and reporting requirements for the proposed rule were 
selected to include all of the applicable records, notifications, and 
reports specified by the General Provisions requirements. Additional 
requirements were included in the proposed rule that are necessary to 
ensure that a given affected source is complying with the emission 
limits from the correct subcategory.
    The proposed rule would also require that the owner/operator keep 
monthly records for each affected source listing the type of fuel 
burned, the total fuel usage, and the fuel heating value. Additional 
recordkeeping would be required for those owners/operators electing to 
comply with a fuel blending emission limit. The owner/operator would be 
required to maintain records of all compliance calculations and 
supporting information.

D. Rationale for the Proposed Hg Emission Guidelines

1. What Is the Authority for Cap-and-Trade Under Section 111(d)?
    Section 111(d)(1) authorizes EPA to promulgate regulations that 
establish a State Implementation Plan-like (SIP-like) procedure under 
which each State submits to EPA a plan that, under subparagraph (A), 
``establishes standards of performance for any existing source'' for 
certain air pollutants, and which, under subparagraph (B), ``provides 
for the implementation and enforcement of such standards of 
performance.'' Paragraph (1) continues, ``Regulations of the 
Administrator under this paragraph shall permit the State in applying a 
standard of performance to any particular source under a plan submitted 
under this paragraph to take into consideration, among other factors, 
the remaining useful life of the existing source to which such standard 
applies.'' Section 111(a) defines, ``(f)or purposes

[[Page 4697]]

of * * * section (111),'' the term ``standard of performance'' to mean

a standard for emissions of air pollutants which reflects the degree 
of emission limitation achievable through the application of the 
best system of emission reduction which (taking into account the 
cost of achieving such reduction and any non-air quality health and 
environmental impact and energy requirements) the Administrator 
determines has been adequately demonstrated.

    Taken together, these provisions authorize EPA to promulgate a 
``standard of performance'' that States must, through a SIP-like 
system, apply to existing sources. A ``standard of performance'' is 
defined as a rule that limits emissions to the degree achievable 
through ``the best system of emission reduction'' that EPA ``determines 
has been adequately demonstrated,'' considering costs and other 
factors.
    A cap-and-trade program reduces the overall amount of emissions by 
requiring sources to hold allowances to cover their emissions on a one-
for-one basis; by limiting overall allowances so that they cannot 
exceed specified levels (the ``cap''); and by reducing the cap to less 
than the amount of emissions actually emitted, or allowed to be 
emitted, at the start of the program. In addition, the cap may be 
reduced further over time. Authorizing the allowances to be traded 
maximizes the cost-effectiveness of the emissions reductions in 
accordance with market forces. Sources have an incentive to endeavor to 
reduce their emissions below the number of allowances they receive; if 
they can do so cost-effectively, they may then sell their excess 
allowances on the open market. On the other hand, sources have an 
incentive to not put on controls that cost more than the allowances 
they may buy on the open market.
    The term ``standard of performance'' is not explicitly defined to 
include or exclude an emissions cap and allowance trading program. In 
today's action, EPA proposes to interpret the term ``standard of 
performance,'' as applied to existing sources, to include a cap-and-
trade program. This interpretation is supported by a careful reading of 
the section 111(a) definition of the term, quoted above: A requirement 
for a cap-and-trade program (i) constitutes a ``standard for emissions 
of air pollutants'' (i.e., a rule for air emissions), (ii) ``which 
reflects the degree of emission limitation achievable'' (i.e., which 
requires an amount of emissions reductions that can be achieved), (iii) 
``through application of (a) * * * system of emission reduction'' 
(i.e., in this case, a cap-and-trade program that caps allowances at a 
level lower than current emissions).\12\
---------------------------------------------------------------------------

    \12\ The legislative history of the term, ``standard of 
performance,'' does not address an allowance/trading system, but 
does indicate that Congress intended that existing sources be 
accorded flexibility in meeting the standards. See ``Clean Air Act 
Amendments of 1977,'' Committee on Interstate and Foreign Commerce, 
H.R. Rep. No. 95-294 at 195, reprinted in 4 ``A Legislative History 
of the Clean Air Act Amendments of 1977,'' Congressional Research 
Service, 2662. The EPA interprets this legislative history as 
generally supportive of interpreting ``standard of performance'' to 
include an allowance/trading program because such a program accords 
flexibility to sources.
---------------------------------------------------------------------------

    Nor do any other provisions of section 111(d) indicate that the 
term ``standard of performance'' may not be defined to include a cap-
and-trade program. Section 111(d)(1)(B) refers to the ``implementation 
and enforcement of such standards of performance,'' and section 
111(d)(1) refers to the State ``in applying a standard of performance 
to any particular source,'' but all of these references readily 
accommodate a cap-and-trade program.
    Although section 111(a) defines ``standard of performance'' for 
purposes of section 111, section 302(l) defines the same term, ``(w)hen 
used in this Act,'' to mean ``a requirement of continuous emission 
reduction, including any requirement relating to the operation or 
maintenance of a source to assure continuous emission reduction.'' The 
term ``continuous'' is not defined in the CAA.
    Even if the 302(l) definition applied to the term ``standard of 
performance'' as used in section 111(d)(1), EPA believes that a cap-
and-trade program meets the definition. A cap-and-trade program with an 
overall cap set below current emissions is a ``requirement of * * * 
emission reduction.'' Moreover, it is a requirement of ``continuous'' 
emissions reductions because all of a source's emissions must be 
covered by allowances sufficient to cover those emissions. That is, 
there is never a time when sources may emit without needing allowances 
to cover those emissions.\13\
---------------------------------------------------------------------------

    \13\ This interpretation of the term ``continuous'' is 
consistent with the legislative history of that term. See H.R. Rep. 
No. 95-294 at 92, reprinted in 4 Congressional Research Service, A 
Legislative History of the Clean Air Act Amendments of 1977, 2559.
---------------------------------------------------------------------------

    We note that EPA has on one prior occasion authorized emissions 
trading under section 111(d). (The Emission Guidelines and Compliance 
Times for Large Municipal Waste Combustors that are Constructed on or 
Before September 20, 1994; 40 CFR part 60, subpart Cb.) This provision 
allows for a NOX trading program implemented by individual 
States. Section 60.33b(C)(2) states,

    A State plan may establish a program to allow owners or 
operators of municipal waste combustor plants to engage in trading 
of nitrogen oxides emission credits. A trading program must be 
approved by the Administrator before implementation.

    Today's proposal is wholly consistent with this prior section 
111(d) trading provision.
    Having interpreted the term ``standard of performance'' to include 
a cap-and-trade program, EPA must next ``determine'' that such a system 
is ``the best system of emissions reductions which (taking into account 
the cost of achieving such reduction and any non-air quality health and 
environmental impact and energy requirements) * * * has been adequately 
demonstrated.'' Section 111(a)(1). The EPA proposes to determine that a 
cap-and-trade program has been adequately determined to be the best 
system for reducing Hg emissions from coal-fired Utility Units.
    Since the passage of the 1990 Amendments to the CAA, EPA has had 
significant experience with the cap-and-trade program for utilities. 
The 1990 Amendments provided, in title IV, for the acid rain program, a 
national cap-and-trade program that covers SO2 emissions 
from utilities. title IV requires sources to hold allowances for each 
ton of emissions, on a one-for-one basis. The EPA allocates the 
allowances for annual periods, in amounts initially determined by the 
statute, and that decrease further at a statutorily specified time. 
This program has resulted in an annual reduction in SO2 
emissions from utilities from 15.9 million tons in 1990 (the year the 
Amendments were enacted) to 10.2 million tons in 2002 (the most recent 
year for which data is available). Emissions in 2002 were 9 percent 
lower than 2000 levels and 41 percent lower than 1980, despite a 
significant increase in electrical generation. As discussed elsewhere, 
at full implementation after 2010, emissions will be limited to 8.95 
million tons, a 50 percent reduction from 1980 levels. The Acid Rain 
program allowed sources to trade allowances, thereby maximizing overall 
cost-effectiveness.
    In addition, in the 1998 NOX SIP Call rulemaking, EPA 
promulgated a NOX reduction requirement that affects 21 
States and the District of Columbia (``Finding of Significant 
Contribution and Rulemaking for Certain States in the Ozone Transport 
Assessment Group Region for Purposes of Reducing Regional Transport of 
Ozone; Rule,'' 63 FR 57,356 (October 27, 1998)). All of the affected 
jurisdictions are implementing the requirements through a cap-and-trade 
program for NOX emissions

[[Page 4698]]

primarily from utilities.\14\ These programs are contained in SIP that 
EPA has approved; and EPA is administering the trading programs. 
However, for most States, the requirements do not need to be 
implemented until May, 2004.
---------------------------------------------------------------------------

    \14\ Non-electricity generating units (EGU) are also included in 
the States' programs.
---------------------------------------------------------------------------

    The success of the Acid Rain cap-and-trade program for utility 
SO2 emissions, which EPA duplicated in large measure with 
the NOX SIP Call cap-and-trade program for, primarily, 
utility NOX emissions, leads EPA to propose to conclude that 
a cap-and-trade program for Hg emissions from utilities qualifies as 
the ``best system of emission reductions'' that ``has been adequately 
demonstrated.'' A market system that employs a fixed tonnage limitation 
(or cap) for Hg sources from the power sector provides the greatest 
certainty that a specific level of emissions will be attained and 
maintained since a predetermined level of reductions is ensured. The 
EPA will administer a Hg trading program and will require the use of 
continuous emissions monitoring systems (CEMS) or an appropriate long-
term method that will allow both EPA and sources to track progress, 
ensure compliance, and provide credibility to the trading component of 
the program. The advantages of the Hg trading program are discussed 
further below. We ask for comments on all aspects of this approach 
under section 111(d).
2. What Is the Regulatory Approach for Existing and New Sources?
What Are the National Hg Budget and Source Emission Limits?
    Mercury budget overview. Our primary goal in this rulemaking is to 
reduce power plant emissions of Hg by 70 percent from today's levels by 
2018. We are proposing to accomplish this goal by setting a 15 ton cap 
on these emissions in 2018. Under our proposal, the 2018 cap would be a 
permanent cap that could not be exceeded, regardless of future growth 
in the energy sector. Thus, the cap would effectively become more 
stringent as more and more plants are required to keep their collective 
emissions below 15 tons.
    We also are proposing to set a near-term cap in 2010 at a level 
that reflects the maximum reduction in Hg emissions that could be 
achieved through the installation of FGD and SCR units that will be 
necessary to meet the 2010 caps for SO2 and NOX 
in our proposed IAQR. Although we know that FGD and SCR units reduce Hg 
emissions (as well as SO2 and NOX), there is 
significant uncertainty about the extent of the Hg reductions that 
these controls could achieve by 2010. Thus, we are seeking technical 
information that would allow us to establish an appropriate Hg cap in 
2010.
    The EPA believes that a carefully designed ``multi-pollutant'' 
approach--a program designed to control NOX, SO2, 
and Hg at the same time--is the most effective way to reduce emissions 
from the power sector. One key feature of this approach is the 
interrelationship of the timing and cap levels for SO2, 
NOX, and Hg. Today, we know that power plants can reduce 
their emissions of all three pollutants by installing FGD (which 
controls SO2 and Hg emissions) and SCR (which controls 
NOX and Hg). With respect to the first phase of Hg 
reductions, we have designed this proposal to take advantage of the 
combined emission reductions that these technologies provide. 
Therefore, we believe that the Phase I Hg cap should be set at a level 
that reflects the Hg reductions that would be achieved from the 
SO2 and NOX cap levels and corresponding control 
requirements in the IAQR that we also are proposing today.
    A phase-one cap based on this approach would set a standard of 
performance based on the best system of emissions reduction that has 
been adequately demonstrated, consistent with section 111(d) of the 
Clean Air Act. Research currently indicates that Hg control 
technologies other than FGD and SCR--most notably activated carbon 
injection (ACI) and breakthrough technologies (e.g., chemical systems 
to enhance removal efficiencies for wet scrubbers)--may one day allow 
facilities to reliably reduce Hg emissions to levels significantly 
below the levels achieved through application of FGD and SCR needed to 
satisfy SO2 and NOX control requirements. 
However, these technologies have not been adequately demonstrated on 
full-scale power plants. Moreover, current information on these 
technologies is not sufficient for us to conclude that they will be 
adequately demonstrated by 2010. Therefore, we believe that the 2010 
cap for Hg should be set at a level that can be achieved through the 
installation of FGD and SCR needed to meet the 2010 SO2 and 
NOX caps in the proposed IAQR. Requiring additional FGD and 
SCR beyond those needed to meet the transport rule in order to further 
reduce Hg emissions by 2010 is not reasonable because the incremental 
cost of such a requirement for additional Hg reductions would be 
extremely high and the capacity of the equipment suppliers may be 
overwhelmed.\15\
---------------------------------------------------------------------------

    \15\ Analysis conducted in support of the proposed IAQR predicts 
that SO2 scrubbers will be installed on 48.7 GW of 
existing coal-fired capacity to comply with the Phase I cap. The 
analysis also predicts that SCRs will be installed on 24.1 GW of 
capacity to reduce NOX emissions. In addition, we predict 
that existing SCRs that are currently operated on a seasonal basis 
(i.e., for the ozone season) will under the IAQR be operated for the 
entire year. These technologies (FGD and SCR) have been developed to 
reduce SO2 and NOX emissions. However, they do 
realize collateral reductions in Hg, although these reductions are 
variable (and somewhat uncertain) across types of coal and other 
control technologies used for treatment. The available modeling 
suggest that these NOX and SO2 controls are 
predicted to reduce Hg emissions from the power sector to a level of 
approximately 34 tons per year.
---------------------------------------------------------------------------

    Consistent with this framework, we are seeking comment and specific 
technical information concerning the 2010 cap level that should be set 
for Hg in the final rule. Almost 2 years ago, the Administration 
proposed Clear Skies legislation that would have established a 26 ton 
Hg cap in 2010. This cap was based on several factors, including 
modeling and policy analysis and technical information that was 
available at that time. Our most recent analysis, based on the most 
recent technical information, suggests that Hg emissions would be 
reduced to approximately 34 tons as a result of the FGD and SCR that 
will be installed to meet the 2010 caps for SO2 and 
NOX in the proposed IAQR. Modeling done by the Energy 
Information Agency (EIA) suggests that the controls required under our 
proposed IAQR would not reduce Hg to the extent that EPA is projecting. 
We are also aware that some stakeholders have recommended near-term Hg 
reductions that are lower than our estimates.
    We recognize that there is and will be for the immediate future 
uncertainty about all these estimates. To a large extent, this 
uncertainty exists because we have relatively little direct experience 
and data about the Hg reductions that can be achieved through different 
combinations of FGD and SCR on different boiler types burning different 
ranks of coal, and because there is a high degree of variability in the 
data that we do have. For example, based on the ICR data, it appears 
that plants with very similar configurations, and that burn similar 
ranks of coal, often achieve significantly different levels of Hg 
control. Thus, if we receive additional technical information, we may 
be able to find that plants can better optimize their FGD and SCR units 
to achieve greater reductions in their Hg emissions than we currently 
estimate. We therefore seek any technical information, including 
information

[[Page 4699]]

about incremental costs and benefits, that provides the basis for any 
of the levels mentioned above or other proposals for a near-term cap.
    As noted above, EPA is proposing a 15 ton cap in 2018 from coal-
fired electric generating facilities. This proposed cap reflects a 
level of Hg emissions reduction that almost certainly exceeds the level 
that would be achieved through the installation of FGD and SCR needed 
to meet the SO2 and NOX caps in the proposed 
IAQR. We conclude that this approach is warranted because we fully 
expect other Hg air pollution control technologies such as ACI and/or 
one or more of the breakthrough technologies will have been adequately 
demonstrated before 2018, making it possible to begin achieving much 
greater reductions in Hg between 2010 and 2018. This conclusion relies 
on the fact that the small number of current-day pilot scale ACI 
projects at Utility Units and the innovative technologies will yield 
information that will be usable in implementing similar pilot scale 
projects at other facilities. Data from these pilot studies ultimately 
will allow companies to design full scale applications that will 
provide reasonable assurance that emissions limitations can be reliably 
achieved over extended compliance periods. We do not believe that such 
full scale technologies can be developed and widely implemented within 
the next 6 years; however, it is reasonable to assume that this can be 
accomplished over the next 14 years.
    Our proposed 15 ton cap in 2018 is grounded largely in the modeling 
completed in support of the President's Clear Skies initiative. This 
modeling suggests that, assuming technologies such as ACI become 
available, such a cap will create an incentive for certain plants to 
install these newer technologies. It also suggests that such controls 
should not have any significant impact on power availability, 
reliability, or pricing. Nor should a 15-ton cap cause any significant 
shift in the fuels currently utilized by power plants or in the source 
of these fuels. Sensitivity analyses indicate that a more stringent cap 
could have potentially significant impacts on fuels and/or power 
availability, reliability, or pricing. Less stringent caps do not 
appear warranted based on our expectations about technology development 
and our modeling analysis of the potential impacts of the 15-ton cap.
    The Agency continues to investigate whether the mandatory 70 
percent reduction in Hg emissions will be adequate to eliminate public 
health risks from local Hg deposition near plants because of scientific 
and technical uncertainties. The Agency requests comment on this issue.
    The EPA is also proposing a method for apportioning the nation-wide 
budget to individual unit sources. The EPA maintains that the emission 
budget provides an efficient method for achieving necessary reductions 
in Hg emissions (as described in earlier sections of this preamble), 
while providing substantial flexibility in implementing the program.
    The EPA has concern about Utility Units with low Hg emissions rates 
(e.g., emitting less than 25 pounds per year) because the new, Hg-
specific control technologies that we expect to be developed prior to 
the Phase II cap deadline may not practicably apply to such units 
period. Our data indicate that the 396 smallest emitting coal-fired 
Utility Units currently account for less than 5 percent of total Hg 
emissions. There is reason to believe that the 15 ton Phase II cap can 
be achieved in a cost-effective manner, even if the lowest emitting 396 
units are excluded from coverage under this cap. Thus, the EPA is 
soliciting comment on the possibility of excluding from the Phase II 
cap units with low Hg emissions rates (e.g., emitting less than 25 
pounds per year).
    In today's notice of proposed rulemaking, EPA is also proposing 
that allowances are allocated to affected Utility Units based on the 
proportionate share of their baseline heat input to total heat input of 
all affected units. For purposes of allocating the allowances, each 
unit's baseline heat input is adjusted to reflect the ranks of coal 
combusted by the unit during the baseline period. The sum of the unit 
emission allowances in a State would be considered the State's 
emissions budget. If States choose not to participate in the trading 
program, the State budgets and unit emission allocations will become 
the required maximum emission limit. States also can require emissions 
reductions beyond those required by the State budget and unit emission 
limits.
    As discussed elsewhere in this preamble, new sources will comply 
with NSPS standards for Hg. In addition, new sources will be covered 
under the Hg cap of the trading program, and will be required to hold 
allowances equivalent to the product of their NSPS and baseline heat 
input. The EPA proposes that these sources not receive an adjustment to 
their allocated share of allowances since they are required to meet 
NSPS, which may increase total emissions but will maintain required 
emissions rates.
    Rationale for source level limits (allowances). Unit-level 
emissions limits will be proposed in a supplemental notice entitled 
``Emission Guidelines and Compliance Times for Coal-fired Electric 
Utility Steam Generating Units.'' If a State chooses to participate in 
the trading program, these unit-level emission limits can be adopted as 
unit-level allocations for the trading program. Additionally, the 
trading program provides the individual States the discretion in 
choosing how to allocate their respective budget allocations.
    Different ranks of coal may achieve different Hg reductions 
depending on the control equipment installed at the unit. In order to 
distribute unit limits equitably, EPA is proposing that Hg emission 
limits (allowances if State is participating in a trading program) are 
distributed to existing coal units based on their share of total heat 
input. This is then adjusted to reflect the concern that the 
installation of PM, NOX, and SO2 control 
equipment on different coal ranks results in different Hg removal.
    The adjustment factors of 1 for bituminous, 1.25 for subbituminous, 
and 3 for lignite coals are based on the expectation that Hg in the 
coal ranks reacts differently to NOX and SO2 
control equipment and that the heat input of the different coal ranks 
varies. The conclusion that Hg in each of the coals reacts differently 
to NOX and SO2 control equipment was based on 
information collected in the ICR as well as more recent data collected 
by EPA, DOE, and industry sources. This information, which was 
collected from units of various coal ranks and control equipment 
configuration, indicated differing levels of Hg removal. The test data 
indicated that installation of PM, NOX, and SO2 
controls on plants burning bituminous coals resulted in greater Hg 
reduction on average than plants burning subbituminous coals or lignite 
coals. Likewise, the test data indicated that installation of PM, 
NOX, and SO2 controls on plants burning 
subbituminous coals resulted in somewhat greater Hg removal than plants 
burning lignite coals. On average, units burning lignite coal showed 
the least Hg removal of the three coal ranks. See section C.4 for 
further discussion on subcategorization approaches considered under 
this proposal.
    Under the proposed emission limit or allocation methodology, 
bituminous units would be allocated a share of the allowances 1.0 times 
their share of the overall heat input, subbituminous units would be 
allocated a share of the allowances 1.25 times their share of the 
overall heat input, and lignite units

[[Page 4700]]

would be allocated a share of the allowances 3.0 times their share of 
the overall heat input. These adjustment factors are considered to be 
directionally correct based on the test data currently available; 
however, we realize that these factors do not in all cases accurately 
predict relative rates of Hg emissions from Utility Units with 
NOX and SO2 controls. Our goal, however, is not 
to have the factors achieve such a result. Rather, the factors are 
intended to equitably distribute allowances to the affected industry. 
The EPA is taking comment on the appropriateness of these adjustment 
factors. Since new sources are required to meet NSPS, EPA is proposing 
new sources will not receive an adjustment to their allocated share.
    Distribution of State budgets. The trading program establishes a 
cap on Hg emissions for affected electric generating units of 15 tons 
starting in 2018. The proposed unit level emission limits (allocations) 
are the basis for establishing State budgets with the State budgets 
equaling the total of the individual unit emission limits in a given 
State (see Table 5 of this preamble below). States also have the 
flexibility to not participate in the trading program or require more 
stringent Hg emissions reductions. For States that do not participate 
in the trading program, the proposed unit level allocations will become 
fixed, unit level emissions limitations.

                 Table 5.--Distribution of State Budgets
------------------------------------------------------------------------
                                                                Phase II
                            State                                budget
                                                                 (tons)
------------------------------------------------------------------------
Alabama......................................................      0.506
Alaska.......................................................      0.002
Arizona......................................................      0.289
Arkansas.....................................................      0.202
California...................................................      0.016
Colorado.....................................................      0.277
Connecticut..................................................      0.023
Delaware.....................................................      0.029
District of Columbia.........................................      0.000
Florida......................................................      0.491
Georgia......................................................      0.483
Hawaii.......................................................      0.009
Idaho........................................................      0.000
Illinois.....................................................      0.635
Indiana......................................................      0.833
Iowa.........................................................      0.284
Kansas.......................................................      0.281
Kentucky.....................................................      0.605
Louisiana....................................................      0.236
Maine........................................................      0.001
Maryland.....................................................      0.186
Massachusetts................................................      0.070
Michigan.....................................................      0.517
Minnesota....................................................      0.274
Mississippi..................................................      0.114
Missouri.....................................................      0.545
Montana......................................................      0.148
Nebraska.....................................................      0.165
Nevada.......................................................      0.112
New Hampshire................................................      0.025
New Jersey...................................................      0.060
New Mexico...................................................      0.240
New York.....................................................      0.157
North Carolina...............................................      0.451
North Dakota.................................................      0.614
Ohio.........................................................      0.810
Oklahoma.....................................................      0.285
Oregon.......................................................      0.030
Pennsylvania.................................................      0.710
Rhode Island.................................................      0.000
South Carolina...............................................      0.226
South Dakota.................................................      0.028
Tennessee....................................................      0.378
Texas........................................................      1.837
Utah.........................................................      0.224
Vermont......................................................      0.000
Virginia.....................................................      0.234
Washington...................................................      0.077
West Virginia................................................      0.554
Wisconsin....................................................      0.353
Wyoming......................................................      0.375
------------------------------------------------------------------------

    Model cap-and-trade program. The EPA is outlining a national cap-
and-trade program that States may choose as a cost-effective mechanism 
to achieve the emissions reductions requirements in today's rulemaking. 
The trading program will meet these requirements by utilizing a cap on 
total emissions in order to ensure that emissions reductions under 
today's proposed rulemaking are achieved, while providing the 
flexibility and cost effectiveness of a market-based system. This 
section provides background information and a description of the 
trading program and an explanation of how the trading program would 
interface with other State and Federal programs. It is EPA's intent to 
propose a model rule in a future supplemental notice.
    States can voluntarily choose to participate in the trading 
programs by adopting the model rule, which is a fully approvable 
control strategy for achieving emissions reductions required under the 
proposed section 111 rulemaking. Should the States voluntarily choose 
to participate in the trading program by adopting the model rule, EPA's 
authority to cooperate with and assist the States in the implementation 
of the trading program resides in both State law and the CAA. With 
respect to State law, any State which elects to adopt the model rule as 
part of its section 111 SIP-like rule will be authorizing EPA to assist 
the State in implementing the trading program with respect to the 
sources in that State. With respect to the CAA, EPA believes that the 
Agency's assistance to those States that choose to participate in the 
trading program will facilitate the implementation of the program and 
minimize administrative burden on the States.
    Purpose of the trading program and model rule. In the trading 
program, EPA is proposing to jointly implement with participating 
States a capped market-based program for certain Utility Units to 
achieve and maintain an emissions budget consistent with the proposed 
section 111 rulemaking. Specifically, today's proposal is designed to 
assist States in: (1) Achieving emissions reductions required under the 
proposed section 111 rulemaking; (2) ensuring flexibility for regulated 
sources; (3) reducing compliance costs for sources; and (4) reducing 
administrative costs to States. In addition to these benefits of 
electing to participate in the proposed trading program, EPA also seeks 
to create as simple a regulatory regime as possible by applying a 
single, comprehensive regulatory approach to all of the affected 
jurisdictions.
    Beyond choosing to use the proposed trading program, State adoption 
of the model rule would ensure consistency in certain key operational 
elements of the program among participating States, while allowing each 
State flexibility in other important program elements. Uniformity of 
the key operational elements across the participating states would 
ensure a viable and efficient trading program with low transaction 
costs and minimum administrative costs for sources, States, and EPA.
    Emissions reductions required by the proposed section 111 
rulemaking.
    State-level emission budgets. Each of the States and the District 
of Columbia covered by today's proposal has been assigned a statewide 
emissions budget for Hg. The statewide budgets were developed by 
totaling unit-level emissions reductions requirements for coal-fired 
electricity generating devices. The statewide budget development 
process is fully described elsewhere in today's preamble. States have 
the flexibility to meet these State budgets by participating in a 
trading program or requiring source level reductions to coal-fired 
electric generating units. States have the ability to require 
reductions beyond those required by the state budget.
    Geographic scope of trading program. As discussed elsewhere in this 
preamble, today's proposal would apply to all coal-fired Utility Units 
located in all 50 states of the U.S.

[[Page 4701]]

    Each State has been assigned a statewide emissions budget for Hg. 
Each of these States must submit a SIP-like plan detailing the controls 
that will be implemented to meet its specified budget for reductions 
from electric generating units. Therefore, should some States choose to 
achieve the mandated reductions by using an approach other than the 
proposed emissions trading rule, the geographic scope of the trading 
program would not be nationwide.
    Some stakeholders have noted that modeling results suggest that Hg 
deposition from emissions from Utility Units may be higher in certain 
regions of the country (e.g., the upper Ohio Valley and Mid-Atlantic 
areas). In addition, the ecosystems in some regions (e.g., the lakes 
regions of the Upper Midwest) may be more sensitive to Hg deposition. 
As discussed more fully below, given the 70 percent emission reduction 
in the proposed section 111 rule and our experience with cap-and-trade 
systems, EPA does not expect any local or regional hot spots. The EPA 
is interested in comments on whether it would be appropriate to adjust 
the geographic scope of this program to introduce trading ratios 
between regions as a way of addressing regional differences should they 
occur. For example, EPA could require that eastern Utility Units in 
areas of heavy deposition would need greater than 1:1 allowances from 
Utility Units outside the region to cover an ounce of Hg emissions. The 
EPA is interested in comments on whether such an approach is 
appropriate, and if so, on the way to identify appropriate regions 
where a higher trading ratio would apply and the appropriate magnitude 
of the trading ratio. The EPA is also interested in comments on the 
extent to which these adjustments would complicate and reduce the 
efficiency of the cap-and-trade program.
    Affected sources in the trading program. The model trading rule 
applies to coal-fired Utility Units. The term ``electric utility steam 
generating unit'' means any fossil fuel fired combustion unit that 
serves a generator of more than 25 MW that produces electricity for 
sale. A unit that cogenerates steam and serves a generator that 
supplies more than one-third of its potential electric output capacity 
and more than 25 MW electrical output to any utility power distribution 
system for sale shall be considered an Utility Unit.
    Benefits of participating in the trading program. Advantages of 
cap-and-trade over command-and-control. When designed and implemented 
properly, a market-based program offers many advantages over its 
traditional command-and-control counterpart. See discussion, supra, 
Section III. Six principal advantages of market-based systems have been 
recognized: (1) Results in a certain, fixed cap in emissions from 
affected and potentially affected sources; (2) potential for the 
creation of incentives for early reductions; (3) creation of incentives 
for emissions reductions beyond those required by regulations; (4) 
reduced cost of compliance for individual sources and the regulated 
community in general; (5) promotion of innovation and continued 
evolution of production and pollution control technology; and, (6) 
increased flexibility for the regulated community without resorting to 
waivers, exemptions and other forms of administrative relief. These 
benefits result primarily from the flexibility in compliance options 
available to sources and the monetary reward associated with avoided 
emissions in a market-based system. The cost of compliance in a market-
based program is reduced because sources have the freedom to pursue 
various compliance strategies, such as switching fuels, installing 
pollution control technologies, or buying authorizations to emit from a 
source that has over-complied. Since emissions level below the level 
mandated allows the freeing up of allowances that may be sold on the 
market, pollution prevention becomes more cost effective, and 
innovations in less-polluting alternatives and control equipment are 
encouraged.
    A market system that employs a fixed tonnage limitation (or cap) 
for a source or group of sources provides the greatest certainty that a 
specific level of emissions will be attained and maintained since a 
predetermined level of reductions is ensured. With respect to transport 
of pollution, an emissions cap also provides the greatest assurance to 
downwind States that emissions from upwind States will be effectively 
managed over time. The capping of total emissions of pollutants over a 
region and through time ensures achievement of the environmental goal 
while allowing economic growth through the development of new sources 
or increased use of existing sources. In an uncapped system (where, for 
example, sources are required only to demonstrate that they meet a 
given emission rate) the addition of new sources to the regulated 
sector or an increase in activity at existing sources can increase 
total emissions even though the desired emission rate control is in 
effect.
    In addition, the reduced implementation burden for regulators and 
affected sources benefits taxpayers and those who must comply with the 
rules. This streamlined administrative approach allows a small number 
of government employees to successfully regulate many sources by (1) 
minimizing the necessity for case-by-case rules and (2) taking full 
advantage of electronic communication and data transfer to track 
compliance and develop detailed, critical inventories of emissions and 
plant operations.
    Application of the cap-and-trade approach in prior rulemakings. 
Title IV. Title IV of the 1990 Amendments to the CAA established the 
Acid Rain Program, a program that utilizes a market-based cap-and-trade 
approach to require power plants to reduce SO2 emissions by 
50 percent from 1980 levels by 2010. At full implementation after 2010, 
emissions will be limited, or capped, at 8.95 million tons. It also 
includes emission rate requirements to reduce NOX emissions. 
The Acid Rain Program for SO2 is widely acknowledged as a 
model air pollution control program because it provides significant and 
measurable environmental and human health benefits with low 
implementation costs.
    Units are allocated their share of the total allowances, each 
allowance providing an authorization to emit a ton of SO2, 
based upon historical records of the heat content of the fuel that they 
combusted during the period 1985 to 1987. Units that reduce their 
emissions below the number of allowances they hold may trade allowances 
with other units in their system, sell them to other sources on the 
open market or through EPA auctions, or bank them to cover emissions in 
future years. Each affected unit is required to surrender allowances to 
cover its emissions each year. Should any unit fail to hold sufficient 
allowances, automatic penalties apply. In addition to financial 
penalties, units either will have allowances deducted immediately from 
their accounts to offset their allowance deficiencies or, if such 
deduction would threaten electric reliability, may submit a plan to EPA 
that specifies when the allowances will be deducted in the future.
    An essential feature of the Acid Rain Program is the requirement 
for affected sources to install systems that continuously monitor 
emissions. The use of CEMS was an important innovation that allowed 
both EPA and sources to track progress, ensure compliance, and provide 
credibility to the trading component of the program.
    While title IV does provide for an Acid Rain Permit, the permit 
simply states a non-source specific requirement that sources comply 
with the standard

[[Page 4702]]

rules of the program. Acid Rain permitting has been easily incorporated 
into the title V permit process and does not require the typically 
resource intensive, case-by-case review associated with other permits 
under command-and-control programs.
    The Acid Rain Program has achieved major SO2 emissions 
reductions, and associated air quality improvements, quickly and cost-
effectively. In 2002, SO2 emissions from power plants were 
10.2 million tons, 41 percent lower than 1980. True to its intent, the 
program has substantially reduced acid deposition, allowing lakes and 
streams in the Northeast to begin recovering from decades of acid rain. 
The Acid Rain Program resulted in emission reductions well below the 
cap in the areas that contribute most of the sulfur in the acid rain. 
Comparing emissions from the 263 power plants regulated in the first 
phase of the program in 1999 with those in 1990, the North Central and 
Southeast and Mid-Atlantic regions achieved 49 percent, 48 percent and 
43 percent reductions in SO2, respectively. Several analyses 
of trading under the acid rain program have concluded that the program 
did not result in local areas with ``hot spots.''
    Trading under the Acid Rain Program has created financial 
incentives for electricity generators to look for new and low-cost ways 
to reduce emissions, and improve the effectiveness of pollution control 
equipment, at costs much lower than predicted. In fact, the Acid Rain 
Program achieved reductions at two-thirds the cost of achieving the 
same reductions under a command-and-control system. The cap on 
emissions and significant automatic penalties for noncompliance ensure 
that environmental goals are achieved and sustained, while stringent 
emissions monitoring and reporting requirements make flexibility 
possible. The level of compliance under the Acid Rain Program continues 
to be uncommonly high, measuring over 99 percent.
    NOX SIP call and OTC Trading Program. The cap-and-trade 
approach has also been used to address regional ozone transport 
problems in the eastern U.S. The north-eastern states (Ozone Transport 
Commission) began implementing a cap-and-trade program to address 
regional ozone transport in 1999. The NOX Budget Trading 
Program under the NOX SIP Call began its first year of 
implementation in 2003 in the Northeast. Eleven additional States will 
join in 2004. Each of the States required to submit a NOX 
SIP to address the regional transport of ozone chose to participate in 
the interstate trading program. They each based their trading program 
on the model rule; some states essentially adopted it in full, other 
states modified some provisions for their unique circumstances.
    Local environmental improvements achieved using cap-and-trade 
model. Mercury emissions from power plants sometimes are deposited 
locally near the plant. Nearby lakes may be a source of fish 
consumption for recreational and/or subsistence fisherman, and thus 
local Hg deposition in nearby lakes could be a source of what are 
called hot spots. In this discussion, we are assuming that a power 
plant may lead to a hot spot if the contribution of the plant's 
emissions of Hg to local deposition is sufficient to cause blood Hg 
levels of highly exposed individuals near the plant to exceed the RfD. 
For the purposes of choosing a regulatory tool to address hot spots, 
the relevant question is what is the contribution of these plants to 
hot spots under a cap-and-trade approach, relative to their current 
contribution and their projected contribution under a traditional 
section 112 approach.
    Concerns about hot spots have been raised despite the success and 
growing use of cap-and-trade programs. The EPA believes that a trading 
approach will help to address this problem. In addition to reductions 
required by the cap, all States would have the ability to address local 
health-based concerns separate from the Hg cap-and-trade program 
requirements.
    The EPA does not anticipate significant local health-based concerns 
under a national Hg trading program. The Agency has considered this 
possibility and believes that the cap-and-trade system, coupled with 
related Federal and State programs, will effectively address local 
risks. This has been EPA's experience with the title IV program 
limiting SO2 emissions.
    First, modeling runs suggest that large coal-fired Utility Units--
those that tend to have relatively high Hg emissions--are likely to 
have larger local deposition footprints than medium-sized and smaller 
coal-fired Utility Units. However, the trading of allowances is likely 
to involve large Utility Units controlling their emissions more than 
required and selling allowances to smaller Utility Units rather than 
the reverse scenario. This prediction arises from the basic economics 
of capital investment in the utility industry. Under a trading system 
where the firm's access to capital is limited, where the up-front 
capital costs of control equipment are significant, and where emission-
removal effectiveness (measured in percentage of removal) is unrelated 
to plant size, it makes more economic sense for the utility company to 
allocate pollution-prevention capital to its larger facilities than to 
the smaller plants (since more allowances will be earned). Any 
economies of scale of pollution control investment will favor 
investment at the larger plants. Insofar as large coal-fired Utility 
Units tend to be newer and/or better maintained than medium-sized and 
small facilities, it can be expected that companies will favor 
investments in plants with a longer expected lifetime.
    Second, the types of Hg that are deposited locally--Hg\++\ and 
particulate Hg (Hgp)--are controlled by the same equipment 
that controls criteria air pollutants (fine particles, SO2 
and NOX). These same types of Hg are more likely to be 
deposited locally than Hg\0\. As utilities invest in equipment to 
comply with the Agency's new fine particle and ozone control 
regulations (e.g., today's proposed IAQR, and new State Implementation 
Plans (SIP) for fine particles and ozone), the Agency expects a ``co-
benefit'' in Hg control as controls such as particulate controls, 
scrubbers and SCR units are installed on an increasing percentage of 
coal-fired Utility Units. The type of Hg that is most difficult to 
control is Hg\0\, and it is this gaseous form of Hg that is most likely 
to be transported long distances from the Utility Units. Effective 
control of Hg\0\ may require significant investment in Hg-specific 
control technologies that are only beginning to reach the 
commercialization stage.
    Considering the economies of Hg trading, Utility Units that have 
significant emissions of Hg\0\ may become buyers of allowances from 
plants that can cost-effectively control Hg\++\ and Hgp. 
Consequently, the economics of the trading system are likely to favor 
controls of Hg that are likely to be deposited locally, thereby 
reducing any local hot spots.
    The structure of the proposed rule permits States to adopt more 
stringent performance standards if the State determines that such 
regulations are necessary. Although more stringent State regulations 
will reduce flexibility built into the cap-and-trade system, States 
retain the power under the proposed section 111 rule to adopt stricter 
regulations to address local hot spots or other problems. Given the 70 
percent emission reduction in the proposed section 111 rule and our 
experience with cap-and-trade systems, which shows that the largest 
emitters are the first to install stringent emission controls, we do 
not expect any local or regional hot spots. However, the Agency plans 
to continue monitoring Hg emissions and the operation of the

[[Page 4703]]

trading system to make sure that localized hot spots do not 
materialize.
    As part of its analysis of the President's Clear Skies initiative, 
EPA analyzed Hg emissions reductions under a cap-and-trade mechanism. 
In the Clear Skies example, the greatest emissions reductions were 
projected to occur at the electric generating sources with the highest 
Hg emissions. This pattern is similar to that observed in the 
SO2 emissions trading program under the Acid Rain Program. 
Under Clear Skies, compared to a base case of existing programs, ionic 
Hg emissions (those Hg emissions which tend to be deposited locally, 
i.e., within 25 kilometers) from power plants located up to 10 
kilometers from a water body were projected to decrease by over 60 
percent in 2020. In addition, based on regional-scale Hg deposition 
model predictions, Clear Skies could reduce Hg deposition by 5 to 15 
percent beyond the existing program base case across much of the 
eastern U.S. and could do so to higher levels in certain specific 
locations. Based on this available information, the proposed cap-and-
trade mechanism in this regulatory proposal can be expected to reduce 
Hg deposition similarly in most areas. Consequently, the EPA does not 
anticipate significant local health-based concerns under a national Hg 
trading program.
    We explain elsewhere in this proposal our intention to take a hard 
look at the Hg emissions inventory after full implementation of the 
first phase cap. The main purpose of this review is to determine 
whether the actual reductions achieved under this program significantly 
differ from the outcome predicted by our current analysis. We retain 
authority to make adjustments to the program if we find remaining areas 
with heavy, localized emissions and higher health risks (i.e., if we 
find ``hot spots'').
    In the final days before signature and publication of this 
proposal, concerns about the possibility of ``hot spots'' under our 
proposed cap and trade program were widely reported. We agree that this 
is an important issue and believe that our program will effectively 
address potential ``hot spots.'' We ask for comment on this issue. We 
are particularly interested in receiving site-specific data and 
information about locations where commenters believe ``hot spots'' will 
continue to exist after implementation of these rules.
    State adoption of the model rule. Participation in the trading 
program would enable States that have been identified in the proposed 
section 111 rulemaking to achieve the required emissions reductions 
from stationary combustion sources while minimizing the administrative 
burden faced by both States and sources. The SIP-like rule process 
required by the proposed rulemaking would be significantly streamlined 
for States choosing to include the trading program as a part of the 
SIP-like rule. The EPA proposes that adoption of the model rule, to be 
published in a future supplemental notice of proposed rulemaking 
(SNPR), will be considered a SIP-approvable control strategy for the 
proposed section 111 rulemaking. States electing to participate in the 
trading program may either adopt the model rule by reference or develop 
State regulations that are in accordance with the model rule.
    The permitting process under the trading program would be 
significantly streamlined since there will be no need for enforceable 
compliance plans and source-specific requirements (each permit will 
have to be revised to add Hg trading program requirements). Emissions 
monitoring, a central requirement of the trading program, as well as 
the availability to the public of emissions data, allowance data, and 
annual reconciliation information, would ensure that participating 
States and the public have confidence that the required emissions 
reductions are being achieved.
    States that elect to participate in the trading program, thereby 
allowing sources to seek the least-cost reductions, are expected to see 
substantially lower compliance costs for their sources than under a 
comparable rate based program.
    Sources included in the trading program also benefit from increased 
compliance flexibility, as compared to a rate-based approach that 
requires each affected source to comply with an emission rate and 
necessitates installation of control equipment for any affected source 
that cannot meet the limit. Participation in the trading program 
provides sources the choice of numerous compliance strategies. 
Moreover, sources can choose to over-comply and free up excess 
allowances that can be sold on the market or, as discussed below, 
possibly banked for future use. In addition, sources may change their 
control approach at any time without regulatory agency approval.
    The Hg trading program. Brief description of Hg trading program. 
The trading program establishes a first phase cap at a level that 
reflects the Hg reductions expected with the SO2 and 
NOx in the IAQR in 2010 and a Phase II cap of 15 tons on Hg 
emissions for affected Utility Units starting in 2018. The new trading 
program for Hg would require sources to hold allowances covering 
emissions beginning January 1, 2010. The EPA is proposing that the 
owner or operator must hold allowances for all the affected Utility 
Units at a facility at least equal to the total Hg emissions for those 
units during the year. Compliance with the requirement to hold 
allowances will thus be determined on a facility-wide basis. In a 
supplemental notice entitled ``Emission Guidelines and Compliance Times 
for Coal-fired Electric Utility Steam Generating Units'' EPA will be 
proposing unit allocations for existing units. New units will be 
covered under the Hg cap of the trading program and will be required to 
hold allowances. In the SNPR, EPA will recommend options for States to 
address the inclusion of new sources (e.g., new source set asides and/
or updating allocations).
    Applicability. The model trading rule applies to coal-fired 
combustion units serving a generator of more than 25 MW that produces 
electricity for sale. A unit that cogenerates steam and supplies more 
than one-third of its potential electric output capacity and more than 
25 MW electrical output to any utility power distribution system for 
sale shall be considered an Utility Unit.
    State trading budgets. This proposal establishes the total number 
of tons for the Budget Trading Program within a specific State. The 
proposed rule sets the State's unit level allocations and adds up those 
allocations to develop a State level budget.
    In a supplemental notice entitled ``Emission Guidelines and 
Compliance Times for Coal-fired Electric Utility Steam Generating 
Units,'' EPA will be taking comment on the proposed methodology for 
establishing unit level allocations and the data used to develop these 
allocations. As discussed earlier, unit allocations were determined by 
adjusting a baseline heat input. That baseline heat input was 
determined using the average of the three highest heat inputs of the 
period 1998 to 2002. In order to adjust the heat input based on coal 
type, coal usage patterns were determined from the ICR data. The EPA 
requests comment on the data used to develop proposed unit-level 
allocation. The EPA also requests comment on the appropriateness of 
using 1999 data to determine the coal adjustment factors.
    In today's proposal, EPA is proposing a safety valve provision that 
sets a maximum cost for Hg emissions reductions. This provision 
addresses some of the uncertainty associated with the cost of Hg 
control. In fact, there is an ongoing research process sponsored by 
EPA, the DOE, the Electric Power Research Institute (EPRI), and vendors 
specifically aimed at furthering our

[[Page 4704]]

understanding of Hg control, with new data being made available on a 
continuous basis.
    Under the safety valve mechanism, the price of allowances is 
capped, meaning that if the allowance price exceeds the ``safety-
valve,'' sources may borrow allowances from following years to have 
access to more allowances available at that price. The EPA proposes a 
price of $2,187.50 for a Hg allowance (covering one ounce). This price 
will be annually adjusted for inflation. The Administrator will deduct 
corresponding allowances from future facility allowance accounts.
    The purpose of this provision is to minimize unanticipated market 
volatility and provide more market information that industry can rely 
upon for compliance decisions. The safety valve mechanism ensures the 
cost of control does not exceed a certain level, but also ensures that 
emissions reductions are achieved. The future year cap is reduced by 
the borrowed amount, and the emissions reductions are achieved.
    We note that this proposed approach may create implementation 
problems associated with the need to ``reconcile'' at some point in 
time the allowances borrowed from future compliance periods. We ask for 
comment on the need for a safety valve and the viability of our 
proposed approach, and solicit suggestions for other viable approaches.
    We also ask for comment on the possibility of conducting auctions 
each year, at which allowances would be offered for sale. The pool of 
allowances to be auctioned would be created by specified procedures, 
such as setting aside a fixed or incremented percentage of allocations 
each year. The auctions would be open to any person. A person wishing 
to bid for allowances in the auction would submit bids according to 
auction procedures, a bidding schedule, a bidding means, and 
requirements for financial guarantees specified in the regulations. 
Winning bids, and required payments, for allowances would be determined 
in accordance with the regulations. For any winning bid, we would 
record the allowances in a tracking system only after the required 
payment for such allowances is received. If we decide to provide for 
auctions, we would need to determine how to collect and properly 
disperse the revenues. We believe that responsibility for managing this 
aspect of the program would necessarily fall to the individual states 
that opt to participate in the cap and trade program. We ask for 
comment on all aspects of this auctions proposal. If we decide to 
proceed, details of the auction program would be spelled out in the 
upcoming SNPR.
    Key elements of Hg model cap-and-trade rule to be proposed in SNPR. 
Allowance allocations. The EPA is proposing heat input-based 
allocations for existing coal units (with different ratios for 
different coal types).
    The EPA believes that allocating based on heat input data is 
desirable because accurate protocols exist for monitoring this data and 
reporting it to EPA, and several years of certified data are available 
for most of the affected sources.
    New sources will be covered under the Hg cap of the trading program 
and will be required to hold allowances equivalent to the product of 
their NSPS standard and a baseline heat input. Therefore, state budgets 
will be maintained at the levels proposed in today's rulemaking even 
after the addition of new coal-fired electricity generating units in 
the state. State SIP-like rules will need to address the inclusion of 
these new sources in their state budget. In the SNPR, EPA will 
recommend options for states to address the inclusion of new sources 
(e.g., new source set asides and/or updating allocations).
    Allowance management system, compliance, penalties, and banking. 
Each of these elements is part of the accounting system that enables 
the functioning of a trading program. An accurate, efficient accounting 
system is critical to an emissions trading market. Transparency of the 
system, allowing all interested parties access to the information 
contained in the accounting system, increases the accountability of 
regulated sources and contributes to reduced transaction costs of 
trading allowances.
    In order to guarantee the equitable treatment of all affected 
sources across the trading region, the elements included in this 
section need to be incorporated in the same manner in each state that 
participates in trading.
    Allowance management. The EPA intends to propose a model trading 
rule that will be reasonably consistent with the existing allowance 
tracking systems that are currently in use for the Acid Rain Program 
under title IV and the NOX Budget Trading Program under the 
NOX SIP Call. These two systems are called the Allowance 
Tracking System (ATS) and the NOX Allowance Tracking System 
(NATS), respectively. Under the section 111 trading rule, EPA would 
maintain a separate system for Hg, Mercury Allowance Tracking System 
(MATS). The MATS would be established as an automated system used to 
track Hg allowances held by affected units under the Hg cap-and-trade 
program, as well as those allowances held by other organizations or 
individuals. Specifically, MATS would track the allocation of all Hg 
allowances, holdings of Hg allowances in accounts, deduction of Hg 
allowances for compliance purposes, and transfers between accounts. The 
primary role of MATS, in conjunction with an emissions tracking system, 
is to provide an efficient, automated means of monitoring compliance 
with the trading programs. The MATS also provide the allowance market 
with a record of ownership of allowances, dates of allowance transfers, 
buyer and seller information, and the serial numbers of allowances 
transferred.
    Compliance. Compliance in the trading program consists of the 
deduction of allowances from affected facilities'' accounts to offset 
the quantity of emissions at the facilities. The EPA plans to propose 
that compliance be assessed at the facility level, rather than the unit 
level as is currently done in both the Acid Rain and NOX 
Budget trading programs.
    Penalties. The EPA plans to propose a system of automatic penalties 
should a facility not obtain sufficient Hg allowances to offset 
emissions for the compliance period. The automatic penalty provisions 
will not limit the ability of the permitting authority or EPA to take 
enforcement action under State law or the CAA.
    Banking. Banking is the retention of unused allowances from 1 year 
for use in a later calendar year. Banking allows sources to create 
reductions beyond required levels and ``bank'' the unused allowances 
for use later. Generally speaking, banking has several advantages: it 
can encourage earlier or greater reductions than are required from 
sources, stimulate the market and encourage efficiency, and provide 
flexibility in achieving emissions reduction goals. On the other hand, 
it may result in banked allowances being used to allow emissions in a 
given year to exceed the trading program budget. The EPA plans to 
propose that banking of allowances after the start of the Hg trading 
program be allowed with no restrictions.
    Emissions monitoring and reporting. Monitoring and reporting are an 
integral part of any cap-and-trade program. Consistent and accurate 
quantification of emissions ensures each allowance actually represents 
one ounce of emissions and that one ounce of reported emissions from 
one source is equivalent to one ounce of reported emissions from 
another source. This establishes the integrity of the

[[Page 4705]]

allowance (i.e., the authorization to emit one ounce of Hg) and 
instills confidence in the market mechanisms that are designed to 
provide sources with flexibility in achieving compliance. Given the 
variability in the type, operation and fuel mix of sources in the cap-
and-trade program, EPA believes that to ensure this accuracy and 
consistency, emissions must be monitored using continuous emissions 
monitoring methods. As discussed earlier, EPA plans to include in the 
model trading rule a requirement for States to require year-round Part 
75 monitoring and reporting for all sources.
    Accountability for affected sources. Key to the success of existing 
cap-and-trade programs and the integrity of the emission allowance 
trading markets has been clear accountability for a source's emissions. 
This takes the form of affected sources officially designating a 
specific person (and alternate) that is responsible for the official 
certification of all allowance transfers and emissions monitoring and 
reporting as submitted to EPA in quarterly compliance reports. With 
each quarterly submission, this responsible party must certify that: 
(1) the monitoring equipment data were reported in compliance with the 
monitoring and reporting requirements, and (2) the emission and 
operation reports are true, accurate, and complete.
    The trading program to be proposed in the future SNPR will include 
provisions to provide for the same strict standards for source 
accountability established in the Acid Rain Program and the 
NOX SIP call. This will include provisions for the 
establishment and management of an Authorized Account Representative. 
Adoption of these provisions will be required by all States that wish 
to participate in the trading program.
3. What Are the Subpart Da Hg Emission Guidelines?
    This information will be provided in the Emission Guidelines, which 
will be provided in an upcoming supplemental notice.
4. How Did EPA Select the Format for the Proposed Emission Guidelines?
    This information will be provided in the Emission Guidelines, which 
will be provided in an upcoming supplemental notice.
5. How Did EPA Determine the Emissions Monitoring and Reporting 
Requirements for the Proposed Emission Guidelines?
    Monitoring and reporting are an integral part of any Hg reduction 
program, including a cap-and-trade program. Consistent and accurate 
quantification of emissions ensures the integrity of a Hg reduction 
program. The continuous emissions monitoring methods must incorporate 
rigorous quality assurance testing and substitute data provisions for 
times when monitors are unavailable because of planned and unplanned 
outages. In addition, there must be requirements for record keeping and 
electronic reporting. Provisions like these are contained in 40 CFR 
part 75, and are used in both the Acid Rain and NOX SIP Call 
programs, for SO2 and NOX, but not currently for 
Hg.
    In an effort to maintain program integrity, the EPA plans to 
propose revisions to 40 CFR part 75 to establish requirements for 
emission monitoring, quality assurance, substitute data, record 
keeping, and reporting and to include in the SNPR a requirement for 
States to require year-round Part 75 monitoring and reporting for all 
sources. Monitor certification deadlines and other details will be 
specified in the SNPR. The EPA believes that emissions will then be 
consistently and accurately monitored and reported from unit to unit 
and from State to State.
    The EPA also intends to require year-round reporting of emissions 
and monitoring data from each unit at each affected facility. A single 
report for Hg will be required on a quarterly basis in a format 
specified by the EPA. The reports will be required to be in an 
electronic data reporting (EDR) format and must be submitted to EPA 
electronically. The reports will be maintained in EPA's Emissions 
Tracking System (ETS). This centralized reporting requirement is 
necessary to ensure consistent review, checking, and posting of the 
emissions and monitoring data at all affected sources, which 
contributes to the integrity of the Hg reduction program.
6. How Did EPA Determine the Compliance Times for the Proposed Emission 
Guidelines?
    This information will be provided in the Emission Guidelines, which 
will be provided in an upcoming supplemental notice.

E. Rationale for the Proposed Ni Guidelines

1. What Is the Rationale for the Proposed Subpart Da Ni Emission 
Guidelines?
    The proposed emission guidelines for Ni from existing oil-fired 
units was determined by analyzing the emissions data available. The 
data were obtained from the Utility RTC which provided information 
indicating that Ni was the pollutant of concern due to its high level 
of emissions from oil-fired units and the potential health effects 
arising from exposure to it. The EPA examined available test data and 
found that ESP-equipped units can effectively reduce Ni. Analysis of 
the available emissions data indicated that existing oil-fired units 
can limit Ni emissions to 210 lb/TBtu input or 0.002 lb/MWh output 
gross. The EPA is proposing both an input-based and an output-based 
standard in the proposed rule for existing sources (based on potential 
difficulties in retrofitting the necessary data acquisition measures 
for the output-based standard at an existing source).
    The EPA is sensitive to the fact that some sources burn fuels 
containing very little Ni. Therefore, EPA solicits comment on a Ni-in-
oil limit that would be equivalent to the proposed stack values of 210 
lb/TBtu input or 0.002 lb/MWh gross. With a limit on the amount of Ni 
in the oil, an existing source could choose to comply with an alternate 
oil-content-based Ni emission limitation instead of the stack Ni 
emission limit to meet the proposed rule. Such an alternate Ni-in-oil 
limit could be useful where Ni constituent levels are low in the fuel.
    Two alternatives for compliance purposes are provided in the 
proposed rule for oil-fired units. The owner/operator can elect to: (1) 
Meet the standard of performance for Ni, 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.
2. How Did EPA Address Dual-Fired (Oil/Natural Gas) Units?
    The EPA is aware that an oil-fired unit may fire oil at certain 
times of the year and natural gas at other times. The choice of when to 
fire oil or natural gas is usually based on the economics or 
availability of fuel (i.e., seasonal considerations). As stated 
elsewhere in this preamble, EPA considers a unit to be an oil-fired 
unit if (1) it is equipped to fire oil and/or natural gas, and (2) it 
fires oil in amounts greater than or equal to two percent of its annual 
fuel consumption. This two percent value is intended to represent that 
amount of oil that a true natural gas-fired unit might

[[Page 4706]]

use strictly for start-up purposes on an annual basis. The EPA solicits 
comment on whether this two percent breakpoint is a reasonable basis 
for allowing those units that use oil only for startup purposes to be 
exempted from regulation under the proposed rule.

V. Impacts of the Proposed Rule

    Under the section 111 proposed approach, Hg reductions prior to 
2015 are expected to be comparable to Hg reductions achieved under the 
proposed section 112 MACT. In fact, given the early reductions achieved 
from banking under the section 111 proposal, plus the possibility that 
a section 112 MACT approach provides no incentive for power plants to 
reduce below the required level, a section 111 approach will likely 
lead to greater reductions in the Hg relative to the proposed section 
112 MACT approach. After 2015, the Phase II cap in the proposed section 
111 approach is reduced to 15 tpy, leading to still more reductions 
than achieved under the proposed section 112 MACT. Therefore, the 
estimated benefits of the proposed section 112 MACT can serve as a 
lower bound of the benefits achieved through the proposed section 111 
approach.

A. What Are the Air Impacts?

    When the emissions rates developed in today's proposed section 112 
MACT rule are applied to current coal use (based on the ICR), annual Hg 
emissions to the atmosphere from Utility Units are projected to be 34 
tons. Consistent with previous regulatory programs affecting 
electricity generating units, EPA has analyzed this scenario using the 
Integrated Planning Model (IPM) (see http://www.epa.gov/airmarkets/epa-ipm). Based on this model, total Hg emissions from affected coal-fired 
power plants are projected to be 30 tons in 2010 and 31 tons in 2020. 
However, Hg emissions are likely to be much closer to the calculated 
level of 34 tons. First, the model allows for Hg reductions using ACI 
only at the 60 percent and 90 percent levels (rather than using a range 
of 60 to 90 percent), which may lead the model to understate Hg 
emissions from as much as 2.3 tons by bituminous-fired units. Second, 
the modeling may not fully capture the range of Hg in different coal 
ranks which could underestimate emissions, particularly when modeling a 
facility-specific limit as is the case with this analysis. The modeling 
assumes a range of Hg contents for different ranks of coal, but due to 
averaging, may not fully capture all Hg contents of coal. (See IPM 
documentation, Chapter 4 for further information on Hg content of 
coal.)

B. What Are the Water and Solid Waste Impacts?

    The EPA estimated the additional water usage that would result from 
the MACT floor level of control to be 307 million gallons per year for 
existing affected sources. These costs are accounted for in the control 
costs estimates.
    The EPA estimated the additional solid waste that would result from 
the MACT floor level of control to be 282,000 tpy for existing sources. 
The costs of handling the additional solid waste generated are also 
accounted for in the control costs estimates.
    A discussion of the methodology used to estimate impacts is 
presented in the memorandum entitled ``Methodology for Estimating Cost 
and Emissions Impact for Coal- and Oil-Fired Electric Utility Steam 
Generating Units National Emission Standards for Hazardous Air 
Pollutants'' in the docket.

C. What Are the Energy Impacts?

    The EPA expects an increase of approximately 1,418 million kilowatt 
hours (kWh) in national annual energy usage as a result of the proposed 
rule. The increase results from the electricity required by existing 
sources to operate control devices installed to meet the proposed rule.

D. What Are the Control Costs?

    Table 6 of this preamble shows the estimated capital and annual 
cost impacts for each subcategory. Costs include testing and monitoring 
costs, but not record keeping and reporting costs.

 Table 6.--Summary of Capital and Annual Costs for New and Existing Sources Under the Section 112 MACT Proposal
----------------------------------------------------------------------------------------------------------------
                                                                            Estimated/
                                                                            projected    Annualized    Capital
                 Source                             Subcategory               No. of    cost (106$/     costs
                                                                             affected       yr)         (106$)
                                                                              units
----------------------------------------------------------------------------------------------------------------
Coal-fired Units........................  Bituminous-fired...............          549          728        4,609
                                          Subbituminous-fired............           68           92          607
                                          Lignite-fired..................            5            9           61
                                          Blends.........................           74          101          654
                                          IGCC unit......................            0            0            0
                                          Coal refuse-fired..............            3           16           52
                                                                          --------------
Total, coal-fired units.................  ...............................          719          945        5,982
Oil-fired Units.........................  Oil-fired......................          186          417        2,190
                                         ----------------------------------
Total, coal- and oil-fired units........  ...............................          905        1,362        8,172
----------------------------------------------------------------------------------------------------------------

    Costs are estimated from methods based on the ``EPA Air Pollution 
Control Cost Manual,'' which uses a factor method for estimating total 
capital investment, then total annual and annualized costs for an 
emission control system. Basic equipment costs are found either from 
the Manual or from vendor contacts. Factors in the manual are applied 
to the equipment cost to estimate direct and indirect costs associated 
with installing the equipment. Annual operating and maintenance costs 
and annualized costs for debt service are estimated to obtain annual 
payments attributable to the system used for emission control. For 
electric utility costing, each of the U.S. units is costed separately 
using equations developed from the cost manual. A discussion of the 
methodology used to estimate impacts is presented in the memorandum 
entitled ``Methodology for Estimating Cost and Emissions Impact for 
Coal- and Oil-Fired Electric Utility Steam Generating Units National 
Emission Standards for Hazardous Air Pollutants'' in the docket.

[[Page 4707]]

    As part of the costing, annual quantities of water, wastewater, 
solid waste, and energy required for operating the emission control 
systems are determined. These quantities represent materials or energy 
used in the system or wastes that must be treated as a result of system 
operation. The quantities are listed elsewhere in this preamble.

E. Can We Achieve the Goals of the Proposed Section 112 MACT Rule in a 
Less Costly Manner?

    The EPA has tried in developing the section 112 MACT proposal to 
ensure that the cost to the regulated community is reasonable in view 
of the potential benefits, and to allow maximum flexibility in 
compliance options consistent with our statutory obligations. The 
Agency recognizes, however, that the section 112 MACT proposal may 
still require some facilities to take costly steps to further control 
Hg and Ni emissions even though those emissions may not result in 
exposures which could pose unacceptable risk. The EPA is, therefore, 
specifically soliciting comment on whether there are further ways to 
structure the section 112 MACT proposal to focus on the facilities 
which may pose significant risks to public health and avoid the 
imposition of high costs on facilities that pose little risk to public 
health and the environment.

F. What Are the Social Costs and Benefits of the Proposed Section 112 
MACT Rule?

    The proposed rule sets out two major alternative actions. The first 
alternative would regulate Hg emissions under the section 112 MACT 
provisions CAA. The second alternative would regulate Hg emissions 
through a cap-and-trade program under section 111 of the CAA. 
Implementation of the section 111 cap-and-trade program would be 
carried out in coordination with a cap-and-trade program for 
SO2 and NOX emissions under the IAQR, which is 
also being proposed in today's Federal Register. The IAQR would limit 
Utility Unit SO2 and NOX emissions in 
approximately 30 eastern states to address their contribution to 
nonattainment of the fine particle (PM2.5) and ozone 
National Ambient Air Quality Standards (NAAQS).
    The control approaches adopted by Utility Units in response to the 
proposed section 112 Hg MACT regulations would also achieve collateral 
reductions of NOX and SO2. Based on the scenario 
analyzed, the proposed action would reduce approximately 902,000 tons 
of NOX emissions, and 591,000 tons of SO2 
emissions in 2010. The proposed IAQR would require annual 
SO2 emissions reductions of 3.6 million tons and 
NOX emissions reductions of 1.4 million tons in 2010, while 
achieving Hg reductions comparable to those estimated for the proposed 
section 112 MACT by 2010.
    Our assessment of costs and benefits of the proposed MACT rule is 
detailed in the ``Benefits Analysis for the Section 112 Utility Rule,'' 
located in the Docket. These analyses are based on the costs and 
emissions reductions associated with a particular Hg control scenario 
that is consistent with the reduction in nationwide Hg emissions 
expected by implementation of the proposed section 112 MACT standard. 
The specific emissions control scenario is derived from application of 
the Integrated Planning Model (IPM), which EPA has used to assess the 
costs and emissions reductions associated with a number of regulations 
of the power sector. While the Hg reduction estimates in the scenario 
are consistent with the Agency's assessment of control technologies, 
EPA is aware that estimates of associated reductions in other 
pollutants, notably SO2 and NOX (co-benefits) may 
vary significantly with alternative assumptions about the application 
of particular control technologies and incentives created by the 
existence of other major regulatory programs affecting the power 
sector. In particular, based on past EPA analyses of multi-pollutant 
strategies (e.g. Clear Skies Technical Support Document D, http://www.epa.gov/clearskies/ technical.html) the control choices made 
pursuant to either a 111-or 112-based Hg program would likely be 
significantly affected by the requirements of the IAQR. For these 
reasons, in addition to the findings of the analyses derived from the 
MACT-only scenario, we also provide some estimates of the direction of 
costs and benefits under reasonably foreseeable alternative scenarios 
for implementing limits on Hg emissions that take such potential 
interactions into account.
    The proposed section 111 and 112 actions address Hg and Ni 
emissions from coal- and oil-fired Utility Units. Exposure to emissions 
of Hg at low levels may cause neurological damage and learning 
disorders. Nickel subsulfide and refinery dusts are classified as known 
human carcinogens; Ni carbonyl is classified as a probable human 
carcinogen based upon studies in animals. Due to the control 
technologies selected for analysis, the actions to reduce Hg will also 
achieve reductions of NOX and SO2. Although not 
incorporated into the analyses, the actions to reduce Ni will also 
reduce direct emissions of particulate matter. Known health and welfare 
effects associated with the pollutants affected by the proposed rule 
are listed in Table 7 of this preamble. As indicated in the table, we 
are able to quantify and monetize only a portion of these effects.

        TABLE 7.--Health and Welfare Effects of Pollutants Affected by the Proposed Utility MACT Standard
----------------------------------------------------------------------------------------------------------------
          Pollutant/effect                  Quantified and monetized                Unquantified effects
----------------------------------------------------------------------------------------------------------------
PM/Health..........................  Premature mortality--adults..........  Low birth weight.
                                     Premature mortality--infants.........  Changes in pulmonary function.
                                     Bronchitis--chronic and acute........  Chronic respiratory diseases other
                                     Hospital admissions--respiratory and    than chronic bronchitis.
                                      cardiovascular.                       Morphological changes.
                                     Emergency room visits for asthma.....  Altered host defense mechanisms.
                                     Non-fatal heart attacks (myocardial    Non-asthma respiratory emergency
                                      infarction).                           room visits.
                                     Lower and upper respiratory illness..  Changes in cardiac function (e.g.,
                                     Asthma exacerbations.................   heart rate variability).
                                     Minor restricted activity days.......  Allergic responses (to diesel
                                     Work loss days.......................   exhaust).
PM/Welfare.........................  .....................................  Visibility in Class I areas.
                                                                            Visibility in residential and non-
                                                                             Class I areas.
                                                                            Household soiling.
Ozone/Health.......................  .....................................  Increased airway responsiveness to
                                                                             stimuli.
                                                                            Inflammation in the lung.
                                                                            Chronic respiratory damage.
                                                                            Premature aging of the lungs.

[[Page 4708]]

 
                                                                            Acute inflammation and respiratory
                                                                             cell damage.
                                                                            Increased susceptibility to
                                                                             respiratory infection.
                                                                            Non-asthma respiratory emergency
                                                                             room visits.
                                                                            Hospital admissions--respiratory.
                                                                            Emergency room visits for asthma.
                                                                            Minor restricted activity days.
                                                                            School loss days.
                                                                            Asthma attacks.
                                                                            Cardiovascular emergency room
                                                                             visits.
                                                                            Premature mortality B acute
                                                                             exposures.
                                                                            Acute respiratory symptoms.
Ozone/Welfare......................  .....................................  Decreased commercial forest
                                                                             productivity.
                                                                            Decreased yields for fruits and
                                                                             vegetables.
                                                                            Decreased yields for commercial and
                                                                             non-commercial crops.
                                                                            Damage to urban ornamental plants.
                                                                            Impacts on recreational demand from
                                                                             damaged forest aesthetics.
                                                                            Damage to ecosystem functions.
                                                                            Decreased outdoor worker
                                                                             productivity.
Nitrogen and Sulfate Deposition/     .....................................  Costs of nitrogen controls to reduce
 Welfare.                                                                    eutrophication in selected eastern
                                                                             estuaries.
                                                                            Impacts of acidic sulfate and
                                                                             nitrate deposition on commercial
                                                                             forests.
                                                                            Impacts of acidic deposition on
                                                                             commercial freshwater fishing.
                                                                            Impacts of acidic deposition on
                                                                             recreation in terrestrial
                                                                             ecosystems.
                                                                            Impacts of nitrogen deposition on
                                                                             commercial fishing, agriculture,
                                                                             and forests.
                                                                            Impacts of nitrogen deposition on
                                                                             recreation in estuarine ecosystems.
                                                                            Reduced existence values for
                                                                             currently healthy ecosystems.
SO2/Health.........................  .....................................  Hospital admissions for respiratory
                                                                             and cardiac diseases.
                                                                            Respiratory symptoms in asthmatics.
NOX/Health.........................  .....................................  Lung irritation.
                                                                            Lowered resistance to respiratory
                                                                             infection.
                                                                            Hospital Admissions for respiratory
                                                                             and cardiac diseases.
Hg Health..........................  .....................................  Neurological disorders.
                                                                            Learning disabilities.
                                                                            Developmental delays.
                                                                            Cardiovascular effects*.
                                                                            Altered blood pressure regulation*.
                                                                            Increased heart rate variability*.
                                                                            Myocardial infarctions*.
                                                                            Reproductive effects in adults*.
Hg Deposition Welfare..............  .....................................  Impacts on birds and mammals (e.g.
                                                                             reproductive effects).
                                                                            Impacts to commercial, subsistence,
                                                                             and recreational fishing.
                                                                            Reduced existence values for
                                                                             currently healthy ecosystems.
Ni Health..........................  .....................................  Dermatitis.
                                                                            Respiratory effects.
                                                                            Increased Risk of Lung and Nasal
                                                                             cancer.
----------------------------------------------------------------------------------------------------------------
* These are potential effects as the literature is either contradictory or incomplete.

    It is estimated that the section 112 MACT proposal will reduce 
national Hg emissions to approximately 34 tons and national Ni 
emissions to approximately 103 tons at electric utility facilities that 
generate steam using fossil fuels (i.e., coal or oil fuels). The health 
effects associated with these pollutants are discussed earlier in this 
preamble, however, a summary of the potential benefits is provided 
below. While it is beneficial to society to reduce Hg and Ni, we are 
unable to quantify and provide a monetized estimate of the benefits at 
this time due to gaps in available information on the fate of emissions 
for these two pollutants, human exposure, and health impact models.
    The Hg and Ni emissions reductions associated with implementing of 
the proposed action would produce a

[[Page 4709]]

variety of benefits. Mercury emitted from utilities and other natural 
and man-made sources is carried by winds through the air and eventually 
is deposited to water and land. In water, Hg is transformed to 
methylmercury through biological processes. Methylmercury, a highly 
toxic form of Hg, is the form of Hg of greatest concern for the purpose 
of this rulemaking. Once Hg has been transformed into methylmercury, it 
can be ingested by the lower trophic level organisms where it can 
bioaccumulate in fish tissue (i.e., concentrations in predatory fish 
build up over the fish's entire lifetime, accumulating in the fish 
tissue as predatory fish consume other species in the food chain). 
Thus, fish and wildlife at the top of the food chain can have Hg 
concentrations that are higher than the lower species, and they can 
have concentrations of Hg that are higher than the concentration found 
in the water body itself. Therefore, the most common form of exposure 
to Hg for humans and wildlife is through the consumption of 
contaminated predatory fish, such as: Commercially consumed tuna, 
shark, or other saltwater fish species and recreationally caught bass, 
perch, walleye or other freshwater fish species. When humans consume 
fish contaminated with methylmercury, the ingested methylmercury is 
almost completely absorbed into the blood and distributed to all 
tissues (including the brain); it also readily passes through the 
placenta to the fetus and fetal brain.
    Based on the findings of the National Research Council, EPA has 
concluded that benefits of Hg reductions would be most apparent at the 
human consumption stage, as consumption of fish is the major source of 
exposure to methylmercury. At lower levels, documented Hg exposure 
effects may include more subtle, yet potentially important, 
neurodevelopmental effects.
    Some subpopulations in the U.S., such as: Native Americans, 
Southeast Asian Americans, and lower income subsistence fishers, may 
rely on fish as a primary source of nutrition and/or for cultural 
practices. Therefore, they consume larger amounts of fish than the 
general population and may be at a greater risk to the adverse health 
effects from Hg due to increased exposure. In pregnant women, 
methylmercury can be passed on to the developing fetus, and at 
sufficient exposure may lead to a number of neurological disorders in 
children. Thus, children who are exposed to low concentrations of 
methylmercury prenatally may be at increased risk of poor performance 
on neurobehavioral tests, such as those measuring attention, fine motor 
function, language skills, visual-spatial abilities (like drawing), and 
verbal memory. The effects from prenatal exposure can occur even at 
doses that do not result in effects in the mother. Mercury may also 
affect young children who consume fish contaminated with Hg. 
Consumption by children may lead to neurological disorders and 
developmental problems, which may lead to later economic consequences.
    In response to potential risks of consuming fish containing 
elevated concentrations of Hg, EPA and FDA have issued fish consumption 
advisories which provide recommended limits on consumption of certain 
fish species for different populations. The EPA and FDA are currently 
developing a joint advisory that has been released in draft form. This 
newest draft FDA-EPA fish advisory recommends that women and young 
children reduce the risks of Hg consumption in their diet by moderating 
their fish consumption, diversifying the types of fish they consume, 
and by checking any local advisories that may exist for local rivers 
and streams. This collaborative FDA-EPA effort will greatly assist in 
educating the most susceptible populations. Additionally, the 
reductions of Hg from this regulation may potentially lead to fewer 
fish consumption advisories, which will benefit the fishing community.
    Reducing emissions of Ni can also contribute to several benefits. 
We are concerned with the inhalation risks of Ni as the primary route 
of human exposure in this rulemaking. Nickel is found in ambient air at 
very low levels as a result of releases from oil combustion. The 
differing forms of Ni have varying levels of toxicity. There is great 
uncertainty about the type of Ni emitted. Respiratory effects have also 
been reported in humans who have been occupationally exposed to high 
levels of Ni. Human and animal studies have reported an increased risk 
of lung and nasal cancers from exposure to Ni refinery dusts and Ni 
subsulfide. Animal studies of soluble Ni compounds (i.e., Ni carbonyl) 
have reported lung tumors. The EPA has classified Ni refinery 
subsulfide as a Group A carcinogen due to lung and nasal cancers in 
humans occupationally exposed to Ni refinery dust. Ni carbonyl is 
classified as a Group B2, probable human carcinogen based upon studies 
conducted in animals.
    The proposed actions would also reduce NOX and 
SO2 emissions that contribute to the formation of fine 
particles (PM2.5). In general, exposure to high 
concentrations of PM2.5 may aggravate existing respiratory 
and cardiovascular disease including asthma, bronchitis and emphysema, 
especially in children and the elderly. Nitrogen oxides and 
SO2 are also contributors to acid deposition, or acid rain, 
which causes acidification of lakes and streams and can damage trees, 
crops, historic buildings and statues. Exposure to PM2.5 can 
lead to decreased lung function, and alterations in lung tissue and 
structure and in respiratory tract defense mechanisms which may then 
lead to, increased respiratory symptoms and disease, or in more severe 
cases, premature death or increased hospital admissions and emergency 
room visits. Children, the elderly, and people with cardiopulmonary 
disease, such as asthma, are most at risk from these health effects. 
Fine PM can also form a haze that reduces the visibility of scenic 
areas, can cause acidification of water bodies, and have other impacts 
on soil, plants, and materials.
    As previously stated, the control technologies selected for 
analysis of the Hg portion of this action would also achieve reductions 
of NOX and SO2. Based on the scenario analyzed, 
the proposed section 112 MACT action would reduce approximately 902,000 
tons of NOX emissions, and 591,000 tons of SO2 
emissions. These projected reductions are due to the reliance on some 
SO2 and NOX controls and coal-switching to 
achieve Hg reductions. When compared to the base case, there is a 
projected shift towards lower sulfur bituminous coals (about 6 percent) 
that are also lower in Hg, which results in SO2 emissions 
reductions. In addition, some units are projected to use SO2 
controls (scrubbers) to comply with the proposed section 112 MACT 
(about 1 GW), as well as generation shifts (about 1 percent) from 
uncontrolled units to units with scrubbers which would result in 
additional SO2 reductions from the base case. Projected 
NOX emissions reductions from the base case are a result of 
seasonal NOX controls being operated annually in the MACT 
case to achieve additional Hg control (about 90 GW of SCR operate 
annually). Because NOX and SO2 contribute to the 
formation of PM2.5, and because direct PM controls would be 
applied to meet the Ni requirements, these standards should lead to 
substantial benefits from reductions of ambient PM. Therefore, 
reduction of SO2 and NOX emissions from utilities 
will contribute to reduced human health and welfare impacts.
    Due to both technical and resource limits in available modeling, we 
have only been able to quantify and monetize the benefits for a few of 
the endpoints associated with reducing Hg, Ni, directly emitted PM, and 
gaseous NOX

[[Page 4710]]

and SO2. However, based on relevant available modeling of 
several alternative control strategies to reduce Utility Unit 
SO2 and NOX emissions (including Clear Skies), we 
can approximate the benefits of reduced exposure to ambient PM 
resulting from reductions in precursor emissions of NOX and 
SO2. These benefit categories--including reductions in 
premature mortality--are believed to represent a dominant fraction of 
the total benefits associated with these proposed actions.
    To quantify benefits, we evaluated PM-related health effects 
(including SO2 and NOX contributions to ambient 
concentrations of PM2.5). Our approach requires the 
estimation of changes in air quality expected from the rule and the 
resulting effects on health. In order to characterize the benefits of 
today's proposed section 112 action, given the constraints on time and 
resources available for the analysis, we adopted a benefits transfer 
technique that relies on air quality and benefits modeling conducted 
for the recently proposed Clear Skies Act of 2003. Results from the 
Clear Skies analysis in 2010 are then scaled and transferred to the 
emission reductions expected from the proposed section 112 MACT rule.
    This benefits assessment is conducted in two phases. First, using 
modeling runs developed in support of the Clear Skies legislation, we 
estimated the number of reduced incidences of illnesses, 
hospitalizations, and premature fatalities associated with a unit 
change in ambient concentrations of PM2.5. The Clear Skies 
program covers a similar universe of affected sources and yields larger 
reductions in NOX and SO2 emissions. The 
distribution of emission reductions across states differs between the 
two analyses, especially in the Western U.S. Given the very small 
reductions in NOX and SO2 expected to occur in 
the Western U.S. as a result of the rule and the potential for errors 
in transferring benefits, we limit the benefits analysis to the Eastern 
U.S., and derive the benefits transfer factors from the Eastern U.S. 
Clear Skies benefits results only. Recognizing the differences in 
emission reduction patterns in the Eastern U.S. between the Clear Skies 
analysis and the current proposed MACT standards, we believe that the 
benefits per ton of SO2 and NOX estimated for the 
Clear Skies analysis represents a reasonable approximation of the 
benefits per ton that might be realized from the reductions in 
NOX and SO2 expected under the current proposed 
section 112 rule. The analysis of the proposed section 112 MACT 
includes only health benefits related to PM2.5 reductions 
associated with the NOX and SO2 reductions, and 
does not include health benefits related to ozone reductions, 
visibility benefits, and other benefits including reduced nitrogen 
deposition and acidification. For the most part, quantifiable ozone 
benefits do not contribute significantly to the monetized benefits: 
thus, their omission does not materially affect the magnitude of 
estimated benefits. Visibility benefits may be more significant; 
although, visibility has generally contributed only a few percent of 
total monetized benefits.
    Second, we used the Clear Skies analysis to develop a relationship 
between changes in ambient PM2.5 concentrations and the 
underlying NOX and SO2 emission reductions to 
reflect differences in emissions reductions between the modeled Clear 
Skies scenario and the proposed standard. The sum of the scaled 
benefits for the SO2 and NOX emission reductions 
provide us with the total benefits of the rule.
    The benefit estimates derived from the Clear Skies air quality 
modeling in the first phase of our analysis uses an analytical 
structure and sequence similar to that used in the benefits analyses 
for the proposed Nonroad Diesel rule and proposed IAQR and in the 
``section 812 studies'' analysis of the total benefits and costs of the 
Clean Air Act. We used many of the same models and assumptions used in 
the Nonroad Diesel and IAQR analyses as well as other Regulatory Impact 
Analyses (RIAs) prepared by the Office of Air and Radiation. By 
adopting the major design elements, models, and assumptions developed 
for the section 812 studies and other RIAs, we have largely relied on 
methods which have already received extensive review by the independent 
Science Advisory Board (SAB), the National Academies of Sciences, by 
the public, and by other federal agencies. Interested parties will be 
able to obtain further information from the section 812 study on the 
kinds of methods we are likely to use for estimating benefits and costs 
in the final rule.
    The benefits transfer method used in the second phase of the 
analysis is similar to that used to estimate benefits in the recent 
analysis of the proposed Nonroad Diesel rule and Nonroad Large Spark-
Ignition Engines and Recreational Engines standards (67 FR 68241, 
November 8, 2002). A similar method has also been used in recent 
benefits analyses for the proposed Industrial Boilers and Process 
Heaters NESHAP and the Reciprocating Internal Combustion Engines 
NESHAP.
    The economic and energy impact analysis memo (for the proposed 
section 112 MACT) details the control scenario as consisting of a 
combination of direct Hg controls and additional SO2 and 
NOX controls. Under this scenario, the extent of 
SO2 and NOX controls in Eastern U.S. would be 
limited to approximately 902,000 tons of NOX and 591,000 
tons of SO2. As outlined above, these reductions drive the 
monetized benefits of the proposed rule, which would be approximately 
$15 billion (1999$). This economic benefit is associated with 
approximately 2,200 avoided premature mortalities, 1,200 avoided cases 
of chronic bronchitis, 2,900 avoided non-fatal heart attacks, thousands 
of avoided hospital and emergency room visits for respiratory and 
cardiovascular diseases, tens of thousands of avoided days with 
respiratory symptoms, and millions of avoided work loss and restricted 
activity days. The EPA recognizes that at the present time, these 
direct controls have not been adequately demonstrated, so this scenario 
reflects uncertain but possible advances in the availability of such 
controls. Under a more restrictive assumption about the availability of 
direct Hg controls (e.g., ACI) than used in this analysis, Utility Unit 
control strategies may rely to an even greater extent on 
SO2, NOX, and direct PM control approaches to 
reduce Hg. In such an alternative MACT-only scenario, projected costs 
and benefits would be correspondingly much greater than those indicated 
in Table 8 of this preamble.
    As noted above, however, consideration of the proposed section 112 
MACT or proposed section 111 only scenarios does not capture the full 
dimension of the most likely air regulatory situation facing the power 
industry over the next decade. As noted above, EPA is also proposing 
significant additional SO2 and NOX reduction 
requirements to limit interstate transport of these pollutants. These 
requirements are likely to require Utility Units to install 
SO2 and NOX controls on significant fractions of 
their coal-fired capacity. For these reasons, there are strong public 
policy reasons to consider the combined influence of the Hg and IAQR 
requirements.
    Table 8 of this preamble summarizes the results of the benefit-cost 
analysis of the proposed section 112 MACT scenario and compares them 
with estimates of the range of potential costs and benefits associated 
with an alternative scenario that addresses combined implementation of 
section 111 Hg requirements in coordination with proposed 
SO2 and NOX

[[Page 4711]]

requirements in the proposed IAQR. The potential influence of such a 
combined scenario is illustrated in the second column of Table 8 of 
this preamble, which assumes the proposed section 111 requirements are 
implemented in combination with the IAQR. The IAQR analysis projects 
that the Hg reductions associated with implementing the SO2/
NOX requirements in the Eastern U.S. in 2010 would be 
approximately 10.6 tons per year, which is almost identical to those 
estimated from the proposed section 112 MACT-only scenario.
    If the goal for the proposed section 111 program in 2010 is limited 
to these co-control reductions, there might be no additional costs or 
benefits to the program, over those achieved by the IAQR--this is 
indicated in the lower portion of the ranges in Table 8 of this 
preamble. By contrast, if the proposed section 111 regulation adopts a 
2010 goal similar to the Phase I Clear Skies Hg cap, additional Hg 
reductions would be required over those forecast for the IAQR. Based on 
a multipollutant analyses conducted for Clear Skies (p D-9, Technical 
appendix D, at http://www.epa.gov/airmarkets/epa-ipm), power generators 
would likely opt for some additional SO2 and NOX 
controls beyond those needed for the IAQR, as well as considering 
additional direct Hg controls. Although the actual results are 
uncertain, the Clear Skies results suggest that the costs and benefits 
associated with a section 112 MACT-only approach may reflect a 
reasonable lower bound for the additional costs and benefits. These 
potential additional costs and benefits related to additional Hg 
controls are reflected in the upper end of the ranges in Table 8 of 
this preamble. In the decade beyond 2010, the proposed section 111 
program would establish a 15 ton cap for Hg in 2018, similar to Clear 
Skies. Based on Clear Skies analyses, this would result in further Hg 
controls, which would likely include at least some additional 
SO2/NOX controls as well as direct Hg controls. 
The IAQR program alone produces only small additional reductions in Hg 
emissions in 2020. The Hg reductions estimated for the proposed section 
112 MACT and the proposed section 111 and proposed IAQR programs are 
summarized in Table 9. These forecasts are based on IPM analyses of the 
proposed section 112 MACT scenario outlined above, the proposed IAQR 
analysis, and estimates derived from earlier analyses of the Clear 
Skies program.
    Every benefit-cost analysis examining the potential effects of a 
change in environmental protection requirements is limited, to some 
extent, by data gaps, limitations in model capabilities (such as 
geographic coverage), and uncertainties in the underlying scientific 
and economic studies used to configure the benefit and cost models. 
Deficiencies in the scientific literature often result in the inability 
to estimate changes in health and environmental effects. Deficiencies 
in the economics literature often result in the inability to assign 
economic values even to those health and environmental outcomes that 
can be quantified. While these general uncertainties in the underlying 
scientific and economics literatures are discussed in detail in the RIA 
and its supporting documents and references, the key uncertainties 
which have a bearing on the results of the benefit-cost analysis of 
today's action are the following:
    1. The exclusion of potentially significant benefit categories 
(e.g., health and ecological benefits of reduction in hazardous air 
pollutants emissions);
    2. Errors in measurement and projection for variables such as 
population growth;
    3. Uncertainties in the estimation of future year emissions 
inventories and air quality;
    4. Uncertainties associated with the extrapolation of air quality 
monitoring data to some unmonitored areas required to better capture 
the effects of the standards on the affected population;
    5. Variability in the estimated relationships of health and welfare 
effects to changes in pollutant concentrations; and
    6. Uncertainties associated with the benefit transfer approach.
    Despite these uncertainties, we believe the benefit-cost analysis 
provides a reasonable indication of the expected economic benefits of 
the proposed actions under a given set of assumptions.
    Based on estimated compliance costs (control + administrative costs 
associated with Paperwork Reduction Act requirements associated with 
the proposed rule and predicted changes in the price and output of 
electricity), the estimated social costs of the proposed section 112 
MACT-only scenario are $1.6 billion (1999$). Social costs are different 
from compliance costs in that social costs take into account the 
interactions between affected producers and the consumers of affected 
products in response to the imposition of the compliance costs. In this 
action, coal-fired utilities are the affected producers and users of 
electricity are the consumers of the affected product.
    As explained above, we estimate $15 billion in benefits from the 
proposed section 112 MACT, compared to less than $2 billion in costs. 
It is important to put the results of this analysis in the proper 
context. The large benefit estimate is not attributable to reducing 
human and environmental exposure to Hg. It arises from ancillary 
reductions in SO2 and NOX that result from 
controls aimed at complying with the proposed MACT. Although 
consideration of ancillary benefits is reasonable, we note that these 
benefits are not uniquely attributable to Hg regulation. Under the 
IAQR, coal-fired units would achieve much larger reductions in 
SO2 and NOX emissions than they would under the 
proposed section 112 MACT. In the years ahead, as the Agency and the 
States develop rules, guidance and policies to implement the new air 
quality standards for ozone and PM, coal-fired power plants will be 
required to implement additional controls to reduce SO2 and 
NOX (e.g., scrubbers, SCR units, year-round NOX 
controls in place of summertime only controls, conversion to low-sulfur 
coals, and so forth). Thus, most or all of the ancillary benefits of Hg 
control would be achieved anyway, regardless of whether a section 112 
MACT is promulgated. Based on analysis of the Clear Skies legislation, 
EPA believes that the proposed 2018 Hg cap in the proposed section 111 
rule would result in additional SO2 and NOX 
reductions beyond those that would be required under the proposed IAQR. 
Thus, the section 111 approach, unlike the section 112 approach, may 
achieve SO2 and NOX reduction benefits beyond 
those that would be achieved under the IAQR. We believe, however, that 
even if no Hg controls were imposed, most major coal-fired units would 
still have to reduce their SO2 and NOX emissions 
as part of the efforts to bring the nation into attainment with the new 
air quality standards. In light of these considerations, the Agency 
believes that the key rationale for controlling Hg is to reduce public 
and environmental exposure to Hg, thereby reducing risk to public 
health and wildlife. Although the available science does not support 
quantification of these benefits at this time, the Agency believes the 
qualitative benefits are large enough to justify substantial investment 
in Hg emission reductions.
    It should be recognized, however, that this analysis does not 
account for many of the potential benefits that may result from these 
actions. The net benefits would be greater if all the benefits of the 
Hg, Ni, and other pollutant reductions

[[Page 4712]]

could be quantified. Notable omissions to the net benefits include all 
benefits of HAP reductions, including reduced cancer incidences, toxic 
morbidity effects, and cardiovascular and CNS effects, and all health 
and welfare effects from reduction of ambient NOX and 
SO2.

 Table 8.--Summary of Monetized Benefits, Costs, and Net Benefits of the Proposed Section 112 MACT Standard, \1\
 With a Range for Potential Alternative Scenario Estimates for MACT and Section III Proposal in 2010 ($billions/
                                                       yr)
----------------------------------------------------------------------------------------------------------------
                                                           MACT-only
                                                            Scenario          Sec. 111 plus IAQR Combined\4\
----------------------------------------------------------------------------------------------------------------
Social Costs\2\.......................................             $1.6  $2.9 to 4.5+
Social Benefits\3\:                                     ...............  .......................................
    PM-related Health benefits........................            $15+B  $58 to 73+B
Net Benefits (Benefits-Costs)\3\......................            $13+B  $55 to $68+B
----------------------------------------------------------------------------------------------------------------
\1\All costs and benefits are rounded to two significant digits.
\2\Note that costs are the total costs of reducing all pollutants, including Hg and other metallic air toxics,
  as well as NOX and SO2 reductions. Benefits in this table are associated only with NOX and SO2.
\3\Not all possible benefits or disbenefits are quantified and monetized in this analysis. In particular, ozone
  health and welfare and PM welfare benefits are omitted. Other potential benefit categories that have not been
  quantified and monetized are listed in Table 5. B is the sum of all unquantified benefits and disbenefits.
\4\Estimated combined benefits of S. 111 plus IAQR costs and benefits in 2010. Ranges do not reflect actual
  analyses of combined programs. Rough estimates based on consideration of available IAQR, MACT, and Clear Skies
  analyses. See text.


   Table 9.--Forecast Mercury Emissions Under the Proposed Section 112
    MACT, and the Proposed Section 111 Rule and the Proposed IAQR\1\
------------------------------------------------------------------------
                     Program/Year                         2010     2020
------------------------------------------------------------------------
MACT only.............................................       34       31
IAQR only.............................................       34       30
IAQR and section 111 caps.............................    \(2)\   18-22
------------------------------------------------------------------------
\1\ Annual reductions from base case forecast under current programs to
  reduce Utility Unit emissions. MACT only value for 2015 based on
  interpolation of 2010 and 2015. Lower bound of IAQR and section 111
  caps in 2010 assumes Hg cap is set at co-control level achieved by
  IAQR. Upper bound in 2010 and ranges thereafter estimates derived from
  Clear Skies analyses.
\2\ Mercury emissions will reflect the level of emissions resulting from
  the co-benefits of controlling SO2 and NOX. See section IV.B.1 for a
  detailed discussion.

VI. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

    Under Executive Order 12866 (58 FR 51735, October 4, 1993), EPA 
must determine whether a regulatory action is ``significant'' and, 
therefore, subject to review by the Office of Management and Budget 
(OMB) and subject to the requirements of the Executive Order. The 
Executive Order defines ``significant regulatory action'' as one that 
is likely to result in a rule that may:
    (1) Have an annual effect on the economy of $100 million or more or 
adversely affect in a material way the economy, a sector of the 
economy, productivity, competition, jobs, the environment, public 
health or safety, or State, local, or tribal governments or 
communities;
    (2) Create a serious inconsistency or otherwise interfere with an 
action taken or planned by another agency;
    (3) Materially alter the budgetary impact of entitlements, grants, 
user fees, or loan programs, or the rights and obligation of recipients 
thereof; or
    (4) Raise novel legal or policy issues arising out of legal 
mandates, the President's priorities, or the principles set forth in 
the Executive Order.
    Pursuant to the terms of Executive Order 12866, it has been 
determined that the proposed rule is an economically ``significant 
regulatory action'' because the annual cost may exceed $100 million 
dollars. As such, this action was submitted to OMB for review. Changes 
made in response to OMB suggestions or recommendations will be 
documented in the public record.

B. Paperwork Reduction Act

    The information collection requirements in the proposed NESHAP have 
been submitted for approval to OMB under the Paperwork Reduction Act, 
44 U.S.C. 3501 et seq. The ICR document prepared by EPA has been 
assigned EPA ICR No.----.
    The information requirements are based on notification, 
recordkeeping, and reporting requirements in the NESHAP General 
Provisions (40 CFR part 63, subpart A), which are mandatory for all 
operators subject to national emission standards. These recordkeeping 
and reporting requirements are specifically authorized by section 114 
of the Act (42 U.S.C. 7414). All information submitted to EPA pursuant 
to the recordkeeping and reporting requirements for which a claim of 
confidentiality is made is safeguarded according to Agency policies set 
forth in 40 CFR part 2, subpart B.
    The proposed rule would require a monitoring plan submitted to the 
Administrator but would not require any reports beyond those required 
by the General Provisions. The recordkeeping requirements require only 
the specific information needed to determine compliance. The proposed 
rule would require notification in advance of complying with the rule 
by changing fuel.
    The annual average monitoring, reporting, and recordkeeping burden 
for this collection (averaged over the first 3 years of this ICR) is 
estimated to total 243,000 labor hours per year. This includes 2 
responses per year from 568 respondents for an average of 214 hours per 
response. The total annualized cost burden is estimated at $48.4 
million, including labor, capital, and operation and maintenance. The 
capital costs of monitoring equipment are estimated at $66.8 million; 
the estimated annual cost for operation and maintenance of monitoring 
equipment is $15.4 million.
    Burden means the total time, effort, or financial resources 
expended by persons to generate, maintain, retain, or disclose or 
provide information to or for a Federal agency. This includes the time 
needed to review instructions; develop, acquire, install, and utilize 
technology and systems for the purposes of collecting, validating, and 
verifying information, processing and maintaining information, and 
disclosing and providing information; adjust the existing ways to 
comply with any previously applicable instructions and requirements; 
train personnel to be able to respond to a collection of information; 
search data sources; complete and review the collection of

[[Page 4713]]

information; and transmit or otherwise disclose the information.
    An agency may not conduct or sponsor, and a person is not required 
to respond to, a collection of information unless it displays a 
currently valid OMB control number. The OMB control numbers for EPA's 
regulations in 40 CFR part 63 are listed in 40 CFR part 9.
    To comment on the Agency's need for this information, the accuracy 
of the provided burden estimates, and any suggested methods for 
minimizing respondent burden, including the use of automated collection 
techniques, EPA has established a public docket for this proposed rule, 
which includes this ICR, under Docket ID number OAR-2003-0056. Submit 
any comments related to the ICR for this proposed rule to EPA and OMB. 
See the ADDRESSES section at the beginning of this notice for where to 
submit comments to EPA. Send comments to OMB at the Office of 
Information and Regulatory Affairs, Office of Management and Budget, 
725 17th Street, NW, Washington, DC 20503, Attention: Desk Office for 
EPA. Because OMB is required to make a decision concerning the ICR 
between 30 and 60 days after January 30, 2004, a comment to OMB is best 
assured of having its full effect if OMB receives it by March 1, 2004. 
The final rule will respond to any OMB or public comments on the 
information collection requirements contained in this proposal.

C. Regulatory Flexibility Act

    The EPA has determined that it is not necessary to prepare a 
regulatory flexibility analysis in connection with the proposed rule. 
We have also determined that the proposed rule will not have a 
significant impact on a substantial number of small entities.
    For purposes of assessing the impacts of the final rule on small 
entities, small entity is defined as:
    (1) A small business according to Small Business Administration 
size standards by the North American Industry Classification System 
(NAICS) category of the owning entity. For electric utilities, the size 
standard is 4 billion kilowatt-hours of production or less, 
respectively;
    (2) a small governmental jurisdiction that is a government of a 
city, county, town, school district or special district with a 
population of less than 50,000; and
    (3) a small organization that is any not-for-profit enterprise that 
is independently owned and operated and is not dominant in its field.
    After considering the economic impact of the proposed rule on small 
entities, we have determined that the proposed rule will not have a 
significant impact on a substantial number of small entities. Companies 
owning affected facilities as small businesses are projected to incur 
about 1.2 percent of the total compliance costs. Comparing these costs 
for small entities to their generation revenues, they represent about 
1.3 percent of generation revenues.
    An economic impact analysis was performed to estimate the changes 
in product price and production quantities for this action. As 
mentioned in the summary of economic impacts earlier in this preamble, 
the estimated changes in prices and output for affected firms is less 
than 1 percent.
    This analysis, therefore, allows us to certify that there will not 
be a significant impact on a substantial number of small entities from 
the implementation of the proposed rule. For more information, consult 
the docket for the proposed rule.
    We specifically solicit comment on the option to lower small entity 
costs through excluding units that release small amounts of Hg (e.g., 
less than 25 pounds annually) from the phase II cap, while maintaining 
this cap for the largest sources of Hg.
    We continue to be interested in the potential impacts of the 
proposed rule on small entities and welcome comments on issues related 
to such impacts.

D. Unfunded Mandates Reform Act

    Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public 
Law 104-4, establishes requirements for Federal agencies to assess the 
effects of their regulatory actions on State, local, and tribal 
governments and the private sector. Under section 202 of the UMRA, we 
generally must prepare a written statement, including a cost-benefit 
analysis, for proposed and final rules with ``Federal mandates'' that 
may result in expenditures to State, local, and tribal governments, in 
the aggregate, or to the private sector, of $100 million or more in any 
1 year. Before promulgating a rule for which a written statement is 
needed, section 205 of the UMRA generally requires us to identify and 
consider a reasonable number of regulatory alternatives and adopt the 
least costly, most cost-effective or least burdensome alternative that 
achieves the objectives of the rule. The provisions of section 205 do 
not apply when they are inconsistent with applicable law. Moreover, 
section 205 allows us to adopt an alternative other than the least 
costly, most cost-effective or least burdensome alternative if the 
Administrator publishes with the final rule an explanation why that 
alternative was not adopted. Before we establish any regulatory 
requirements that may significantly or uniquely affect small 
governments, including tribal governments, we must develop a small 
government agency plan under section 203 of the UMRA. The plan must 
provide for notifying potentially affected small governments, enabling 
officials of affected small governments to have meaningful and timely 
input in the development of regulatory proposals with significant 
Federal intergovernmental mandates, and informing, educating, and 
advising small governments on compliance with the regulatory 
requirements.
    We have determined that the proposed rule contains a Federal 
mandate that may result in expenditures of $100 million or more for 
State, local, and tribal governments, in the aggregate, or the private 
sector in any 1 year. Accordingly, we have prepared a written statement 
(titled ``Unfunded Mandates Reform Act Analysis for the Proposed 
Industrial Boilers and Process Heaters NESHAP)'' under section 202 of 
the UMRA which is summarized below.
1. Statutory Authority
    As discussed in section I of this preamble, the statutory authority 
for the proposed rulemaking is sections 111 and 112 of the CAA. Title 
III of the CAA Amendments was enacted to reduce nationwide air toxic 
emissions. Section 112(b) of the CAA lists the 188 chemicals, 
compounds, or groups of chemicals deemed by Congress to be HAP. These 
toxic air pollutants are to be regulated by NESHAP.
    Section 112(d) of the CAA directs us to develop NESHAP which 
require existing and new major sources to control emissions of HAP 
using MACT based standards. This NESHAP applies to all fossil fuel-
fired utility boilers located at major sources of HAP emissions as 
mentioned earlier in this preamble.
    In compliance with section 205(a) of the UMRA, we identified and 
considered a reasonable number of regulatory alternatives. Additional 
information on the costs and environmental impacts of these regulatory 
alternatives is presented in the docket.
    The regulatory alternative upon which the proposed rule is based 
represents the MACT floor for fossil fuel-fired utility boilers and, as 
a result, it is the least costly and least burdensome alternative.

[[Page 4714]]

2. Social Costs and Benefits
    The benefits and cost analyses prepared for the proposed rule are 
detailed in the ``Benefit Analysis of the CAA Section 111 Proposal To 
Reduce Mercury Emissions From Fossil-Fuel Fired Utilities'' and the 
``Economic and Energy Impact Analysis of the Section 112 Utility 
MACT,'' respectively. Both of these reports are in the docket. Based on 
estimated compliance costs associated with the proposed rule and the 
predicted change in prices and production in the affected industry, the 
estimated social costs of the proposed rule are $1.6 billion (1999 
dollars).
    It is estimated that by 2010, Hg emissions will be reduced by the 
section 112 MACT rule to approximately 34 tons and Ni emissions reduced 
to approximately 103 tons. Studies have determined a relationship 
between exposure to these HAP and the onset of cancer and a number of 
other health effects. The Agency is unable to provide a monetized 
estimate of the benefits of the Hg and Ni emissions reduced by the 
proposed rule at this time. However, there are significant reductions 
in NOX and SO2 that occur. Reductions of 
NOX amount to 902,000 tons and 591,000 tons of 
SO2 are expected to occur. These reductions occur from 
existing sources in operation in 2010 and are expected to continue 
throughout the life of the affected sources. The major health effect 
that results from these NOX and SO2 emissions 
reductions is a reduction in premature mortality. Other health effects 
that occur are reductions in chronic bronchitis, asthma attacks, and 
work-lost days (i.e., days when employees are unable to work).
    While we are unable to monetize the benefits associated with the Hg 
and Ni HAP emissions reductions, we are able to monetize the benefits 
associated with the PM and SO2 emissions reductions. For 
NOX and SO2, we estimated the benefits associated 
with reductions of health effects but were unable to quantify all 
categories of benefits (particularly those associated with ecosystem 
and environmental effects). Estimates of the benefits and costs of the 
SO2 and NOX emission reductions associated with 
the proposed actions are presented in Table 8 above. Unquantified 
benefits are noted with ``B'' in the estimates presented below.
3. Future and Disproportionate Costs
    The Unfunded Mandates Act requires that we estimate, where accurate 
estimation is reasonably feasible, future compliance costs imposed by 
the proposed rule and any disproportionate budgetary effects. Our 
estimates of the future compliance costs of the proposed rule are 
discussed in section--of this preamble.
    We do not believe that there will be any disproportionate budgetary 
effects of the proposed rule on any particular areas of the country, 
State or local governments, types of communities (e.g., urban, rural), 
or particular industry segments. This is true for the 28 facilities 
owned by about 80 different government bodies, and this is borne out by 
the results of the ``Economic and Energy Impact Analysis of the Utility 
MACT,'' the results of which are discussed in a previous section of 
this preamble.
4. Effects on the National Economy
    The Unfunded Mandates Act requires that we estimate the effect of 
the proposed rule on the national economy. To the extent feasible, we 
must estimate the effect on productivity, economic growth, full 
employment, creation of productive jobs, and international 
competitiveness of the U.S. goods and services, if we determine that 
accurate estimates are reasonably feasible and that such effect is 
relevant and material.
    The nationwide economic impact of the proposed rule is presented in 
the ``Economic and Energy Impact Analysis for the Utility MACT'' in the 
docket. This analysis provides estimates of the effect of the proposed 
rule on some of the categories mentioned above. The results of the 
economic impact analysis are summarized in a previous section of this 
preamble.
5. Consultation With Government Officials
    The Unfunded Mandates Act requires that we describe the extent of 
the Agency's prior consultation with affected State, local, and tribal 
officials, summarize the officials' comments or concerns, and summarize 
our response to those comments or concerns. In addition, section 203 of 
the UMRA requires that we develop a plan for informing and advising 
small governments that may be significantly or uniquely impacted by a 
proposal. Although the proposed rule does not affect any State, local, 
or tribal governments, we have consulted with State and local air 
pollution control officials. We also have held meetings on the proposed 
rule with many of the stakeholders from numerous individual companies, 
environmental groups, consultants and vendors, labor unions, and other 
interested parties. We have added materials to the Air docket to 
document these meetings.
    In addition, we have determined that the proposed rule contains no 
regulatory requirements that might significantly or uniquely affect 
small governments. While some small governments may have some sources 
affected by the proposed rule, the impacts are not expected to be 
significant. Therefore, today's proposed rule is not subject to the 
requirements of section 203 of the UMRA.

E. Executive Order 13132: Federalism

    Executive Order 13132 (64 FR 43255, August 10, 1999), requires EPA 
to develop an accountable process to ensure ``meaningful and timely 
input by State and local officials in the development of regulatory 
policies that have federalism implications.'' ``Policies that have 
federalism implications'' is defined in the Executive Order to include 
regulations that have ``substantial direct effects on the States, on 
the relationship between the national government and the States, or on 
the distribution of power and responsibilities among the various levels 
of government.''
    The proposed rule does not have federalism implications. It will 
not have substantial direct effects on the States, on the relationship 
between the national government and the States, or on the distribution 
of power and responsibilities among the various levels of government, 
as specified in Executive Order 13132.
    Although section 6 of Executive Order 13132 does not apply to the 
proposed rule, we consulted with representatives of State and local 
governments to enable them to provide meaningful and timely input into 
the development of the proposed rule. This consultation took place 
during the FACA committee meetings where members representing State and 
local governments participated in developing recommendations for this 
rulemaking. The concerns raised by representatives of State and local 
governments were considered during the development of the proposed 
rule.
    In the spirit of Executive Order 13132, and consistent with EPA 
policy to promote communications between EPA and State and local 
governments, EPA specifically solicits comment on the proposed rule 
from State and local officials.

F. Executive Order 13175: Consultation and Coordination With Indian 
Tribal Governments

    Executive Order 13175 (65 FR 67249, November 6, 2000) requires the 
EPA to develop an accountable process to ensure ``meaningful and timely 
input by tribal officials in the development of regulatory policies 
that have Tribal

[[Page 4715]]

implications.'' ``Policies that have tribal implications'' is defined 
in the Executive Order to include regulations that have ``substantial 
direct effects on one or more Indian tribes, on the relationship 
between the Federal government and the Indian tribes, or on the 
distribution of power and responsibilities between the Federal 
government and Indian tribes.''
    Under section 5(b) of Executive Order 13175, EPA may not issue a 
regulation that has tribal implications, that imposes substantial 
direct compliance costs, and that is not required by statute, unless 
the Federal government provides the funds necessary to pay the direct 
compliance costs incurred by Tribal governments, or EPA consults with 
Tribal officials early in the process of developing the proposed 
regulation. Under section 5(c) of Executive Order 13175, EPA may not 
issue a regulation that has Tribal implications and that preempts 
tribal law, unless the Agency consults with Tribal officials early in 
the process of developing the proposed regulation.
    The EPA has concluded that the proposed rule may have Tribal 
implications because two coal-fired Utility Units are located in Indian 
Country. Based on a review of information available to EPA at this time 
about the operations at these two plants, the Agency concluded that 
compliance of the plants with the requirements of the proposed rule 
would not impose substantial direct compliance costs on the affected 
Tribal governments. The EPA specifically solicits additional comment 
from Tribal officials on the proposed rule's potential impacts on 
Utility Units located in Indian Country.

G. Executive Order 13045: Protection of Children From Environmental 
Health and Safety Risks

    Executive Order 13045, ``Protection of Children From Environmental 
Health Risks and Safety Risks'' (62 FR 19885, April 23, 1997) applies 
to any rule that (1) is determined to be ``economically significant'' 
as defined under Executive Order 12866, and (2) concerns an 
environmental health or safety risk that EPA has reason to believe may 
have a disproportionate effect on children. If the regulatory action 
meets both criteria, Section 5-501 of the Order directs the Agency to 
evaluate the environmental health or safety effects of the planned rule 
on children, and explain why the planned regulation is preferable to 
other potentially effective and reasonably feasible alternatives.
    In accordance with the Order, the Agency evaluated the 
environmental and health and safety effects of the proposed rule, and 
for the reasons explained above, the Agency believes that the proposed 
strategies are preferable to other potentially effective and reasonably 
feasible alternatives. The strategies proposed in this rulemaking will 
further improve air quality and will further improve children's health.

H. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use

    Executive Order 13211 (66 FR 28355, May 22, 2001) provides that 
agencies shall prepare and submit to the Administrator of the Office of 
Information and Regulatory Affairs, Office of Management and Budget, a 
Statement of Energy Effects for certain actions identified as 
``significant energy actions.'' Section 4(b) of Executive Order 13211 
defines ``significant energy actions'' as ``any action by an agency 
(normally published in the Federal Register) that promulgates or is 
expected to lead to the promulgation of a final rule or regulation, 
including notices of inquiry, advance notices of final rulemaking, and 
notices of final rulemaking: (1) (i) That is a significant regulatory 
action under Executive Order 12866 or any successor order, and (ii) is 
likely to have a significant adverse effect on the supply, 
distribution, or use of energy; or (2) that is designated by the 
Administrator of the Office of Information and Regulatory Affairs as a 
``significant energy action.'' The proposed rule is a ``significant 
energy action'' because it is likely to have a significant adverse 
effect on the supply, distribution, or use of energy. The basis for the 
determination is as follows.
    Compared to 2010 projections of existing statutory and regulatory 
requirements, coal-fired and gas-fired electricity generation are 
projected to remain relatively unchanged by this action. When compared 
to 2010 projections of existing statutory and regulatory requirements, 
about 900 MW of coal-fired capacity is projected to be uneconomic to 
maintain. Coal production for the electric power sector is expected to 
increase from 2000 levels, about 147 million tons or 16 percent. When 
compared to 2010 projections of existing statutory and regulatory 
requirements, the nationwide price of fuel for the electric power 
sector, both coal and natural gas remain relatively unchanged by this 
action, with coal prices projected to remain unchanged and gas prices 
projected to increase less than 1 percent. Nationwide retail 
electricity prices are projected to gradually decline from 2000 levels 
but then rise over time. Prices are projected to drop initially due to 
excess generation capacity; in 2010 prices are projected to increase 
due to new capacity requirements, which lead to higher capital costs 
and greater natural gas use, and higher retail prices passed on to 
consumers. In 2020, retail electricity prices are projected to still be 
below 2000 prices. When compared to 2010 projections of existing 
statutory and regulatory requirements, electricity prices are projected 
to increase less than 1 percent. We also expect that there will be no 
discernible impact on the import of foreign energy supplies, and no 
other adverse outcomes are expected to occur with regards to energy 
supplies. For more information on the estimated energy effects, please 
refer to the economic and energy impact analysis memo for the proposed 
rule. The analysis is available in the public docket. Total annual 
costs of this action are projected to be up to $1.6 billion in 2010, 
depending on other actions that EPA or States might take to control 
SO2 and NOX emissions. These costs represent 
about a 1.9 percent increase in annual electricity production costs.
    Because this proposed regulation has greater than a 1 percent 
impact on the cost of electricity production and because it results in 
the retirement of greater than 500 MW of coal-fired generation (the 
retirement estimate is 900 MW), this regulation is significant. It 
should be noted that EPA has proposed a trading program to achieve Hg 
reduction as an alternative to the MACT standard, which is a command 
and control regulation. The relative flexibility offered by a trading 
program may ease the impact on energy production.

I. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement 
Act (NTTAA) of 1995 (Pub. L. No. 104-113; 15 U.S.C. 272 note) directs 
EPA to use voluntary consensus standards in its regulatory and 
procurement activities unless to do so would be inconsistent with 
applicable law or otherwise impractical. Voluntary consensus standards 
are technical standards (e.g., materials specifications, test methods, 
sampling procedures, business practices) developed or adopted by one or 
more voluntary consensus bodies. The NTTAA directs EPA to provide 
Congress, through annual reports to the OMB, with explanations when EPA 
does not use available and applicable voluntary consensus standards.
    This rulemaking involves technical standards.

[[Page 4716]]

List of Subjects

40 CFR Part 60

    Environmental protection, Administrative practice and procedure, 
Air pollution control, Coal, Electric power plants, Intergovernmental 
relations, Metals, Natural gas, Nitrogen dioxide, Particulate matter, 
Reporting and recordkeeping requirements, Sulfur oxides.

40 CFR Part 63

    Environmental protection, Air pollution control, Hazardous 
substances, Reporting and recordkeeping requirements.

    Dated: December 15, 2003.
Michael O. Leavitt,
Administrator.
    For the reasons stated in the preamble, title 40, chapter I, parts 
60 and 63 of the Code of the Federal Regulations are proposed to be 
amended as follows:

Note: There are two options proposed for comment. Based on the 
comments we receive on this proposal, we will promulgate either 
Option 1 or Option 2.

Option 1--Proposed Amendments to Parts 60 and 63

PART 60--[AMENDED]

    1. The authority citation for part 60 continues to read as follows:

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

    2. Section 60.17 is amended by adding paragraph (a)(65) to read as 
follows:


Sec. 60.17  Incorporations by Reference.

* * * * *
    (a) * * *
    (65) ASTM D6784-02, Standard Test Method for Elemental, Oxidized, 
Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired 
Stationary Sources (Ontario Hydro Method), for appendix B to part 60, 
Performance Specification 12A.
* * * * *

APPENDIX B PART 60

    3. Appendix B to part 60 is amended by adding in numerical order 
new Performance Specification 12A to read as follows:

Performance Specification 12a--Specifications and Test Procedures 
for Total Vapor Phase Mercury Continuous Emission Monitoring 
Systems in Stationary Sources

    1.0 Scope and Application.
    1.1 Analyte.

------------------------------------------------------------------------
                          Analyte                              CAS No.
------------------------------------------------------------------------
Mercury (Hg)...............................................    7439-97-6
------------------------------------------------------------------------

    1.2 Applicability.
    1.2.1 This specification is for evaluating the acceptability of 
total vapor phase Hg continuous emission monitoring systems (CEMS) 
installed on the exit gases from fossil fuel fired boilers at the 
time of or soon after installation and whenever specified in the 
regulations. The Hg CEMS must be capable of measuring the total 
concentration in [mu]g/m3 (regardless of speciation) of 
vapor phase Hg, and recording that concentration on a dry basis, 
corrected to 20 degrees C and 7 percent CO2. Particle 
bound Hg is not included. The CEMS must include (a) a diluent 
(CO2) monitor, which must meet Performance Specification 
3 in 40 CFR part 60, appendix B, and (b) an automatic sampling 
system. Existing diluent and flow monitoring equipment can be used.
    This specification is not designed to evaluate an installed 
CEMS's performance over an extended period of time nor does it 
identify specific calibration techniques and auxiliary procedures to 
assess the CEMS's performance. The source owner or operator, 
however, is responsible to calibrate, maintain, and operate the CEMS 
properly. The Administrator may require, under CAA section 114, the 
operator to conduct CEMS performance evaluations at other times 
besides the initial test to evaluate the CEMS performance. See 40 
CFR 60.13(c).
    2.0 Summary of Performance Specification
    Procedures for measuring CEMS relative accuracy, measurement 
error and drift are outlined. CEMS installation and measurement 
location specifications, and data reduction procedures are included. 
Conformance of the CEMS with the Performance Specification is 
determined.
    3.0 Definitions
    3.1 Continuous Emission Monitoring System (CEMS) means the total 
equipment required for the determination of a pollutant 
concentration. The system consists of the following major 
subsystems:
    3.2 Sample Interface means that portion of the CEMS used for one 
or more of the following: sample acquisition, sample transport, 
sample conditioning, and protection of the monitor from the effects 
of the stack effluent.
    3.3 Hg Analyzer means that portion of the CEMS that measures the 
total vapor phase Hg mass concentration and generates a proportional 
output.
    3.4 Diluent Analyzer (if applicable) means that portion of the 
CEMS that senses the diluent gas (CO2) and generates an 
output proportional to the gas concentration.
    3.5 Data Recorder means that portion of the CEMS that provides a 
permanent electronic record of the analyzer output. The data 
recorder can provide automatic data reduction and CEMS control 
capabilities.
    3.6 Span Value means the upper limit of the intended Hg 
concentration measurement range. The span value is a value equal to 
two times the emission standard.
    3.7 Measurement Error (ME) means the difference between the 
concentration indicated by the CEMS and the known concentration 
generated by a reference gas when the entire CEMS, including the 
sampling interface, is challenged. An ME test procedure is performed 
to document the accuracy and linearity of the CEMS at several points 
over the measurement range.
    3.8 Upscale Drift (UD) means the difference in the CEMS output 
responses to a Hg reference gas when the entire CEMS, including the 
sampling interface, is challenged after a stated period of operation 
during which no unscheduled maintenance, repair, or adjustment took 
place.
    3.9 Zero Drift (ZD) means the difference in the CEMS output 
responses to a zero gas when the entire CEMS, including the sampling 
interface, is challenged after a stated period of operation during 
which no unscheduled maintenance, repair, or adjustment took place.
    3.10 Relative Accuracy (RA) means the absolute mean difference 
between the pollutant concentration(s) determined by the CEMS and 
the value determined by the reference method (RM) plus the 2.5 
percent error confidence coefficient of a series of tests divided by 
the mean of the RM tests or the applicable emission limit.
    4.0 Interferences [Reserved]
    5.0 Safety
    The procedures required under this performance specification may 
involve hazardous materials, operations, and equipment. This 
performance specification may not address all of the safety problems 
associated with these procedures. It is the responsibility of the 
user to establish appropriate safety and health practices and 
determine the applicable regulatory limitations prior to performing 
these procedures. The CEMS user's manual and materials recommended 
by the reference method should be consulted for specific precautions 
to be taken.
    6.0 Equipment and Supplies
    6.1 CEMS Equipment Specifications.
    6.1.1 Data Recorder Scale. The CEMS data recorder output range 
must include zero and a high level value. The high level value must 
be approximately 2 times the Hg concentration corresponding to the 
emission standard level for the stack gas under the circumstances 
existing as the stack gas is sampled. If a lower high level value is 
used, the CEMS must have the capability of providing multiple high 
level values (one of which is equal to the span value) or be capable 
of automatically changing the high level value as required (up to 
specified high level value) such that the measured value does not 
exceed 95 percent of the high level value.
    6.1.2 The CEMS design should also provide for the determination 
of response drift at both the zero and mid-level value. If this is 
not possible or practical, the design must allow these 
determinations to be conducted at a low-level value (zero to 20 
percent of the high-level value) and at a value between 50 and 100 
percent of the high-level value.
    6.2 Reference Gas Delivery System. The reference gas delivery 
system must be designed so that the flowrate of reference gas 
introduced to the CEMS is the same at all three challenge levels 
specified in Section 7.1 and at all times exceeds the flow 
requirements of the CEMS.

[[Page 4717]]

    6.3 Other equipment and supplies, as needed by the applicable 
reference method used. See Section 8.6.2.
    7.0 Reagents and Standards
    7.1 Reference Gases.
    7.1.1 Zero--N2 or Air. Less than 0.1 [mu]g Hg/
m3.
    7.1.2 Mid-level Hg0 and HgCl2. 40 to 60 
percent of span.
    7.1.3 High-level Hg0 and HgCl2. 80 to 100 
percent of span.
    7.2 Reagents and Standards. May be required for the reference 
methods. See Section 8.6.2.
    8.0 Performance Specification Test Procedure
    8.1 Installation and Measurement Location Specifications.
    8.1.1 CEMS Installation. Install the CEMS at an accessible 
location downstream of all pollution control equipment. Since the Hg 
CEMS sample system normally extracts gas from a single point in the 
stack, use a location that has been shown to be free of 
stratification for SO2 and NOX through 
concentration measurement traverses for those gases. If the cause of 
failure to meet the RA test requirement is determined to be the 
measurement location and a satisfactory correction technique cannot 
be established, the Administrator may require the CEMS to be 
relocated.
    Measurement locations and points or paths that are most likely 
to provide data that will meet the RA requirements are listed below.
    8.1.2 Measurement Location. The measurement location should be 
(1) at least eight equivalent diameters downstream of the nearest 
control device, point of pollutant generation, bend, or other point 
at which a change of pollutant concentration or flow disturbance may 
occur, and (2) at least two equivalent diameters upstream from the 
effluent exhaust. The equivalent duct diameter is calculated as per 
40 CFR part 60, appendix A, Method 1.
    8.1.3 Hg CEMS Sample extraction Point. Use a sample extraction 
point (1) no less than 1.0 meter from the stack or duct wall, or (2) 
within the centroidal velocity traverse area of the stack or duct 
cross section.
    8.2 Reference Method (RM) Measurement Location and Traverse 
Points. The RM measurement location should be at a point or points 
in the same stack cross sectional area as the CEMS is located, 
according to the criteria above. The RM and CEMS locations need not 
be immediately adjacent. They should be as close as possible without 
causing interference with one another.
    8.3 Measurement Error (ME) Test Procedure. The Hg CEMS must be 
constructed to permit the introduction of known (NIST traceable) 
concentrations of elemental mercury (Hg0) and mercuric 
chloride (HgCl2) separately into the sampling system of 
the CEMS immediately preceding the sample extraction filtration 
system such that the entire CEMS can be challenged. Inject 
sequentially each of the three reference gases (zero, mid-level, and 
high level) for each Hg species. CEMS measurements of each reference 
gas shall not differ from their respective reference values by more 
than 5 percent of the span value. If this specification is not met, 
identify and correct the problem before proceeding.
    8.4 Upscale Drift (UD) Test Procedure.
    8.4.1 UD Test Period. While the affected facility is operating 
at more than 50 percent of normal load, or as specified in an 
applicable subpart, determine the magnitude of the UD once each day 
(at 24-hour intervals) for 7 consecutive days according to the 
procedure given in Sections 8.4.2 through 8.4.3.
    8.4.2 The purpose of the UD measurement is to verify the ability 
of the CEMS to conform to the established CEMS response used for 
determining emission concentrations or emission rates. Therefore, if 
periodic automatic or manual adjustments are made to the CEMS zero 
and response settings, conduct the UD test immediately before these 
adjustments, or conduct it in such a way that the UD can be 
determined.
    8.4.3 Conduct the UD test at the mid-level point specified in 
Section 7.1. Evaluate upscale drift for elemental Hg 
(Hg0) only. Introduce the reference gas to the CEMS. 
Record the CEMS response and subtract the reference value from the 
CEM value (see example data sheet in Figure 12A-1).
    8.5 Zero Drift (ZD) Test Procedure.
    8.5.1 ZD Test Period. While the affected facility is operating 
at more than 50 percent of normal load, or as specified in an 
applicable subpart, determine the magnitude of the ZD once each day 
(at 24-hour intervals) for 7 consecutive days according to the 
procedure given in Sections 8.5.2 through 8.5.3.
    8.5.2 The purpose of the ZD measurement is to verify the ability 
of the CEMS to conform to the established CEMS response used for 
determining emission concentrations or emission rates. Therefore, if 
periodic automatic or manual adjustments are made to the CEMS zero 
and response settings, conduct the ZD test immediately before these 
adjustments, or conduct it in such a way that the ZD can be 
determined.
    8.5.3 Conduct the ZD test at the zero level specified in Section 
7.1. Introduce the zero gas to the CEMS. Record the CEMS response 
and subtract the zero value from the CEM value (see example data 
sheet in Figure 12A-1).
    8.6 Relative Accuracy (RA) Test Procedure.
    8.6.1 RA Test Period. Conduct the RA test according to the 
procedure given in Sections 8.6.2 through 8.6.6 while the affected 
facility is operating at normal full load, or as specified in an 
applicable subpart. The RA test can be conducted during the UD test 
period.
    8.6.2 Reference Method (RM). Unless otherwise specified in an 
applicable subpart of the regulations, use either Method 29 in 
appendix A to 40 CFR part 60, or ASTM Method D 6784-02 (incorporated 
by reference in Sec. 60.17) as the RM for Hg. Do not include the 
filterable portion of the sample when making comparisons to the CEMS 
results. Conduct all RM tests with paired or duplicate sampling 
systems.
    8.6.3 Sampling Strategy for RM Tests. Conduct the RM tests in 
such a way that they will yield results representative of the 
emissions from the source and can be compared to the CEMS data. It 
is preferable to conduct the diluent (if applicable), moisture (if 
needed), and Hg measurements simultaneously. However, diluent and 
moisture measurements that are taken within an hour of the Hg 
measurements can be used to adjust the results to a consistent 
basis. In order to correlate the CEMS and RM data properly, note the 
beginning and end of each RM test period for each paired RM run 
(including the exact time of day) on the CEMS chart recordings or 
other permanent record of output.
    8.6.4 Number and length of RM Tests. Conduct a minimum of nine 
paired sets of all necessary RM test runs that meet the relative 
standard deviation criteria of this PS. Use a minimum sample run 
time of 2 hours for each pair.

    Note: More than nine paired sets of RM tests can be performed. 
If this option is chosen, test results can be rejected so long as 
the total number of paired RM test results used to determine the 
CEMS RA is greater than or equal to nine. However, all data must be 
reported, including the rejected data.

    8.6.5 Correlation of RM and CEMS Data. Correlate the CEMS and 
the RM test data as to the time and duration by first determining 
from the CEMS final output (the one used for reporting) the 
integrated average pollutant concentration or emission rate for each 
pollutant RM test period. Consider system response time, if 
important, and confirm that the results are on a consistent 
moisture, temperature, and diluent concentration basis with the 
paired RM test. Then, compare each integrated CEMS value against the 
corresponding average of the paired RM values.
    8.6.6 Paired RM Outliers.
    8.6.6.1 Outliers are identified through the determination of 
precision and any systematic bias of the paired RM tests. Data that 
do not meet this criteria should be flagged as a data quality 
problem. The primary reason for performing dual RM sampling is to 
generate information to quantify the precision of the RM data. The 
relative standard deviation (RSD) of paired data is the parameter 
used to quantify data precision. Determine RSD for two 
simultaneously gathered data points as follows:

[GRAPHIC] [TIFF OMITTED] TP30JA04.002



[[Page 4718]]


where:
Ca and Cb are concentration values determined from trains A and B 
respectively. For RSD calculation, the concentration units are 
unimportant so long as they are consistent.

    8.6.6.2 A minimum precision criteria for RM Hg data is that RSD 
for any data pair must be [le]10 percent as long as the mean Hg 
concentration is greater than 1.0 [mu]g/m3. If the mean 
Hg concentration is less than or equal to 1.0 [mu]g/m3, 
the RSD must be [le]20 percent. Pairs of RM data exceeding these RSD 
criteria should be eliminated from the data set used to develop a Hg 
CEMS correlation or to assess CEMS RA.
    8.6.7 Calculate the mean difference between the RM and CEMS 
values in the units of the emission standard, the standard 
deviation, the confidence coefficient, and the RA according to the 
procedures in Section 12.0.
    8.7 Reporting. At a minimum (check with the appropriate EPA 
Regional Office, State, or local Agency for additional requirements, 
if any), summarize in tabular form the results of the RD tests and 
the RA tests or alternative RA procedure, as appropriate. Include 
all data sheets, calculations, charts (records of CEMS responses), 
reference gas concentration certifications, and any other 
information necessary to confirm that the performance of the CEMS 
meets the performance criteria.
    9.0 Quality Control [Reserved]
    10.0 Calibration and Standardization [Reserved]
    11.0 Analytical Procedure.
    Sample collection and analysis are concurrent for this 
Performance Specification (see Section 8.0). Refer to the RM 
employed for specific analytical procedures.
    12.0 Calculations and Data Analysis
    Summarize the results on a data sheet similar to that shown in 
Figure 2-2 for Performance Specification 2.
    12.1 Consistent Basis. All data from the RM and CEMS must be on 
a consistent dry basis and, as applicable, on a consistent diluent 
basis. Correct the RM and CEMS data for moisture and diluent as 
follows:
    12.1.1 Moisture Correction (as applicable). Correct each wet RM 
run for moisture with the corresponding Method 4 data; correct each 
wet CEMS run using the corresponding CEMS moisture monitor date 
using Equation 12A-2.

[GRAPHIC] [TIFF OMITTED] TP30JA04.003


    12.1.2 Correction to Units of Standard (as applicable). Correct 
each dry RM run to the units of the emission standard with the 
corresponding Method 3B data; correct each dry CEMS run using the 
corresponding CEMS diluent monitor data as follows:
    12.1.3 Correct to Diluent Basis. The following is an example of 
concentration (ppm) correction to 7 percent oxygen.

[GRAPHIC] [TIFF OMITTED] TP30JA04.004


    The following is an example of mass/gross calorific value (lbs/
million Btu) correction.

lbs/MMBtu = Conc(dry) (F-factor) ((20.9/(20.9 - percent 
O2))

    12.2 Arithmetic Mean. Calculate the arithmetic mean of the 
difference, d, of a data set as follows:

[GRAPHIC] [TIFF OMITTED] TP30JA04.005

Where:
n = Number of data points.
12.3 Standard Deviation. Calculate the standard deviation, 
Sd, as follows:

[GRAPHIC] [TIFF OMITTED] TP30JA04.006


Where:
[GRAPHIC] [TIFF OMITTED] TP30JA04.007


12.4 Confidence Coefficient. Calculate the 2.5 percent error 
confidence coefficient (one-tailed), CC, as follows:

[GRAPHIC] [TIFF OMITTED] TP30JA04.008


    12.5 Relative Accuracy. Calculate the RA of a set of data as 
follows:

[GRAPHIC] [TIFF OMITTED] TP30JA04.009


Where:
[bond]d[bond] = Absolute value of the mean differences (from 
Equation 12A-4).
[bond]CC[bond] = Absolute value of the confidence coefficient (from 
Equation 12A-6).
RM = Average RM value. In cases where the average emissions for the 
test are less than 50 percent of the applicable standard, substitute 
the emission standard value in the denominator of Eq. 12A-7 in place 
of RM. In all other cases, use RM.

    13.0 Method Performance.
    13.1 Measurement Error (ME). ME is assessed at mid-level and 
high-level values as given below using standards for both 
Hg0 and HgCl2. The mean difference between the 
indicated CEMS concentration and the reference concentration value 
for each standard shall be no greater than 5 percent of span. The 
same difference for the zero reference gas shall be no greater than 
5 percent of span.
    13.2 Upscale Drift (UD). The CEMS design must allow the 
determination of UD of the analyzer. The CEMS response can not drift 
or deviate from the benchmark value of the reference standard by 
more than 5 percent of span for the mid level value. Evaluate 
upscale drift for Hg0 only.
    13.3 Zero Drift (ZD). The CEMS design must allow the 
determination of drift at the

[[Page 4719]]

zero level. This drift shall not exceed 5 percent of span.
    13.4 Relative Accuracy (RA). The RA of the CEMS must be no 
greater than 20 percent of the mean value of the RM test data in 
terms of units of the emission standard, or 10 percent of the 
applicable standard, whichever is greater.
    14.0 Pollution Prevention. [Reserved]
    15.0 Waste Management. [Reserved]
    16.0 Alternative Procedures. [Reserved]
    17.0 Bibliography.
    17.1 40 CFR part 60, appendix B, ``Performance Specification 2--
Specifications and Test Procedures for SO2 and 
NOX Continuous Emission Monitoring Systems in Stationary 
Sources.''
    17.2 40 CFR part 60, appendix A, ``Method 29--Determination of 
Metals Emissions from Stationary Sources.''
    17.3 ASTM Method D6784-02, ``Standard Test Method for Elemental, 
Oxidized, Particle-Bound and Total Mercury in Flue Gas Generated 
from Coal-Fired Stationary Sources (Ontario Hydro Method).''
    18.0 Tables and Figures

                                             Table 12A-1.--t-Values
----------------------------------------------------------------------------------------------------------------
                     n \a\                         t 0.975        n a        t 0.975        n a        t 0.975
----------------------------------------------------------------------------------------------------------------
2..............................................       12.706            7        2.447           12        2.201
3..............................................        4.303            8        2.365           13        2.179
4..............................................        3.182            9        2.306           14        2.160
5..............................................        2.776           10        2.262           15        2.145
6..............................................        2.571           11        2.228           16       2.131
----------------------------------------------------------------------------------------------------------------
\a\ The values in this table are already corrected for n-1 degrees of freedom. Use n equal to the number of
  individual values.


------------------------------------------------------------------------
                                            CEMS
             Day    Date and   Reference   value    Measurement   Drift
                       time   value  (C)    (M)        error
------------------------------------------------------------------------
Zero
Level
         -----------
 
         -----------
 
         -----------
 
         -----------
Mid-
 level
 
         -----------
 
         -----------
 
=========
High-
 level
 
         -----------
 
         -----------
 
         -----------
           Figure 12A-1. Zero and Upscale Drift Determination.

PART 63--[AMENDED]

    4. The authority citation for part 63 continues to read as follows:

    Authority: 42 U.S.C. 7401, et seq.
    5. Section 63.14 is amended by adding paragraph (b)(35) to read as 
follows:


Sec. 63.14  Incorporations by Reference.

* * * * *
    (b) * * *
    (35) ASTM D6784-02, Standard Test Method for Elemental, Oxidized, 
Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired 
Stationary Sources (Ontario Hydro Method), for appendix B to part 63, 
Method 324.
* * * * *
    6. Part 63 is amended by adding subpart UUUUU to read as follows:

Subpart UUUUU--National Emission Standards for Hazardous Air 
Pollutants for Coal-or Oil-Fired Electric Utility Steam Generating 
Units

Sec.

What This Subpart Covers

63.9980 What is the purpose of this subpart?
63.9981 Am I subject to this subpart?
63.9982 What parts of my facility does this subpart cover?
63.9983 When do I have to comply with this subpart?

Emissions Limitations

63.9990 What emissions limitations must I meet for coal-fired 
electric utility steam generating units?
63.9991 What emissions limitations must I meet for oil-fired 
electric utility steam generating units?
63.9992 What are my compliance options for multiple affected 
sources?

General Compliance Requirements

63.10000 What are my general requirements for complying with this 
subpart?

Initial Compliance Requirements

63.10005 By what date must I conduct performance tests or other 
initial compliance demonstrations?
63.10006 When must I conduct subsequent performance tests?
63.10007 What performance test procedures must I use?
63.10008 What are my monitoring, installation, operation, and 
maintenance requirements?
63.10009 How do I demonstrate initial compliance with the emissions 
limitations?

Continuous Compliance Requirements

63.10020 How do I monitor and collect data to demonstrate continuous 
compliance?
63.10021 How do I demonstrate continuous compliance with the 
emissions limitations?

[[Page 4720]]

Notifications, Reports, and Records

63.10030 What notifications must I submit and when?
63.10031 What reports must I submit and when?
63.10032 What records must I keep?
63.10033 In what form and how long must I keep my records?

Other Requirements and Information

63.10040 What parts of the General Provisions apply to me?
63.10041 Who implements and enforces this subpart?
63.10042 What definitions apply to this subpart?

Tables to Subpart UUUUU of Part 63

Table 1 to Subpart UUUUU of Part 63--Performance Test Requirements 
for Ni and Hg
Table 2 to Subpart UUUUU of Part 63--Initial Compliance With 
Emissions Limitations for Ni and Hg
Table 3 to Subpart UUUUU of Part 63--Continuous Compliance with 
Emissions Limitations for Hg and Ni
Table 4 to Subpart UUUUU of Part 63--Applicability of General 
Provisions to Subpart UUUUU

What This Subpart Covers


Sec. 63.9980  What is the purpose of this subpart?

    This subpart establishes national emissions limitations for 
hazardous air pollutants (HAP) emitted from coal-fired electric utility 
steam generating units and oil-fired electric utility steam generating 
units. This subpart also establishes requirements to demonstrate 
initial and continuous compliance with the emissions limitations.


Sec. 63.9981  Am I subject to this subpart?

    You are subject to this subpart if you own or operate a coal-fired 
electric utility steam generating unit or an oil-fired electric utility 
steam generating unit.


Sec. 63.9982  What parts of my facility does this subpart cover?

    (a) The affected source is each group of one or more coal- or oil-
fired electric utility steam generating units located at a facility. An 
electric utility steam generating unit that combusts natural gas at 
greater than or equal to 98 percent of the unit's annual fuel 
consumption is not an affected source under this subpart.
    (b) A coal or oil-fired electric utility steam generating unit is a 
new affected source if you commenced construction of the unit after 
January 30, 2004.
    (c) An affected source is reconstructed if you meet the criteria as 
defined in Sec. 63.2. An existing electric utility steam generating 
unit that is switched completely to burning a different coal rank or 
fuel type is considered to be an existing affected source under this 
subpart.
    (d) An affected source is existing if it is not new or 
reconstructed.


Sec. 63.9983  When do I have to comply with this subpart?

    (a) If you have a new or reconstructed affected source, you must 
comply with this subpart according to paragraph (a) (1) or (2) of this 
section.
    (1) If you start up your affected source before [DATE THE FINAL 
RULE IS PUBLISHED IN THE Federal Register], then you must comply with 
the emissions limitations and work practice standards for new and 
reconstructed sources in this subpart no later than [DATE THE FINAL 
RULE IS PUBLISHED IN THE Federal Register].
    (2) If you startup your affected source on or after [DATE THE FINAL 
RULE IS PUBLISHED IN THE Federal Register], then you must comply with 
the emissions limitations and work practice standards for new and 
reconstructed sources in this subpart upon startup of your affected 
source.
    (b) If you have an existing affected source, you must comply with 
the emissions limitations for existing sources no later than 3 years 
after [DATE THE FINAL RULE IS PUBLISHED IN THE Federal Register].
    (c) You must meet the notification requirements according to the 
schedule applicable to your facility as specified in Sec. 63.10300 and 
in subpart A of this part. Some of the notifications must be submitted 
before you are required to comply with the emissions limitations in 
this subpart.

Emissions Limitations


Sec. 63.9990  What emissions limitations must I meet for coal-fired 
electric utility steam generating units?

    (a) For each coal-fired electric utility steam generating unit 
other than an integrated gasification combined-cycle (IGCC) electric 
utility steam generating unit, you must meet the mercury (Hg) emissions 
limit in paragraphs (a)(1) through (5) of this section that applies to 
your unit. The Hg emissions limits in paragraphs (a)(1) through (5) of 
this section are based on a 12-month rolling average using the 
procedures in Sec. 63.10009.
    (1) For each coal-fired electric utility steam generating unit that 
burns only bituminous coal, you must meet the Hg emissions limit in 
either paragraph (a)(1)(i) or (ii) of this section that applies to you.
    (i) You must not discharge into the atmosphere from an existing 
affected source any gases which contain Hg in excess of 2.0 pound per 
trillion British thermal unit (lb/TBtu) on an input basis or 21 x 
10-6 pound per Megawatt hour (lb/MWh) on an output basis.
    (ii) You must not discharge into the atmosphere any gases from a 
new affected source which contain Hg in excess of 6.0 x 10-6 
lb/MWh on an output basis.
    (2) For each coal-fired electric utility steam generating unit that 
burns only subbituminous coal, you must meet the Hg emissions limit in 
either paragraph (a)(2)(i) or (ii) of this section that applies to you.
    (i) You must not discharge into the atmosphere any gases from an 
existing affected source which contain Hg in excess of 5.8 lb/TBtu on 
an input basis or 61 x 10-6 lb/MWh on an output basis.
    (ii) You must not discharge into the atmosphere any gases from a 
new affected source which contain Hg in excess of 20 x 10-6 
lb/MWh on an output basis.
    (3) For each coal-fired electric utility steam generating unit that 
burns only lignite coal, you must meet the Hg emissions limit in either 
paragraph (a)(3)(i) or (ii) of this section that applies to you.
    (i) You must not discharge into the atmosphere any gases from an 
existing affected source which contain Hg in excess of 9.2 lb/TBtu on 
an input basis or 98 x 10-6 lb/MWh on an output basis.
    (ii) You must not discharge into the atmosphere any gases from a 
new affected source which contain Hg in excess of 62 x 10-6 
lb/MWh on an output basis.
    (4) For each coal-burning electric utility steam generating unit 
that burns only coal refuse, you must meet the Hg emissions limit in 
either paragraph (a)(4)(i) or (ii) of this section that applies to you.
    (i) You must not discharge into the atmosphere any gases from an 
existing affected source which contain Hg in excess of 0.38 lb/TBtu on 
an input basis or 4.1 x 10-6 lb/MWh on an output basis.
    (ii) You must not discharge into the atmosphere any gases from a 
new affected source which contain Hg in excess of 1.1 x 10-6 
lb/MWh on an output basis.
    (5) For each coal-fired electric utility steam generating unit that 
burns a blend of coals from different coal ranks (i.e., bituminous 
coal, subbituminous coal, lignite) or a blend of coal and coal refuse, 
you must not discharge into the atmosphere any gases from a new or 
existing affected source that contain Hg in excess of the monthly unit-
specific Hg emissions limit established

[[Page 4721]]

according to paragraph (a)(5)(i) or (ii) of this section, as applicable 
to your unit.
    (i) If you operate a coal-fired electric utility steam generating 
unit that burns a blend of coals from different coal ranks or a blend 
of coal and coal refuse, you must not discharge into the atmosphere any 
gases from a new or existing affected source that contain Hg in excess 
of the computed weighted Hg emissions limit based on the proportion of 
energy output (in Btu) contributed by each coal type burned during the 
compliance period and its applicable Hg emissions limit in paragraphs 
(a)(1) through (4) of this section as determined using Equation 1 of 
this section. You must meet the weighted Hg emissions limit calculated 
using Equation 1 of this section by calculating the unit emission rate 
based on the total Hg loading of the unit and the total Btu or megawatt 
hours contributed by all fuels burned during the compliance period.
[GRAPHIC] [TIFF OMITTED] TP30JA04.010


Where:

ELb = Total allowable Hg in lb/MWh (or lb/TBtu) that can be 
emitted to the atmosphere from any affected source being averaged under 
the blending provision.
ELi = Hg emissions limit for the subcategory that applies to 
affected source i, lb/MWh (or lb/TBtu).
HHi = Heat input to, or electricity output from, affected 
source i during the production period related to the corresponding H 
i that falls within the compliance period, gross MWh 
generated or MMBtu heat input to the electric utility steam generating 
unit.
n = Number of coal ranks being averaged for an affected source.

    (ii) If you operate a coal-fired electric utility steam generating 
unit that burns a blend of coals from different coal ranks or a blend 
of coal and coal refuse together with one or more non-regulated, 
supplementary fuels, you must not discharge into the atmosphere any 
gases from the unit that contain Hg in excess of the computed weighted 
Hg emission limit based on the proportion of energy output (in Btu) 
contributed by each coal type burned during the compliance period and 
its applicable Hg emissions limit in paragraphs (a)(1) through (4) of 
this section as determined using Equation 1 of this section. You must 
meet the weighted Hg emissions limit calculated using Equation 1 of 
this section by calculating the unit emission rate based on the total 
Hg loading of the unit and the total Btu or megawatt hours contributed 
by both regulated and nonregulated fuels burned during the compliance 
period.
    (b) For each IGCC electric utility steam generating unit, you must 
meet the Hg emissions limit in either paragraph (b)(1) or (2) of this 
section that applies to you. The Hg emissions limits in this paragraph 
are based on a 12-month rolling average using the procedures in Sec. 
63.10009.
    (1) You must not discharge into the atmosphere any gases from an 
existing affected source which contain Hg in excess of 19 lb/TBtu on an 
input basis or 200 x 10-6 lb/MWh on an output basis.
    (2) You must not discharge into the atmosphere any gases from a new 
affected source which contain Hg in excess of 20 x 10-6 lb/
MWh on an output basis.


Sec. 63.9991  What emissions limitations must I meet for oil-fired 
electric utility steam generating units?

    (a) For each oil-fired electric utility steam generating unit, you 
must meet the nickel (Ni) emissions limit in paragraphs (a)(1) and (2) 
of this section that applies to you, except as provided in paragraph 
(b) of this section.
    (1) You must not discharge into the atmosphere any gases from an 
existing affected source which contain Ni in excess of 210 lb/TBtu on 
an input basis or 0.002 lb/MWh on an output basis.
    (2) You must not discharge into the atmosphere any gases from a new 
affected source which contain Ni in excess of 0.0008 lb/MWh on an 
output basis.
    (b) The emissions limit in paragraph (a) of this section does not 
apply to a new or existing oil-fired electric utility steam generating 
unit if during the reporting period, to burn 98 percent or more 
distillate oil exclusively as the fuel for the unit. The emissions 
limit in paragraph (a) of this section will apply immediately if you 
subsequently burn a fuel other than distillate oil in the unit.
    (c) If you use an electrostatic precipitator (ESP) to meet the 
applicable Ni emissions limit, you must operate the ESP such that the 
hourly average voltage and secondary current (or total power input) do 
not fall below the limit established in the initial or subsequent 
performance test.
    (d) If you use a control device or combination of control devices 
other than an ESP to meet the applicable Ni emissions limit, or you 
wish to establish and monitor an alternative operating limit and 
alternative monitoring parameters for an ESP, you must apply to the 
Administrator for approval of alternative monitoring under Sec. 
63.8(f).


Sec. 63.9992  What are my compliance options for multiple affected 
sources?

    (a) If you have two or more coal-fired electric utility steam 
generating units at your facility that are subject to Hg emission 
limits in Sec. 63.9990, you may choose to use the emissions averaging 
compliance approach specified in paragraph (b) of this section as an 
alternative to complying with the applicable Hg emission limits for 
each individual unit. You may use emissions averaging only under the 
conditions specified in paragraphs (a)(1) and (2) of this section.
    (1) The emissions averaging compliance approach is applicable to 
coal-fired electric utility steam generating units subject to the Hg 
emission limits for existing affected sources under this subpart that 
are located at a common contiguous facility. The emissions averaging 
compliance approach is also applicable to coal-fired electric utility 
stream generating units subject to the Hg emission limits for new 
affected sources under this subpart as long as they meet the new source 
limits specified under this subpart.
    (2) All of the Hg emission limits used for the emissions averaging 
compliance approach must meet the applicable limits expressed in the 
same format (i.e., all of the Hg emission limits must be either the 
applicable lb/TBtu limit values or the applicable lb/MWh limit values).
    (b) If you choose to use the emissions averaging compliance 
approach, you must meet the requirements specified in paragraphs (b)(1) 
through (5) of this section.
    (1) You must designate your emissions averaging source group by 
identifying each of the existing coal-fired electric utility stream 
generating units at your facility site to be included in your emissions 
averaging source group.
    (2) You must designate a common Hg emissions limit format to be 
used for all of the coal-fired electric utility stream generating units 
in your designated emissions averaging source group (either the lb/TBtu 
limit format or the lb/MWh limit format).
    (3) You must determine the Hg emissions limit value in Sec. 63.9990 
for your selected format that is applicable to each of the individual 
coal-fired electric utility stream generating units in your designated 
emissions averaging source group.
    (4) You must calculate the unit-specific Hg emissions limit for 
your

[[Page 4722]]

designated emissions averaging source group using Equation 1 of this 
section.
[GRAPHIC] [TIFF OMITTED] TP30JA04.011


Where:

AvEL = Total allowable Hg that can be emitted to the atmosphere from 
all emission sources in the emissions averaging group, lb/MWh or lb/
TBtu;
Li = Hg emissions limit for the subcategory that applies to 
emission source i or the calculated emissions limit derived for an 
emissions averaging group using Equation 1 of this section, lb/MWh or 
lb/MMBtu;
Vi = Volume of production for emissions source i during the 
production period related to the corresponding Li that falls 
within the 12-month compliance period, gross MWh generated or MMBtu 
heat input to the electric utility steam generating unit; and
n = Number of emissions sources being averaged. This number may apply 
to individual emissions sources or emissions averaging groups.

    (5) You must not discharge into the atmosphere any gases from your 
designated emissions averaging group that contain Hg in excess of the 
unit-specific Hg emissions limit established according to paragraph 
(b)(4) of this section as determined based on a 12-month rolling 
average using the procedures in Sec. 63.10009.
    (c) You may use the emissions averaging compliance approach or 
revise an existing emissions averaging group at any time after the 
compliance date by submitting an emissions averaging plan or revision, 
respectively, using the title V operating permit amendment process 
specified by the regulating authority. The emissions averaging plan 
must contain the information specified in paragraphs (c)(1) and (2) of 
this section.
    (1) Identification of each coal-fired electric utility steam 
generating unit in your designated emissions averaging group and the 
applicable Hg emissions limit for each unit as determined in paragraph 
(b) of this section.
    (2) The Hg emissions limit for your designated emissions averaging 
group as determined in paragraph (b) of this section, including all 
calculations and supporting information.

General Compliance Requirements


Sec. 63.10000  What are my general requirements for complying with this 
subpart?

    (a) You must be in compliance with the emissions limitations 
(including operating limits) in this subpart at all times, except 
during periods of startup, shutdown, and malfunction.
    (b) You must always operate and maintain your affected source, 
including air pollution control and monitoring equipment, according to 
the provisions in Sec. 63.6(e)(1)(i).
    (c) For each monitoring system required by this subpart, you must 
develop and submit to the Administrator for approval a unit-specific 
monitoring plan according to the requirements in Sec. 63.10008(f).
    (d) You must conduct a performance evaluation of each continuous 
monitoring system (CMS) in accordance with your unit-specific 
monitoring plan.
    (e) You must operate and maintain the CMS in continuous operation 
according to the unit-specific monitoring plan.
    (f) You must develop and implement a written startup, shutdown, and 
malfunction plan (SSMP) according to the provisions in Sec. 63.6(e)(3).

Initial Compliance Requirements


Sec. 63.10005  By what date must I conduct performance tests or other 
initial compliance demonstrations?

    (a) For each existing affected source, you must conduct performance 
tests, set operating limits, and conduct monitoring equipment 
performance evaluations, as applicable to your source, by the 
compliance date that is specified for your source in Sec. 63.9983 and 
according to the applicable provisions in Sec. 63.7(a)(2).
    (b) For each new affected source, you must conduct performance 
tests, set operating limits, and conduct monitoring equipment 
performance evaluations, as applicable to your source, within 180 days 
after the compliance date that is specified for your source in Sec. 
63.9983 and according to the provisions in Sec. 63.7(a)(2).


Sec. 63.10006  When must I conduct subsequent performance tests?

    For each affected oil-fired electric utility steam generating units 
subject to a Ni emissions limit in this subpart, you must conduct a 
subsequent performance test at least once each year to demonstrate 
compliance and include the results in the next semiannual compliance 
report.


Sec. 63.10007  What performance test procedures must I use?

    (a) For each affected oil-fired electric utility steam generating 
unit subject to a Ni emissions limit under this subpart, you must 
conduct each performance test to demonstrate compliance with the 
applicable emissions limit according to the requirements in paragraphs 
(a)(1) through (4) of this section.
    (1) You must conduct each performance test according to Sec. 
63.7(c), (d), (f), and (h) and the procedures in Table 1 to this 
subpart. You must also develop a site-specific test plan according to 
the requirements in Sec. 63.7(c).
    (2) You must conduct each performance test at the representative 
process operating conditions that are expected to result in the highest 
emissions of Ni, and you must demonstrate initial compliance and 
establish your operating limits based on this test.
    (3) You may not conduct performance tests during periods of 
startup, shutdown, or malfunction.
    (4) You must conduct three separate test runs for each performance 
test required in this section, as specified in Sec. 63.7(e)(3). Each 
test run must last at least 1 hour.
    (b) You must submit a Notification of Compliance Status report 
containing the results of the initial or annual compliance 
demonstration according to the requirements in Sec. 63.10031(b).


Sec. 63.10008  What are my monitoring, installation, operation, and 
maintenance requirements?

    (a) If you use an ESP to meet a Ni limit in this subpart, you must 
install and operate a continuous parameter monitoring system (CPMS) to 
measure and record the voltage and secondary current (or total power 
input) to the control device.
    (b) You must install, operate, and maintain each CPMS by the 
compliance date specified in Sec. 63.9983 according to the requirements 
in paragraphs (b)(1) through (3) of this section.
    (1) Each CPMS must complete a minimum of one cycle of operation for 
each successive 15-minute period. You must have a minimum of four 
successive cycles of operation to have a valid hour of data.
    (2) Each CPMS must determine the 1-hour block average of all 
recorded readings.
    (3) You must record the results of each inspection, calibration, 
and validation check for a CPMS.
    (c) You must install and operate a continuous emissions monitoring 
system (CEMS) to measure and record

[[Page 4723]]

the concentration of Hg in the exhaust gases from each stack.
    (d) You must install, operate, and maintain each CEMS by the 
compliance date specified in Sec. 63.9983 according to the requirements 
in paragraphs (d)(1) through (4) of this section.
    (1) You must install, operate, and maintain each CEMS according to 
Performance Specification 12A in 40 CFR part 60, appendix B.
    (2) You must conduct a performance evaluation of each CEMS 
according to the requirements of Sec. 63.8 and Performance 
Specification 12A in 40 CFR part 60, appendix B. id.
    (3) You must operate each CEMS according to the requirements in 
paragraphs (d)(3)(i) through (iv) of this section.
    (i) As specified in 63.8(c)(4)(ii), each CEMS must complete a 
minimum of one cycle of operation (sampling, analyzing, and data 
recording) for each successive 15-minute period.
    (ii) You must reduce CEMS data as specified in Sec. 63.8(g)(2).
    (iii) Each CEMS must determine and record the 1 hour average 
emissions using all the hourly averages collected for periods during 
which the CEMS is not out of control.
    (iv) You must record the results of each inspection, calibration, 
and validation check.
    (4) The provisions in paragraphs (d)(4)(i) through (iv) of this 
section apply to data collection periods for your Hg CEMS.
    (i) A complete day of data for continuous monitoring is 18 hours or 
more in a 24-hour period.
    (ii) A complete month of data for continuous monitoring is 21 days 
or more in a calendar month.
    (iii) If you collect less than 21 days of continuous emissions 
data, you must discard the data collected that month and replace that 
data with the mean of the individual monthly emission rate values 
determined in the last 12 months.
    (iv) If you collect less than 21 days per monthly period of 
continuous data again in that same 12-month rolling average cycle, you 
must discard the data collected that month and replace that data with 
the highest individual monthly emission rate determined in the last 12 
months.
    (e) As an alternative to the CEMS required in paragraph (c) of this 
section, the owner or operator must monitor Hg emissions using Method 
324 in 40 CFR part 63, appendix A.
    (f) You must prepare and submit to the Administrator for approval a 
unit-specific monitoring plan for each monitoring system. You must 
comply with the requirements in your plan. The plan must address the 
requirements in paragraphs (f)(1) through (6) of this section.
    (1) Installation of the CMS sampling probe or other interface at a 
measurement location relative to each affected process unit such that 
the measurement is representative of control of the exhaust emissions 
(e.g., at or downstream of the last control device);
    (2) Performance and equipment specifications for the sample 
interface, the pollutant concentration or parametric signal analyzer, 
and the data collection and reduction systems;
    (3) Performance evaluation procedures and acceptance criteria 
(e.g., calibrations);
    (4) Ongoing operation and maintenance procedures in accordance with 
the general requirements of Sec. 63.8(c)(1), (3), and (4)(ii);
    (5) Ongoing data quality assurance procedures in accordance with 
the general requirements of Sec. 63.8(d); and
    (6) Ongoing recordkeeping and reporting procedures in accordance 
with the general requirements of Sec. 63.10(c), (e)(1) and (e)(2)(i).
    (g) Quarterly accuracy determinations and daily calibration drift 
tests for gaseous Hg CEMS shall be performed in accordance with 
Procedure 1 (appendix F of 40 CFR part 60). Annual relative accuracy 
test audits (RATAs) for Hg sorbent trap monitoring systems shall also 
be performed in accordance with Procedure 1.


Sec. 63.10009  How do I demonstrate initial compliance with the 
emissions limitations?

    (a) You must demonstrate initial compliance with each emission 
limitation in Sec. 63.9990 that applies to you according to Table 2 to 
this subpart.
    (b) If you elect to comply with an emissions limit using emissions 
averaging according to the requirements in Sec. 63.9992, you must 
demonstrate compliance with the emissions limit established for each 
emissions averaging group for the 12-month compliance period using 
Equation 1 of this section.
[GRAPHIC] [TIFF OMITTED] TP30JA04.012


Where:

AvH = Total Hg emitted for the 12-month compliance period, lb/MWh or 
lb/MMBtu;
Hi = Total mass of measured Hg from AvEL emissions averaging 
group i during the 12-month compliance period, lb;
Vi = Total volume of production from AvEL emissions 
averaging group i during 12-month compliance period, gross MWh 
generated or MMBtu heat input to the electric utility steam generating 
unit; and
n = Number of emission sources in the emissions averaging group or 
number of emission averaging groups.

    (c) If your affected electric utility steam generating unit is also 
a cogeneration unit, you must use the procedures in paragraphs (c)(1) 
and (2) of this section to calculate emission rates based on electrical 
output to the grid plus half of the equivalent electrical energy in the 
unit's process stream.
    (1) All conversions from Btu/hr unit input to MWe unit output must 
use equivalents found in 40 CFR part 60.40(a)(1) for electric utilities 
(i.e., 250 million Btu/hr input to an electric utility steam generating 
unit is equivalent to 73 MWe input to the electric utility steam 
generating unit); 73 MWe input to the electric utility steam generating 
unit is equivalent to 25 MWe output from the boiler electric utility 
steam generating unit; therefore, 250 million Btu input to the electric 
utility steam generating unit is equivalent to 25 MWe output from the 
electric utility steam generating unit).
    (2) You must use the Equation 2 of this section to determine the 
cogeneration Hg or Ni emission rate over a specific compliance period.
[GRAPHIC] [TIFF OMITTED] TP30JA04.013


[[Page 4724]]



Where:

ERcogen = Cogeneration Hg or Ni emission rate over a 
compliance period in lb/MWh (or lb Hg/TBtu);
E = Mass of Hg or Ni emitted from the stack over the same compliance 
period (lb Hg or lb Ni);
Vgrid = Amount of energy sent to the grid over the same 
compliance period (MWh or TBtu); and
Vprocess = Amount of energy converted to steam for process 
use over the same compliance period (MWh or TBtu).

    (d) If your coal-fired electric utility steam generating unit is 
subject to an Hg limit in Sec. 63.9990, you must determine initial 
compliance according to the applicable requirements in paragraphs 
(d)(1) through (4) of this section.
    (1) Begin compliance monitoring on the effective date of this 
subpart.
    (2) If you use a CEMS, determine the 12-month rolling average Hg 
emission rate according to the applicable procedures in paragraphs 
(d)(2)(i) through (iii) of this section.
    (i) Calculate the total mass of Hg emissions over a month (M), in 
micrograms ([mu]g), using Equation 3 of this section.
[GRAPHIC] [TIFF OMITTED] TP30JA04.014


Where:

M = Total mass of Hg emissions, ([mu]g);
C = Concentration of Hg recorded by CEMS per Performance Specification 
12A, micrograms per dry standard cubic meter ([mu]g/dscm);
V = Volumetric flow rate recorded at the same frequency as the CEMS 
reading for the Hg concentration indicated in Performance Specification 
12A, cubic meters per hour (dscm/hr); and
t = total time period over which mass measurements are collected, (hr).

    (ii) Calculate the Hg emission rate for an input-based limit (lb/
TBtu) using Equation 4 of this section.
[GRAPHIC] [TIFF OMITTED] TP30JA04.015


Where:

ER = Hg emission rate, (lb/TBtu);
M = Total mass of Hg emissions, micrograms ([mu]g);
Conversion factor = 2.205 x 10\-9\, used to convert micrograms to 
pounds; and
TPinput-based = Total power, (TBtu).

    (iii) Calculate the Hg emission rate for an output-based limit (lb/
MWh) using Equation 5 of this section:
[GRAPHIC] [TIFF OMITTED] TP30JA04.016


Where:

ER = Hg emission rate, (lb/MWh);
M = Total mass of Hg emissions, ([mu]g);
Conversion factor = 2.205 x 10\-9\; and
TPoutput-based = Total power, megawatt-hours (MWh).

    (3) If you use Method 324 (40 CFR part 63, appendix A), determine 
the 12-month rolling average Hg emission rate according to the 
applicable procedures in paragraphs (d)(3)(i) through (v) of this 
section.
    (i) Sum the Hg concentrations for the emission rate period, ([mu]g/
dscm).
    (ii) Calculate the total volumetric flow for the emission rate 
period, (dscm).
    (iii) Multiply the total Hg concentration times the total 
volumetric flow to obtain the total mass of Hg for the emissions rate 
period in micrograms.
    (iv) Calculate the Hg emissions rate for an input-based limit (lb/
TBtu) using Equation 4 of this section.
    (v) Calculate the Hg emissions rate for an output-based limit (lb/
MWh) using Equation 5 of this section.
    (4) Report the 12-month rolling average Hg emissions rate in the 
first semiannual compliance report.
    (e) If your oil-fired unit is subject to a Ni emissions limit in 
Sec. 63.9991, you must determine initial compliance using the 
applicable procedures in paragraphs (e)(1) through (3) of this section.
    (1) Begin compliance monitoring on the effective date of this 
subpart.
    (2) Use the applicable procedures in paragraphs (e)(2)(i) through 
(v) of this section to convert the Method 29 Ni measurement to the 
selected format.
    (i) Sum the Ni concentrations obtained from the Method 29 test 
runs, milligrams per dscm (mg/dscm).
    (ii) Calculate the total volumetric flow obtained during the Method 
29 test runs, (dscm).
    (iii) Multiply the total Ni concentration times the total 
volumetric flow for the duration of the initial compliance testing 
period to obtain the total mass of Ni in milligrams.
    (iv) Calculate the input-based Ni emissions rate in a lb/TBtu 
format using Equation 6 of this section.
[GRAPHIC] [TIFF OMITTED] TP30JA04.017


Where:

ER = Ni emissions rate, (lb/TBtu);
M = Total mass of Ni emissions, (mg);
Conversion factor = 2.205 x 10-6, used to convert milligrams 
to pounds; and
TPinput-based = Total power, (TBtu).

    (v) Calculate the output-based Ni emissions rate in a lb/MWh format 
using Equation 7 of this section.

[GRAPHIC] [TIFF OMITTED] TP30JA04.018


Where:

ER = Ni emissions rate, (lb/MWh);
M = Total mass of Ni emissions, (mg);
Conversion factor = 2.205 x 10-6 and
TPoutput-based = Total power, (MWH).
    (f) You must submit the Notification of Compliance Status report 
containing the results of the initial compliance demonstration 
according to the requirements in Sec. 63.10030(e).

Continuous Compliance Requirements


Sec. 63.10020  How do I monitor and collect data to demonstrate 
continuous compliance?

    (a) Except for monitor malfunctions, associated repairs, and 
required quality assurance or control activities (including, as 
applicable, calibration checks and required zero and span adjustments), 
you must monitor continuously (or collect data at all required 
intervals) at all times that the affected source is operating.
    (b) You may not use data recorded during monitoring malfunctions, 
associated repairs, or required quality assurance or control 
activities, in data averages and calculations used to report emission 
or operating levels. You must use all the data collected during all 
other periods in assessing the operation of the control device and 
associated control system.
    (c) A monitoring malfunction is any sudden, infrequent, not 
reasonably preventable failure of the monitoring system to provide 
valid data. Monitoring failures that are caused in part by poor 
maintenance or careless operation are not malfunctions. Any period for 
which the monitoring system is out-of-control and data are not 
available for required calculations constitutes a deviation from the 
monitoring requirements.


Sec. 63.10021  How do I demonstrate continuous compliance with the 
emissions limitations?

    (a) You must demonstrate continuous compliance with each emission 
limitation that applies to you according to the methods specified in 
Table 3 to this subpart.
    (b) During periods of startup, shutdown, and malfunction, you must 
operate in accordance with the startup, shutdown, and malfunction plan 
as required in Sec. 63.10000(f).
    (c) Consistent with Sec.Sec. 63.6(e) and 63.7(e)(1), deviations 
that occur during

[[Page 4725]]

a period of startup, shutdown, or malfunction are not violations if you 
demonstrate to the Administrator's satisfaction that you were operating 
in accordance with the startup, shutdown, and malfunction plan. The 
Administrator will determine whether deviations that occur during a 
period of startup, shutdown, or malfunction are violations, according 
to the provisions in Sec. 63.6(e).

Notification, Reports, and Records


Sec. 63.10030  What notifications must I submit and when?

    (a) You must submit all of the notifications in Sec.Sec. 63.6(h)(4) 
and (5), 63.7(b) and (c), 63.8(e), 63.8(f)(4) and (6), and 63.9(b) 
through (h) that apply to you by the dates specified. Except as 
provided in paragraph (f) of this section, if you comply with the 
requirements in Sec. 63.9991(b) for switching fuel, you must notify the 
Administrator in writing at least 30 days prior to using a fuel other 
than distillate oil.
    (b) As specified in Sec. 63.9(b)(2), if you operate an affected 
source before [DATE OF PUBLICATION OF THE FINAL RULE IN THE Federal 
Register], you must submit an Initial Notification not later than 120 
days after [DATE THE FINAL RULE IS PUBLISHED IN THE Federal Register]. 
The Initial Notification must include the information required in 
paragraphs (b)(1) through (4) of this section, as applicable.
    (1) The name and address of the owner or operator;
    (2) The address (i.e., physical location) of the affected source;
    (3) An identification of the relevant standard, or other 
requirement, that is the basis of the notification and the source's 
compliance date;
    (4) A brief description of the nature, size, design and method of 
operation of the source and an identification of the types of emission 
points within the affected source subject to the requirements and the 
Hg or Ni pollutant being emitted.
    (c) If you startup your new or reconstructed affected source on or 
after [DATE THE FINAL RULE IS PUBLISHED IN THE Federal Register], you 
must submit an Initial Notification not later than 120 days after you 
become subject to this subpart. The Initial Notification must include 
the information required in paragraphs (c)(1) through (4) of this 
section, as applicable.
    (1) The name and address of the owner or operator;
    (2) The address (i.e., physical location) of the affected source;
    (3) An identification of the relevant standard, or other 
requirement, that is the basis of the notification and the source's 
compliance date;
    (4) A brief description of the nature, size, design and method of 
operation of the source and an identification of the types of emission 
points within the affected source subject to the requirements and the 
Hg or Ni pollutant being emitted.
    (d) If you are required to conduct a performance test, you must 
submit a notification of intent to conduct a performance test at least 
60 days before the performance test is scheduled to begin as required 
in Sec. 63.7(b)(1).
    (e) If you are required to conduct a performance test or other 
initial compliance demonstration as specified in Sec. 63.10007, you 
must submit a Notification of Compliance Status report according to 
Sec. 63.9(h)(2)(ii) and the requirements specified in paragraphs (e)(1) 
through (3) of this section.
    (1) For each initial compliance demonstration, you must submit the 
Notification of Compliance Status report, including all performance 
test results, before the close of business on the 60th day following 
the completion of the performance test and/or other initial compliance 
demonstrations according to Sec. 63.10(d)(2).
    (2) The Notification of Compliance Status report must contain all 
the information specified in paragraphs (e)(2)(i) through (iv) of this 
section, as applicable.
    (i) A description of the affected source(s) including 
identification of which subcategory the source is in, the capacity of 
the source, a description of the add-on controls used on the source 
description of the fuel(s) burned, and justification for the worst-case 
fuel burned during the performance test.
    (ii) Summary of the results of all performance tests, fuel 
analyses, and calculations conducted to demonstrate initial compliance 
including all established operating limits.
    (iii) A signed certification that you have met all applicable 
emissions limitations, including any emission limitation for an 
emissions averaging group.
    (iv) If you had a deviation from any emission limitation, you must 
also submit a description of the deviation, the duration of the 
deviation, and the corrective action taken in the Notification of 
Compliance Status report.
    (f) If you comply with the requirements in Sec. 63.9991(b) by using 
distillate fuel, and you must switch fuel because of an emergency, you 
must notify the Administrator in writing within 30 days of using a fuel 
other than distillate oil.


Sec. 63.10031  What reports must I submit and when?

    (a) Compliance report due dates. Unless the Administrator has 
approved a different schedule for submission of reports under Sec. 
63.10(a), you must submit a semiannual compliance report to the 
permitting authority according to the requirements in paragraphs (a)(1) 
through (5) of this section.
    (1) The first compliance report must cover the period beginning on 
the compliance date that is specified for your affected source in Sec. 
63.9983 and ending on June 30 or December 31, whichever date comes 
first after the compliance date that is specified for your affected 
source in Sec. 63.9983.
    (2) The first compliance report must be postmarked or delivered no 
later than July 31 or January 31, whichever date comes first after the 
first compliance report is due.
    (3) Each subsequent compliance report must cover the semiannual 
reporting period from January 1 through June 30 or the semiannual 
reporting period from July 1 through December 31.
    (4) Each subsequent compliance report must be postmarked or 
delivered no later than July 31 or January 31, whichever date comes 
first after the end of the semiannual reporting period.
    (5) For each affected source that is subject to permitting 
regulations pursuant to 40 CFR part 70 or 40 CFR part 71, and if the 
permitting authority has established dates for submitting semiannual 
reports pursuant to 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR 
71.6(a)(3)(iii)(A), you may submit the first and subsequent compliance 
reports according to the dates the permitting authority has established 
instead of according to the dates in paragraphs (a)(1) through (4) of 
this section.
    (b) Compliance report contents. The compliance report must contain 
the information required in paragraphs (b)(1) through (5) of this 
section and, as applicable, paragraphs (b)(6) through (10) of this 
section.
    (1) Company name and address.
    (2) Statement by a responsible official with that official's name, 
title, and signature, certifying the truth, accuracy, and completeness 
of the content of the report.
    (3) Date of report and beginning and ending dates of the reporting 
period.
    (4) A summary of the results of the annual performance tests and 
documentation of any operating limits that were reestablished during 
this test, if applicable.

[[Page 4726]]

    (5) If you had a startup, shutdown, or malfunction during the 
reporting period and you took actions consistent with your SSMP, the 
compliance report must include the information in Sec. 63.10(d)(5)(i).
    (6) If there are no deviations from any emission limitation 
(emissions limit or operating limit) in this subpart that apply to you, 
a statement that there were no deviations from the emissions 
limitations during the reporting period.
    (7) If there were no periods during which a CMS, including CEMS or 
CPMS, was out-of-control as specified in Sec. 63.8(c)(7), a statement 
that there were no periods during which the CMS were out-of-control 
during the reporting period.
    (8) For each deviation from an emission limitation (emissions limit 
or operating limit) in this subpart that occurs at an affected source 
where you are not using a CMS to comply with that emission limitation, 
the compliance report must contain the information in paragraphs 
(b)(8)(i) through (iii) of this section. This includes periods of 
startup, shutdown, and malfunction.
    (i) The total operating time of each affected source during the 
reporting period.
    (ii) Information on the number, duration, and cause of the 
deviation (including unknown cause) as applicable and the corrective 
action taken.
    (iii) A copy of the test report if the annual performance test 
showed a deviation from the Ni emissions limit or a deviation from the 
Hg emissions limit.
    (9) For each deviation from an emission limitation (emissions limit 
or operating limit) in this subpart occurring at an affected source 
where you are using a CMS to comply with that emission limitation, you 
must include the information in paragraphs (b)(9)(i) through (xii) of 
this section. This includes periods of startup, shutdown, and 
malfunction and any deviations from your unit-specific monitoring plan 
as required in Sec. 63.10000(c).
    (i) The date and time that each malfunction started and stopped and 
description of the nature of the deviation (i.e., what you deviated 
from).
    (ii) The date and time that each CMS was inoperative, except for 
zero (low-level) and high-level checks.
    (iii) The date, time, and duration that each CMS was out-of-
control, including the information in Sec. 63.8(c)(8).
    (iv) The date and time that each deviation started and stopped, and 
whether each deviation occurred during a period of startup, shutdown, 
or malfunction or during another period.
    (v) A summary of the total duration of the deviation during the 
reporting period and the total duration as a percent of the total 
source operating time during that reporting period.
    (vi) A breakdown of the total duration of the deviations during the 
reporting period into those that are due to startup, shutdown, control 
equipment problems, process problems, other known causes, and other 
unknown causes.
    (vii) A summary of the total duration of CMS downtime during the 
reporting period and the total duration of CMS downtime as a percent of 
the total source operating time during that reporting period.
    (viii) An identification of each parameter that was monitored at 
the affected source for which there was a deviation, including opacity, 
carbon monoxide, and operating parameters for wet scrubbers and other 
control devices.
    (ix) A brief description of the source for which there was a 
deviation.
    (x) A brief description of each CMS for which there was a 
deviation.
    (xi) The date of the latest CMS certification or audit for the 
system for which there was a deviation.
    (xii) A description of any changes in CMS, processes, or controls 
since the last reporting period for the source for which there was a 
deviation.
    (10) A statement that each emissions averaging group was in 
compliance with its applicable limit during the semiannual reporting 
period.
    (c) Immediate startup, shutdown, and malfunction report. If you had 
a startup, shutdown, or malfunction during the semiannual reporting 
period that was not consistent with your SSMP, you must submit an 
immediate startup, shutdown, and malfunction report according to the 
requirements of Sec. 63.10(d)(5)(ii).
    (d) Part 70 monitoring report. Each affected source that has 
obtained a title V operating permit pursuant to 40 CFR part 70 or 40 
CFR part 71 must report all deviations as defined in this subpart in 
the semiannual monitoring report required by 40 CFR 70.6(a)(3)(iii)(A) 
or 40 CFR 71.6(a)(3)(iii)(A). If an affected source submits a 
compliance report along with, or as part of, the semiannual monitoring 
report required by 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR 
71.6(a)(3)(iii)(A), and the compliance report includes all required 
information concerning deviations from any emission limitation 
(including any operating limit), submission of the compliance report 
satisfies any obligation to report the same deviations in the 
semiannual monitoring report. However, submission of a compliance 
report does not otherwise affect any obligation the affected source may 
have to report deviations from permit requirements to the permitting 
authority.


Sec. 63.10032  What records must I keep?

    (a) You must keep records according to paragraphs (a)(1) through 
(3) of this section.
    (1) A copy of each notification and report that you submitted to 
comply with this subpart, including all documentation supporting any 
Initial Notification or Notification of Compliance Status or semiannual 
compliance report that you submitted, according to the requirements in 
Sec. 63.10(b)(2)(xiv).
    (2) The records in Sec. 63.6(e)(3)(iii) through (v) related to 
startup, shutdown, and malfunction.
    (3) Records of performance tests or other compliance demonstrations 
and performance evaluations as required in Sec. 63.10(b)(2)(viii).
    (b) For each monitoring system required by this subpart, you must 
keep records according to paragraphs (b)(1) through (4) of this 
section.
    (1) Records described in Sec. 63.10(b)(2)(vi) through (xi).
    (2) Previous (i.e., superseded) versions of the performance 
evaluation plan as required in Sec. 63.8(d)(3).
    (3) Request for alternatives to relative accuracy test for CEMS as 
required in Sec. 63.8(f)(6)(i).
    (4) Records of the date and time that each deviation started and 
stopped, and whether the deviation occurred during a period of startup, 
shutdown, or malfunction or during another period.
    (c) You must keep the records required in Table 3 to this subpart 
including records of all monitoring data to show continuous compliance 
with each emission limitation that applies to you.


Sec. 63.10033  In what form and how long must I keep my records?

    (a) Your records must be in a form suitable and readily available 
for expeditious review, according to Sec. 63.10(b)(1).
    (b) As specified in Sec. 63.10(b)(1), you must keep each record for 
5 years following the date of each occurrence, measurement, 
maintenance, corrective action, report, or record.
    (c) You must keep each record on site for at least 2 years after 
the date of each occurrence, measurement, maintenance, corrective 
action, report, or record, according to Sec. 63.10(b)(1). You can keep 
the records offsite for the remaining 3 years.

[[Page 4727]]

Other Requirements and Information


Sec. 63.10040  What parts of the General Provisions apply to me?

    Table 4 to this subpart shows which parts of the General Provisions 
in Sec.Sec. 63.1 through 63.15 apply to you.


Sec. 63.10041  Who implements and enforces this subpart?

    (a) This subpart can be implemented and enforced by the U.S. 
Environmental Protection Agency (U.S. EPA), or a delegated authority 
such as your State, local, or tribal agency. If the Administrator has 
delegated authority to your State, local, or tribal agency, then that 
agency has the authority to implement and enforce this subpart. You 
should contact your EPA Regional Office to find out if this subpart is 
delegated to your State, local, or tribal agency.
    (b) In delegating implementation and enforcement authority to this 
subpart to a State, local, or tribal agency under 40 CFR part 63, 
subpart E, the authorities contained in paragraph (c) of this section 
are retained by the Administrator and are not transferred to the State, 
local, or tribal agency. The U.S. EPA retains oversight of this subpart 
and can take enforcement actions, as appropriate.
    (c) The authorities that will not be delegated to State, local, or 
tribal agencies are listed in paragraphs (c)(1) through (5) of this 
section.
    (1) Approval of alternatives to the non-opacity emission limits in 
63.9990(a) through (g) under Sec. 63.6(g).
    (2) Approval of major alternatives to test methods under Sec. 
63.7(e)(2)(ii) and (f) and as defined in Sec. 63.90.
    (3) Approval of major alternatives to monitoring under Sec. 63.8(f) 
and as defined in Sec. 63.90.
    (4) Approval of major alternatives to recordkeeping and reporting 
under Sec. 63.10(f) and as defined in Sec. 63.90.
    (5) Approval of the unit-specific monitoring plan under Sec. 
63.10000(c).


Sec. 63.10042  What definitions apply to this subpart?

    Terms used in this subpart are defined in the Clean Air Act, in 
Sec. 63.2, and in this section as follows:
    Anthracite coal means solid fossil fuel classified as anthracite 
coal by ASTM Designation D388-77, 90, 91, 95, or 98a (incorporated by 
reference--see 40 CFR 60.17).
    Bituminous coal means solid fossil fuel classified as bituminous 
coal by ASTM D388-77, 90, 91, 95, or 98a (incorporated by reference--
see 40 CFR 60.17).
    Coal means all solid fossil fuels classified as anthracite, 
bituminous, subbituminous, or lignite by ASTM Designation D388-77, 90, 
91, 95, or 98a (incorporated by reference--see 40 CFR 60.17).
    Coal refuse means 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.
    Coal-fired electric utility steam generating unit means an electric 
utility steam generating unit that burns coal, coal refuse, or a 
synthetic gas derived from coal either exclusively, in any combination 
together, or in any combination with other supplemental fuels. Examples 
of supplemental fuels include, but are not limited to, petroleum coke 
and tire-derived fuels.
    Combined-cycle gas turbine means a stationary turbine combustion 
system where heat from the turbine exhaust gases is recovered by a 
waste heat boiler.
    Deviation means any instance in which an affected source subject to 
this subpart, or an owner or operator of such a source:
    (1) Fails to meet any requirement or obligation established by this 
subpart including, but not limited to, any emission limitation 
(including any operating limit) or work practice standard;
    (2) Fails to meet any term or condition that is adopted to 
implement an applicable requirement in this subpart and that is 
included in the operating permit for any affected source required to 
obtain such a permit; or
    (3) Fails to meet any emission limitation (including any operating 
limit) or work practice standard in this subpart during startup, 
shutdown, or malfunction, regardless of whether or not such failure is 
permitted by this subpart.
    Distillate oil means fuel oils that contain 0.05 weight percent 
nitrogen or less and comply with the specifications for fuel oil 
numbers 1 and 2, as defined by the American Society of Testing and 
Materials in ASTM D396-78, 89, 90, 92, 96, or 98, Standard 
Specifications for Fuel Oils (incorporated by reference--see 40 CFR 
60.17).
    Electric utility steam generating unit means any 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 considered an electric 
utility steam generating unit.
    Electrostatic precipitator means an add-on air pollution control 
device used to capture particulate matter by charging the particles 
using an electrostatic field, collecting the particles using a grounded 
collecting surface, and transporting the particles into a hopper.
    Emission limitation means any emissions limit or operating limit.
    Federally enforceable means all limitations and conditions that are 
enforceable by the Administrator, including the requirements of 40 CFR 
parts 60 and 61, requirements within any applicable State 
implementation plan, and any permit requirements established under 40 
CFR 52.21 or Sec.Sec. 51.18 and 51.24.
    Fossil fuel means natural gas, petroleum, coal, and any form of 
solid, liquid, or gaseous fuel derived from such material for the 
purpose of creating useful heat.
    Integrated gasification combined cycle (IGCC) electric utility 
steam generating unit means a coal-fired electric utility steam 
generating unit that burns a synthetic gas derived from coal in a 
combined-cycle gas turbine. No coal is directly burned in the unit 
during operation.
    Lignite means solid fossil fuel classified as lignite coal by ASTM 
D388-77, 90, 91, 95, or 98a (incorporated by reference--see 40 CFR 
60.17).
    Oil means crude oil or petroleum or a liquid fuel derived from 
crude oil or petroleum, including distillate and residual oil.
    Oil-fired electric utility steam generating unit means an electric 
utility steam generating unit that either burns oil exclusively, or 
burns oil alternately with burning fuels other than oil at other times.
    Residual oil means crude oil, fuel oil numbers 1 and 2 that have a 
nitrogen content greater than 0.05 weight percent, and all fuel oil 
numbers 4, 5 and 6, as defined by the American Society of Testing and 
Materials in ASTM D396-78, Standard Specifications for Fuel Oils 
(incorporated by reference--see 40 CFR 60.17).
    Responsible official means responsible official as defined in 40 
CFR 70.2.
    Steam generating unit means any furnace, boiler, or other device 
used for combusting fuel for the purpose of producing steam (including 
fossil-fuel fired steam generators associated with combined-cycle gas 
turbines; nuclear steam generators are not included).
    Subbituminous coal means solid fossil fuel that is classified as 
subbituminous A, B, or C according to

[[Page 4728]]

the American Society of Testing and Materials (ASTM) Standard 
Specification for Classification of Coals by Rank D388-77 (incorporated 
by reference--see 40 CFR 60.17).

Tables to Subpart UUUUU of Part 63

    As stated in Sec. 63.10007, you must comply with the following 
requirements for performance tests:

                Table 1 to Subpart UUUUU of Part 63.--Performance Test Requirements for Ni and Hg
----------------------------------------------------------------------------------------------------------------
                                                                                            According to the
  For each affected source . . .         You must . . .        Using this method . . .  following requirements .
                                                                                                   . .
----------------------------------------------------------------------------------------------------------------
1. Subject to Ni emissions limit.  a. Select sampling port    Method 1 or 1A (40 CFR    Sampling sites must be
                                    locations and number of    part 60, appendix A).     located at the outlet
                                    traverse points in each                              of the control device
                                    stack or duct.                                       (or at the outlet of
                                                                                         the emissions source if
                                                                                         no control device is
                                                                                         present) prior to any
                                                                                         releases to the
                                                                                         atmosphere.
                                   b. Determine the           Method 2, 2A, 2C, 2D,
                                    volumetric flow rate of    2F, or 2G (40 CFR part
                                    the stack gas.             60, appendix A).
                                   c. Determine the dry       Method 3A or 3B (40 CFR
                                    molecular weight of the    part 60, appendix A).
                                    stack gas.
                                   d. Determine the moisture  Method 4 (40 CFR part
                                    content of the stack gas.  60, appendix A).
                                   e. Determine the Ni        Method 29 (40 CFR part
                                    concentration.             60, appendix A) for Ni.
2. Subject to Ni emissions limit   Establish operating        Data from the current     (1) Collect secondary
 and that use an ESP.               limits for minimum         and voltage monitors      current and voltage or
                                    voltage and secondary      for the ESP and the Ni    total power input for
                                    current or total power     performance test.         the ESP every 15
                                    input.                                               minutes during the
                                                                                         entire period of the
                                                                                         three-run Ni
                                                                                         performance test.
                                                                                        (2) Determine the
                                                                                         average secondary
                                                                                         current and voltage or
                                                                                         total power input by
                                                                                         computing the average
                                                                                         of all 15 minute
                                                                                         readings taken during
                                                                                         each test run. You must
                                                                                         set the minimum
                                                                                         operating limits equal
                                                                                         to the minimum 1-hour
                                                                                         average values measured
                                                                                         during the three-run
                                                                                         performance test.
----------------------------------------------------------------------------------------------------------------

    As stated in Sec. 63.10009, you must show initial compliance with 
the emissions limitations according to the following:

 Table 2 to Subpart UUUUU of Part 63.--Initial Compliance With Emissions
                        Limitations for Ni and Hg
------------------------------------------------------------------------
                                                          You have
          For . . .            That is controlled   demonstrated initial
                                   with . . .        compliance if . . .
------------------------------------------------------------------------
1. Each oil-fired unit        Electrostatic         i. The average Ni
 subject to a Ni emissions     precipitator (ESP).   emissions in lb/
 limit in Sec. 63.9991.                              TBtu or lb/MWH over
                                                     the three-run
                                                     performance test do
                                                     not exceed the
                                                     applicable
                                                     emissions limit.
                                                    ii. You have a
                                                     record of the
                                                     average secondary
                                                     current and voltage
                                                     or total power
                                                     input of the ESP
                                                     for each test run
                                                     over the three-run
                                                     performance test
                                                     during which the Ni
                                                     emissions did not
                                                     exceed the
                                                     applicable limit.
2. Each oil-fired unit        Any type............  i. You submit a
 subject to alternative                              signed
 standard in Sec. 63.9991(b)                         certification in
 for fuel switching.                                 the Notification of
                                                     Compliance Status
                                                     report that you
                                                     burn only
                                                     distillate oil as
                                                     the fuel in your
                                                     unit.
                                                    ii. You have records
                                                     demonstrating that
                                                     you burn only
                                                     distillate oil as
                                                     the fuel in your
                                                     unit.
3. Each coal-fired unit       Any.................  You have established
 subject to Hg emissions                             a site specific Hg
 limit in Sec. 63.9990.                              limit according to
                                                     the procedures in
                                                     Sec. 63.10009 and
                                                     reported the limit
                                                     in your
                                                     Notification of
                                                     Compliance Status.
------------------------------------------------------------------------


[[Page 4729]]

    As stated in Sec. 63.10021, you must show continuous compliance 
with the emissions limitations according to the following:

     Table 3 to Subpart UUUUU of Part 63--Continuous Compliance with
                   Emissions Limitations for Hg and Ni
------------------------------------------------------------------------
                                                    You must demonstrate
                               That is controlled        continuous
          For . . .                with . . .        compliance by . . .
 
------------------------------------------------------------------------
i. Each unit subject to Hg    Any type............  i. Continuously
 emissions limit in Sec.                             monitoring the
 63.9990.                                            hourly average Hg
                                                     emissions using a
                                                     CEMS or monitoring
                                                     and recording the
                                                     Hg measurements by
                                                     semicontinous
                                                     method.
                                                    ii. Collecting and
                                                     reducing the
                                                     monitoring data
                                                     according to Sec.
                                                     63.100.20.
                                                    iii. Calculating for
                                                     each month the
                                                     monthly rolling
                                                     average emissions.
                                                    iv. Maintaining the
                                                     12-month rolling
                                                     average at or below
                                                     the applicable
                                                     limit.
2. Each unit subject to Ni    Electrostatic         i. Collecting and
 limit in Sec. 63.9991.        precipitator.         reducing the
                                                     secondary current
                                                     and voltage (or
                                                     total power input)
                                                     monitoring data.
                                                    ii. Maintaining the
                                                     hoursly average
                                                     secondary current
                                                     and voltage or
                                                     total power input
                                                     at or above the
                                                     limits established
                                                     in the performance
                                                     test.
                                                    iii. Conducting
                                                     performance tests
                                                     at least once per
                                                     year and reporting
                                                     the results in the
                                                     semiannual
                                                     compliance report.
3. Each unit subject to       Any type............  i. Submitting
 alternative standard for                            written
 distillate fuel switching                           certifications with
 in Sec. 63.9991(b).                                 each semiannual
                                                     compliance report
                                                     according to the
                                                     requirements in
                                                     Sec. 63.10031(b)
                                                     and keeping records
                                                     of fuel burned to
                                                     document
                                                     compliance.
                                                    ii. Notifying the
                                                     Adminsitrator if
                                                     resume burning fuel
                                                     other than
                                                     distillate oil
                                                     according to the
                                                     requirements in
                                                     Sec. 63.10030(a).
                                                    iii. If at any time
                                                     the unit does not
                                                     meet the
                                                     alternative limit,
                                                     the owner or
                                                     operator must
                                                     immediately comply
                                                     with the applicable
                                                     Ni limit, including
                                                     all initial and
                                                     continuous
                                                     compliance
                                                     requirements.
------------------------------------------------------------------------

    As stated in Sec. 63.10040, you must comply with the applicable 
General Provisions according to the following:

            Table 4 to Subpart UUUUU of Part 63--Applicability of General Provisions to Subpart UUUUU
----------------------------------------------------------------------------------------------------------------
             Citation                         Subject                Brief description            Comments
----------------------------------------------------------------------------------------------------------------
Sec. 63.1.........................  Applicability.............  Initial Applicability       Yes.
                                                                 Determination;
                                                                 Applicability After
                                                                 Standard Established;
                                                                 Permit Requirements;
                                                                 Extensions, Notifications.
Sec. 63.2.........................  Definitions...............  Definitions for part 63     Yes.
                                                                 standards.
Sec. 63.3.........................  Units and Abbreviations...  Units and abbreviations     Yes.
                                                                 for part 63 standards.
Sec. 63.4.........................  Prohibited Activities.....  Prohibited Activities;      Yes.
                                                                 Compliance date;
                                                                 Circumvention,
                                                                 Severability.
Sec. 63.5.........................  Construction/               Applicability;              Yes.
                                     Reconstruction.             applications; approvals.
Sec. 63.6(a)......................  Applicability.............  GP apply unless compliance  Yes.
                                                                 extension and GP apply to
                                                                 area sources that become
                                                                 major.
Sec. 63.6(b)(1)-(4)...............  Compliance Dates for New    Standards apply at          Yes.
                                     and Reconstructed sources.  effective date; 3 years
                                                                 after effective date;
                                                                 upon startup; 10 years
                                                                 after construction or
                                                                 reconstruction commences
                                                                 for 112(f).
Sec. 63.6(b)(5)...................  Notification..............  Must notify if commenced    Yes.
                                                                 construction or
                                                                 reconstruction after
                                                                 proposal.
Sec. 63.6(b)(6)...................  [Reserved]................

[[Page 4730]]

 
Sec. 63.6(b)(7)...................  Compliance Dates for New    Area sources that become    Yes.
                                     and Reconstructed Area      major must comply with
                                     Sources That Become Major.  major source standards
                                                                 immediately upon becoming
                                                                 major, regardless of
                                                                 whether required to
                                                                 comply when they were an
                                                                 area source.
Sec. 63.6(c)(1)-(2)...............  Compliance Dates for        Comply according to date    Yes.
                                     Existing Sources.           in subpart, which must be
                                                                 no later than 3 years
                                                                 after effective date and
                                                                 for 112(f) standards,
                                                                 comply within 90 days of
                                                                 effective date unless
                                                                 compliance extension.
Sec. 63.6(c)(3)-(4)...............  [Reserved]................
Sec. 63.6(c)(5)...................  Compliance Dates for        Area sources that become    Yes.
                                     Existing Area Sources       major must comply with
                                     That Become Major.          major source standards by
                                                                 date indicated in subpart
                                                                 or by equivalent time
                                                                 period (for example, 3
                                                                 years).
Sec. 63.6(d)......................  [Reserved]................
Sec. 63.6(e)(1)-(2)...............  Operation & Maintenance...  Operate to minimize         Yes.
                                                                 emissions at all times.
                                                                AND.......................
                                                                Correct malfunctions as
                                                                 soon as practicable.
                                                                AND.......................
                                                                Operation and maintenance
                                                                 requirements
                                                                 independently enforceable
                                                                 information Administrator
                                                                 will use to determine if
                                                                 operation and maintenance
                                                                 requirements were met.
Sec. 63.6(e)(3)...................  Startup, Shutdown, and       Requirement for SSM and    Yes.
                                     Malfunction Plan (SSMP).    startup, shutdown,
                                                                 malfunction plan.
                                                                Content of SSMP...........
Sec. 63.6(f)(1)...................  Compliance Except During    Comply with emission        Yes.
                                     SSM.                        standards at all times
                                                                 except during SSM.
Sec. 63.6(f)(2)-(3)...............  Methods for Determining     Compliance based on         Yes.
                                     Compliance.                 performance test,
                                                                 operation and maintenance
                                                                 plans, records,
                                                                 inspection.
Sec. 63.6(g)(1)-(3)...............  Alternative Standard......  Procedures for getting an   Yes.
                                                                 alternative standard.
Sec. 63.6(h)(1)...................  Compliance with Opacity/VE  Comply with opacity/VE      No.
                                     Standards.                  emissions limitations at
                                                                 all times except during
                                                                 SSM.
Sec. 63.6(h)(2)(i)................  Determining Compliance      If standard does not state  No.
                                     with Opacity/Visible        test method, use Method 9
                                     Emission (VE) Standards.    for opacity and Method 22
                                                                 for VE.
Sec. 63.6(h)(2)(ii)...............  [Reserved]................
Sec. 63.6(h)(2)(iii)..............  Using Previous Tests to     Criteria for when previous  No.
                                     Demonstrate Compliance      opacity/VE testing can be
                                     with Opacity/VE Standards.  used to show compliance
                                                                 with this rule.
Sec. 63.6(h)(3)...................  [Reserved]................
Sec. 63.6(h)(4)...................  Notification of Opacity/VE  Notify Administrator of     No.
                                     Observation Date.           anticipated date of
                                                                 observation.
Sec. 63.6(h)(5)(i), (iii)-(v).....  Conducting Opacity/VE       Dates and Schedule for      No.
                                     Observations.               conducting opacity/VE
                                                                 observations.
Sec. 63.6(h)(5)(ii)...............  Opacity Test Duration and   Must have at least 3 hours  No.
                                     Averaging Times.            of observation with
                                                                 thirty, 6-minute averages.
Sec. 63.6(h)(6)...................  Records of Conditions       Keep records available and  No.
                                     During Opacity/VE           allow Administrator to
                                     observations.               inspect.
Sec. 63.6(h)(7)(i)................  Report continuous opacity   Submit continuous opacity   No.
                                     monitoring system data      monitoring system data
                                     monitoring data from        with other performance
                                     performance test.           test.
Sec. 63.6(h)(7)(ii)...............  Using continuous opacity    Can submit continuous       No.
                                     monitoring system instead   opacity monitoring system
                                     of Method 9.                data instead of Method 9
                                                                 results even if rule
                                                                 requires Method 9, but
                                                                 must notify Administrator
                                                                 before performance test.
Sec. 63.6(h)(7)(iii)..............  Averaging time for          To determine compliance,    No.
                                     continuous opacity          must reduce continuous
                                     monitoring system during    opacity monitoring system
                                     performance test.           data to 6-minute averages.

[[Page 4731]]

 
Sec. 63.6(h)(7)(iv)...............  Continuous opacity          Demonstrate that            No.
                                     monitoring system           continuous opacity
                                     requirements.               monitoring system
                                                                 performance evaluations
                                                                 are conducted according
                                                                 to Sec.Sec. 63.8(e),
                                                                 continuous opacity
                                                                 monitoring system are
                                                                 properly maintained and
                                                                 operated according to
                                                                 63.8(c) and data quality
                                                                 as Sec. 63.8(d).
Sec. 63.6(h)(7)(v)................  Determining Compliance      Continuous opacity          No.
                                     with Opacity/VE Standards.  monitoring system is
                                                                 probative but not
                                                                 conclusive evidence of
                                                                 compliance with opacity
                                                                 standard, even if Method
                                                                 9 observation shows
                                                                 otherwise. Requirements
                                                                 for continuous opacity
                                                                 monitoring system to be
                                                                 probative evidence-proper
                                                                 maintenance, meeting PS
                                                                 1, and data have not been
                                                                 altered.
Sec. 63.6(h)(8)...................  Determining Compliance      Administrator will use all  No.
                                     with Opacity/VE Standards.  continuous opacity
                                                                 monitoring system, Method
                                                                 9, and Method 22 results,
                                                                 as well as information
                                                                 about operation and
                                                                 maintenance to determine
                                                                 compliance.
Sec. 63.6(h)(9)...................  Adjusted Opacity Standard.  Procedures for              No.
                                                                 Administrator to adjust
                                                                 an opacity standard.
Sec. 63.6(i)(1)-(14)..............  Compliance Extension......  Procedures and criteria     Yes.
                                                                 for Administrator to
                                                                 grant compliance
                                                                 extension.
Sec. 63.6(j)......................  Presidential Compliance     President may exempt        Yes.
                                     Exemption.                  source category from
                                                                 requirement to comply
                                                                 with rule.
Sec. 63.7(a)(1)...................  Performance Test Dates....  Dates for Conducting        Yes.
                                                                 Initial Performance
                                                                 Testing and Other
                                                                 Compliance Demonstrations.
Sec. 63.7(a)(2)(i)................  Performance Test Dates....  New source with initial     Yes.
                                                                 startup date before
                                                                 effective date has 180
                                                                 days after effective date
                                                                 to demonstrate compliance.
Sec. 63.7(a)(2)(ii)...............  Performance Test Dates....  New source with initial     Yes.
                                                                 startup date after
                                                                 effective date has 180
                                                                 days after initial
                                                                 startup date to
                                                                 demonstrate compliance.
Sec. 63.7(a)(2)(iii)..............  Performance Test Dates....  Existing source subject to  Yes.
                                                                 standard established
                                                                 pursuant to 112(d) has
                                                                 180 days after compliance
                                                                 date to demonstrate
                                                                 compliance.
                                                                AND.......................
                                                                Existing source with        Yes.
                                                                 startup date after
                                                                 effective date has 180
                                                                 days after startup to
                                                                 demonstrate compliance.
Sec. 63.7(a)(2)(iv)...............  Performance Test Dates....  Existing source subject to  No.
                                                                 standard established
                                                                 pursuant to 112(f) has
                                                                 180 days after compliance
                                                                 date to demonstrate
                                                                 compliance.
Sec. 63.7(a)(2)(v)................  Performance Test Dates....  Existing source that        Yes.
                                                                 applied for extension of
                                                                 compliance has 180 days
                                                                 after termination date of
                                                                 extension to demonstrate
                                                                 compliance.
Sec. 63.7(a)(2)(vi)...............  Performance Test Dates....  New source subject to       No.
                                                                 standard established
                                                                 pursuant to 112(f) that
                                                                 commenced construction
                                                                 after proposal date of
                                                                 112(d) standard but
                                                                 before proposal date of
                                                                 112(f) standard, has 180
                                                                 days after compliance
                                                                 date to demonstrate
                                                                 compliance.
Sec. 63.7(a)(2)(vii-viii).........  [Reserved]................

[[Page 4732]]

 
Sec. 63.7(a)(2)(ix)...............  Performance Test Dates....  New source that commenced   Yes.
                                                                 construction between
                                                                 proposal and promulgation
                                                                 dates, when promulgated
                                                                 standard is more
                                                                 stringent than proposed
                                                                 standard, has 180 days
                                                                 after effective date or
                                                                 180 days after startup of
                                                                 source, whichever is
                                                                 later, to demonstrate
                                                                 compliance.
                                                                AND.......................
                                                                If source initially
                                                                 demonstrates compliance
                                                                 with less stringent
                                                                 proposed standard, it has
                                                                 3 years and 180 days
                                                                 after the effective date
                                                                 of the standard or 180
                                                                 days after startup of
                                                                 source, whichever is
                                                                 later, to demonstrate
                                                                 compliance with
                                                                 promulgated standard.
Sec. 63.7(a)(3)...................  Section 114 Authority.....  Administrator may require   Yes.
                                                                 a performance test under
                                                                 Act Section 114 at any
                                                                 time.
Sec. 63.7(b)(1)...................  Notification of             Must notify Administrator   Yes.
                                     Performance Test.           60 days before the test.
Sec. 63.7(b)(2)...................  Notification of             If rescheduling a           Yes.
                                     Rescheduling.               performance test is
                                                                 necessary, must notify
                                                                 Administrator 5 days
                                                                 before scheduled date of
                                                                 rescheduled date.
Sec. 63.7(c)......................  Quality Assurance/Test      Requirement to submit unit  Yes.
                                     Plan.                       specific test plan 60
                                                                 days before the test or
                                                                 on date Administrator
                                                                 agrees with:
                                                                Test plan approval
                                                                 procedures.
                                                                AND.......................
                                                                Performance audit
                                                                 requirements.
                                                                AND.......................
                                                                Internal and External QA
                                                                 procedures for testing.
Sec. 63.7(d)......................  Testing Facilities........  Requirements for testing    Yes.
                                                                 facilities.
Sec. 63.7(e)(1)...................  Conditions for Conducting   Perfomance tests must be    Yes.
                                     Performance Tests.          conducted under
                                                                 representative conditions.
                                                                AND
                                                                Cannot conduct performance  Yes.
                                                                 tests during SSMs.
                                                                AND.......................
                                                                Not a deviation to exceed   Yes.
                                                                 standard during SSM
                                                                AND.......................
                                                                Upon request of             Yes.
                                                                 Administrator, make
                                                                 available records
                                                                 necessary to determine
                                                                 conditions of performance
                                                                 tests.
Sec. 63.7(e)(2)...................  Conditions for Conducting   Must conduct according to   Yes.
                                     Performance Tests.          rule and EPA test methods
                                                                 unless Administrator
                                                                 approves alternative.
Sec. 63.7(e)(3)...................  Test Run Duration.........  Must have three separate    Yes.
                                                                 test runs.
                                                                AND.......................
                                                                Compliance is based on
                                                                 arithmetic mean of three
                                                                 runs.
                                                                AND.......................
                                                                Conditions when data from
                                                                 an additional test run
                                                                 can be used.
Sec. 63.7(f)......................  Alternative Test Method...  Procedures by which         Yes.
                                                                 Administrator can grant
                                                                 approval to use an
                                                                 alternative test method.
Sec. 63.7(g)......................  Performance Test Data       Must include raw data in    Yes.
                                     Analysis.                   performance test report.
                                                                AND.......................
                                                                Must submit performance
                                                                 test data 60 days after
                                                                 end of test with the
                                                                 Notification of
                                                                 Compliance Status.
                                                                AND.......................
                                                                Keep data for 5 years.....
Sec. 63.7(h)......................  Waiver of Tests...........  Procedures for              Yes.
                                                                 Administrator to waive
                                                                 performance test.

[[Page 4733]]

 
Sec. 63.7(a)(1)...................  Applicability of            Subject to all monitoring   Yes.
                                     Monitoring Requirements.    requirements in standard.
Sec. 63.8(a)(2)...................  Performance Specifications  Performance Specifications  Yes.
                                                                 in appendix B of part 60
                                                                 apply.
Sec. 63.8(a)(3)...................  [Reserved]................
Sec. 63.8(a)(4)...................  Monitoring with Flares....  Unless your rule says       No.
                                                                 otherwise, the
                                                                 requirements for flares
                                                                 in Sec. 63.11 apply.
Sec. 63.8(b)(1)(i)-(ii)...........  Monitoring................  Must conduct monitoring     Yes.
                                                                 according to standard
                                                                 unless Administrator
                                                                 approves alternative.
Sec. 63.8(b)(1)(iii)..............  Monitoring................  Flares not subject to this  No.
                                                                 section unless otherwise
                                                                 specified in relevant
                                                                 standard.
Sec. 63.8(b)(2)-(3)...............  Multiple Effluents and      Specific requirements for   Yes.
                                     Multiple Monitoring         installing monitoring
                                     Systems.                    systems.
                                                                AND.......................
                                                                Must install on each
                                                                 effluent before it is
                                                                 combined and before it is
                                                                 released to the
                                                                 atmosphere unless
                                                                 Administrator approves
                                                                 otherwise.
                                                                AND.......................
                                                                If more than one
                                                                 monitoring system on an
                                                                 emission point, must
                                                                 report all monitoring
                                                                 system results, unless
                                                                 one monitoring system is
                                                                 a backup.
Sec. 63.8(c)(1)...................  Monitoring System           Maintain monitoring system  Yes.
                                     Operation and Maintenance.  in a manner consistent
                                                                 with good air pollution
                                                                 control practices.
Sec. 63.8(c)(1)(i)................  Routine and Predictable     Follow the SSM plan for     Yes.
                                     SSM.                        routine repairs. Keep
                                                                 parts for routine repairs
                                                                 readily available.
                                                                Reporting requirements for
                                                                 SSM when action is
                                                                 described in SSM plan.
Sec. 63.8(c)(1)(ii)...............  SSM not in SSMP...........  Reporting requirements for  Yes.
                                                                 SSM when action is not
                                                                 described in SSM plan.
Sec. 63.8(c)(1)(iii)..............  Compliance with Operation   How Administrator           Yes.
                                     and Maintenance             determines if source
                                     Requirements.               complying with operation
                                                                 and maintenance
                                                                 requirements.
                                                                AND.......................
                                                                Review of source O&M
                                                                 procedures, records,
                                                                 Manufacturer's
                                                                 instructions,
                                                                 recommendations, and
                                                                 inspection of monitoring
                                                                 system.
Sec. 63.8(c)(2)-(3)...............  Monitoring System           Must install to get         Yes.
                                     Installation.               representative emission
                                                                 and parameter
                                                                 measurements.
                                                                AND.......................
                                                                Must verify operational
                                                                 status before or at
                                                                 performance test.
Sec. 63.8(c)(4)...................  Continuous Monitoring       Continuous monitoring       Yes.
                                     System (CMS) Requirements.  systems must be operating
                                                                 except during breakdown,
                                                                 out-of-control, repair,
                                                                 maintenance, and high-
                                                                 level calibration drifts.
 Sec. 63.8(c)(4)(i)...............  Continuous Monitoring       Continuous opacity          No.
                                     System (CMS) Requirements.  monitoring system must
                                                                 have a minimum of one
                                                                 cycle of sampling and
                                                                 analysis for each
                                                                 successive 10-second
                                                                 period and one cycle of
                                                                 data recording for each
                                                                 successive 6-minute
                                                                 period.
 Sec. 63.8(c)(4)(ii)..............  Continuous Monitoring       Continuous emissions        Yes.
                                     System (CMS) Requirements.  monitoring system must
                                                                 have a minimum of one
                                                                 cycle of operation for
                                                                 each successive 15-minute
                                                                 period.
 Sec. 63.8(c)(7)-(8)..............  Continuous monitoring       Out-of-control periods,     Yes.
                                     systems Requirements.       including reporting.

[[Page 4734]]

 
 Sec. 63.8(d).....................  Continuous monitoring       Requirements for            Yes.
                                     systems Quality Control.    continuous monitoring
                                                                 systems quality control,
                                                                 including calibration,
                                                                 etc.
                                                                AND.......................
                                                                Must keep quality control
                                                                 plan on record for the
                                                                 life of the affected
                                                                 source. Keep old versions
                                                                 for 5 years after
                                                                 revisions.
 Sec. 63.8(e).....................  Continuous monitoring       Notification, performance   Yes.
                                     systems Performance         evaluation test plan,
                                     Evaluation.                 reports.
 Sec. 63.8(f)(1)-(5)..............   Alternative Monitoring     Procedures for              Yes.
                                     Method.                     Administrator to approve
                                                                 alternative monitoring.
 Sec. 63.8(f)(6)..................  Alternative to Relative     Procedures for              No.
                                     Accuracy Test.              Administrator to approve
                                                                 alternative relative
                                                                 accuracy tests for
                                                                 continuous emissions
                                                                 monitoring system.
 Sec. 63.8(g)(1)-(4)..............  Data Reduction............  Continuous emissions        Yes.
                                                                 monitoring system 1-hour
                                                                 averages computed over at
                                                                 least 4 equally spaced
                                                                 data points.
 Sec. 63.8(g)(5)..................  Data Reduction............  Data that cannot be used    No.
                                                                 in computing averages for
                                                                 continuous emissions
                                                                 monitoring system and
                                                                 continuous opacity
                                                                 monitoring system.
 Sec. 63.9(a).....................  Notification Requirements.  Applicability and State     Yes.
                                                                 Delegation.
 Sec. 63.9(b)(1)-(5)..............  Initial Notifications.....  Submit notification 120     Yes.
                                                                 days after effective date.
                                                                AND.......................
                                                                Notification of intent to
                                                                 construct/reconstruct.
                                                                AND.......................
                                                                Notification of
                                                                 commencement of construct/
                                                                 reconstruct; Notification
                                                                 of startup..
                                                                AND.......................
                                                                Contents of each..........
 Sec. 63.9(c).....................  Request for Compliance      Can request if cannot       Yes.
                                     Extension.                  comply by date or if
                                                                 installed BACT/LAER.
 Sec. 63.9(d).....................  Notification of Special     For sources that commence   Yes.
                                     Compliance Requirements     construction between
                                     for New Source.             proposal and promulgation
                                                                 and want to comply 3
                                                                 years after effective
                                                                 date.
 Sec. 63.9(e).....................  Notification of             Notify Administrator 60     Yes.
                                     Performance Test.           days prior.
 Sec. 63.9(f).....................  Notification of VE/Opacity  Notify Administrator 30     No.
                                     Test.                       days prior.
Sec. 63.9(g)......................  Additional Notifications    Notification of             Yes.
                                     When Using Continuous       performance evaluation.
                                     Monitoring Systems.        AND.......................
                                                                Notification that exceeded
                                                                 criterion for relative
                                                                 accuracy.
Sec. 63.9(h)(1)-(6)...............  Notification of Compliance  Contents..................  Yes.
                                     Status.                    AND.......................
                                                                Due 60 days after end of
                                                                 performance test or other
                                                                 compliance demonstration.
                                                                When to submit to Federal
                                                                 vs. State authority.
Sec. 63.9(i)......................  Adjustment of Submittal     Procedures for              Yes.
                                     Deadlines.                  Administrator to approve
                                                                 change in when
                                                                 notifications must be
                                                                 submitted.
Sec. 63.9(j)......................  Change in Previous          Must submit within 15 days  Yes.
                                     Information.                after the change.
Sec. 63.10(a).....................  Recordkeeping/Reporting...  Applies to all, unless      Yes.
                                                                 compliance extension.
                                                                AND.......................
                                                                When to submit to Federal
                                                                 vs. State authority.
                                                                AND.......................
                                                                Procedures for owners of
                                                                 more than 1 source.

[[Page 4735]]

 
Sec. 63.10(b)(1)..................  Recordkeeping/Reporting...  General Requirements......  Yes.
                                                                AND.......................
                                                                Keep all records readily
                                                                 available.
                                                                AND.......................
                                                                Keep for 5 years..........
Sec. 63.10(b)(2)(i)-(v)...........  Records related to          Occurrence of each of       Yes.
                                     Startup, Shutdown, and      operation (process
                                     Malfunction.                equipment).
                                                                AND.......................
                                                                Occurrence of each
                                                                 malfunction of air
                                                                 pollution equipment.
                                                                AND.......................
                                                                Maintenance on air
                                                                 pollution control
                                                                 equipment.
                                                                AND.......................
                                                                Actions during startup,
                                                                 shutdown, and malfunction.
Sec. 63.10(b)(2)(vi) and (x-xi)...  Continuous monitoring       Malfunctions, inoperative,  Yes.
                                     systems Records.            out-of-control.
                                                                AND.......................
                                                                Calibration checks........
                                                                AND.......................
                                                                Adjustments, maintenance..
Sec. 63.10(b)(2)(vii)-(ix)........  Records...................  Measurements to             Yes.
                                                                 demonstrate compliance
                                                                 with emissions
                                                                 limitations.
                                                                AND.......................
                                                                Performance test and
                                                                 performance evaluation.
                                                                AND.......................
                                                                Measurements to determine
                                                                 conditions of performance
                                                                 test and performance
                                                                 evaluations..
Sec. 63.10(b)(2)(xii).............  Records...................  Records when under waiver.  Yes.
Sec. 63.10(b)(2)(xiii)............  Records...................  Records when using          Yes.
                                                                 alternative to relative
                                                                 accuracy test.
Sec. 63.10(b)(2)(xiv).............  Records...................  All documentation           Yes.
                                                                 supporting Initial
                                                                 Notification and
                                                                 Notification of
                                                                 Compliance Status.
Sec. 63.10(b)(3)..................  Records...................  Applicability               Yes.
                                                                 Determinations.
Sec. 63.10(c)(1)-(6), (9)-(15)....  Records...................  Additional Records for      Yes.
                                                                 continuous monitoring
                                                                 systems.
Sec. 63.10(c)(7)-(8)..............  Records...................  Records of excess           Yes.
                                                                 emissions and parameter
                                                                 monitoring exceedances
                                                                 for continuous monitoring
                                                                 systems.
Sec. 63.10(d)(1)..................  General Reporting           Requirement to report.....  Yes.
                                     Requirements.
Sec. 63.10(d)(2)..................  Report of Performance Test  When to submit to Federal   Yes.
                                     Results.                    or State authority.
Sec. 63.10(d)(3)..................  Reporting Opacity or VE     What to report and when...  No.
                                     Observations.
Sec. 63.10(d)(4)..................  Progress Reports..........  Must submit progress        Yes.
                                                                 reports on schedule if
                                                                 under compliance
                                                                 extension.
Sec. 63.10(d)(5)..................  Startup, Shutdown, and      Contents and submission...  Yes.
                                     Malfunction Reports.
Sec. 63.10(e)(1)-(92).............  Additional continuous       Must report results for     Yes.
                                     monitoring systems          each CEM on a unit.
                                     Reports.                   AND.......................
                                                                Written copy of
                                                                 performance evaluation.
Sec. 63.10(e)(3)..................  Reports...................  Excess Emission Reports...  No.
Sec. 63.10(e)(3)(i-iii)...........  Reports...................  Schedule for reporting      No.
                                                                 excess emission and
                                                                 parameter monitor
                                                                 exceedance (now defined
                                                                 as deviations).

[[Page 4736]]

 
Sec. 63.10(e)(3)(iv-v)............  Excess Emissions Reports..  Requirement to revert to    No.
                                                                 quarterly submission if
                                                                 there is an excess
                                                                 emissions and parameter
                                                                 monitor exceedance (now
                                                                 defined as deviations).
                                                                AND.......................
                                                                Provision to request
                                                                 semiannual reporting
                                                                 after compliance for one
                                                                 year.
                                                                AND.......................
                                                                Submit report by 30th day
                                                                 following end of quarter
                                                                 or calendar half.
                                                                AND.......................
                                                                If there has not been an
                                                                 exceedance or excess
                                                                 emission (now defined as
                                                                 deviations), report
                                                                 contents is a statement
                                                                 that there have been no
                                                                 deviations.
Sec. 63.10(e)(3)(iv-v)............  Excess Emissions Reports..  Must submit report          No.
                                                                 containing all of the
                                                                 information in Sec.
                                                                 63.10(c)(5-13), Sec.
                                                                 63.8(c)(7-8).
Sec. 63.10(e)(3)(vi-viii).........  Excess Emissions Report     Requirements for reporting  No.
                                     and Summary Report.         excess emissions for
                                                                 continuous monitoring
                                                                 systems (now called
                                                                 deviations).
Sec. 63.10(e)(4)..................   Reporting continuous       Must submit continuous      No.
                                     opacity monitoring system   opacity monitoring system
                                     data.                       data with performance
                                                                 test data.
Sec. 63.10(f).....................  Waiver for Recordkeeping    Procedures for              Yes.
                                     Reporting.                  Administrator to waive.
Sec. 63.11........................  Flares....................  Requirements for flares...  No.
Sec. 63.12........................  Delegation................  State authority to enforce  Yes.
                                                                 standards.
Sec. 63.13........................  Addresses.................  Addresses where reports,    Yes.
                                                                 notifications, and
                                                                 requests are sent.
Sec. 63.14........................  Incorporation by Reference  Test methods incorporated   Yes.
                                                                 by reference.
Sec. 63.15........................  Availability of             Public and confidential     Yes.
                                     Information.                information.
----------------------------------------------------------------------------------------------------------------

APPENDIX B--PART 63

    7. Appendix B to part 63 is amended by adding in numerical order 
new Method 324 to read as follows:

Method 324--Determination of Vapor Phase Flue Gas Mercury Emissions 
From Stationary Sources Using Dry Sorbent Trap Sampling

    1.0 Introduction.
    This method describes sampling criteria and procedures for the 
continuous sampling of mercury (Hg) emissions in combustion flue gas 
streams using sorbent traps. Analysis of each trap can be by cold 
vapor atomic fluorescence spectrometry (AF) which is described in 
this method, or by cold vapor atomic absorption spectrometry (AA). 
Only the AF analytical method is detailed in this method, with 
reference being made to other published methods for the AA 
analytical procedure. The Electric Power Research Institute has 
investigated the AF analytical procedure in the field with the 
support of ADA-ES and Frontier Geosciences, Inc. The AF procedure is 
based on EPA Method 1631, Revision E: Mercury in Water by Oxidation, 
Purge and Trap, and Cold Vapor Atomic Fluorescence Spectrometry. 
Persons using this method should have a thorough working knowledge 
of Methods 1, 2, 3, 4 and 5 of 40 CFR part 60, appendix A.
    1.1 Scope and Application.
    1.1.1 Analytes. The analyte measured by this method is total 
vapor-phase Hg, which represents the sum of elemental (CAS Number 
7439-97-6) and oxidized forms of Hg, mass concentration (micrograms/
dscm) in flue gas samples.
    1.1.2 Applicability. This method is applicable to the 
determination of vapor-phase Hg concentrations ranging from 0.03 
[mu]g/dncm to 100 [mu]g/dncm in low-dust applications, including 
controlled and uncontrolled emissions from stationary sources, only 
when specified within the regulations. When employed to demonstrate 
compliance with an emission regulation, paired sampling is to be 
performed as part of the method quality control procedure. The 
method is appropriate for flue gas Hg measurements from combustion 
sources. Very low Hg concentrations will require greater sample 
volumes. The method can be used over any period from 30 minutes to 
several days in duration, provided appropriate sample volumes are 
collected and all the quality control criteria in Section 9.0 are 
met. When sampling for periods greater than 12 hours, the sample 
rate is required to be maintained at a constant proportion to the 
total stack flowrate, 25 percent to ensure 
representativeness of the sample collected.
    2.0 Summary of Method.
    Known volumes of flue gas are extracted from a duct through a 
single or paired sorbent traps with a nominal flow rate of 0.2 to 
0.6 liters per minute through each trap. Each trap is then acid 
leached and the resulting leachate is analyzed by cold vapor atomic 
fluorescence spectrometry (CVAFS) detection. The AF analytical 
procedure is described in detail in EPA Method 1631. Analysis by AA 
can be performed by existing recognized procedures, such as that 
contained in ASTM Method D6784-02 (incorporated by reference, see 
Sec. 63.14) or EPA Method 29.
    3.0 Definitions. [Reserved]
    4.0 Clean Handling and Contamination.
    During preparation of the sorbent traps, as well as transport, 
field handling, sampling, recovery, and laboratory analysis, special 
attention must be paid to cleanliness procedures. This is to avoid 
Hg contamination of the samples, which generally contain very small 
amounts of Hg. For specifics on how to avoid contamination, Section 
4 of Method 1631 should be well understood.
    5.0 Safety.
    5.1 Site hazards must be prepared for in advance of applying 
this method in the field. Suitable clothing to protect against site 
hazards is required, and requires advance coordination with the site 
to understand the conditions and applicable safety policies. At a 
minimum, portions of the sampling system will be hot, requiring 
appropriate gloves, long sleeves, and caution in handling this 
equipment.
    5.2 Laboratory safety policies are to minimize risk of chemical 
exposure and to properly handle waste disposal. Personnel will don 
appropriate laboratory attire according to a Chemical Hygiene Plan 
established by the laboratory. This includes, but is not limited to, 
laboratory coat, safety goggles, and nitrile gloves under clean 
gloves.

[[Page 4737]]

    5.3 The toxicity or carcinogenicity of reagents used in this 
method has not been fully established. The procedures required in 
this method may involve hazardous materials, operations, and 
equipment. This method may not address all of the safety problems 
associated with these procedures. It is the responsibility of the 
user to establish appropriate safety and health practices and 
determine the applicable regulatory limitations prior to performing 
these procedures. Each chemical should be regarded as a potential 
health hazard and exposure to these compounds should be minimized. 
Chemists should refer to the MSDS for each chemical with which they 
are working.
    5.4 Any wastes generated by this procedure must be disposed of 
according to a hazardous materials management plan that details and 
tracks various waste streams and disposal procedures.
    6.0 Equipment and Supplies.
    6.1 Hg Sampling Train. A Schematic of a single trap sampling 
train used for this method is shown in Figure 324-1. Where this 
method is used to collect data to demonstrate compliance with a 
regulation, it must be performed with paired sorbent trap equipment.
[GRAPHIC] [TIFF OMITTED] TP30JA04.019


 
 
 
        Figure 324-1. Hg Sampling Train Illustrating Single Trap.
 

    6.1.1 Sorbent Trap. Use sorbent traps with separate main and 
backup sections in series for collection of Hg. Selection of the 
sorbent trap shall be based on: (1) Achievement of the performance 
criteria of this method, and (2) data is available to demonstrate 
the method can pass the criteria in EPA Method 301 when used in this 
method and when the results are compared with those from EPA Method 
29, EPA Method 101A, or ASTM Method 6784-02 for the measurement of 
vapor-phase Hg in a similar flue gas matrix. Appropriate traps are 
referred to as ``sorbent trap'' throughout this method. The method 
requires the analysis of Hg in both main and backup portions of the 
sorbent within each trap. The sorbent trap should be obtained from a 
reliable source that has clean handling procedures in place for 
ultra low-level Hg analysis. This will help assure the low Hg 
environment required to manufacture sorbent traps with low blank 
levels of Hg. Sorbent trap sampling requirements or needed 
characteristics are shown in Table 324-1. Blank/cleanliness and 
other requirements are described in Table 324-2. The sorbent trap is 
supported on a probe and inserted directly into the flue gas stream, 
as shown on Figure 324-1. The sampled sorbent trap is the entire Hg 
sample.
    6.1.2 Sampling Probe. The probe assembly shall have a leak-free 
attachment to the sorbent trap. For duct temperatures from 200 to 
375F, no heating is required. For duct temperatures 
less than 200F, the sorbent tube must be heated to at 
least 200F or higher to avoid liquid condensation in 
the sorbent trap by using a heated probe. For duct temperatures 
greater than 375F, a large sorbent trap must be used, 
as shown in Table 324-1, and no heating is required. A thermocouple 
is used to monitor stack temperature.
    6.1.3 Umbilical Vacuum Line. A 250F heated 
umbilical line shall be used to convey to the moisture knockout the 
sampled gas that has passed through the sorbent trap and probe 
assembly.
    6.1.4 Moisture Knockout. Impingers and desiccant can be combined 
to dry the sample gas prior to entering the dry gas meter. 
Alternative sample drying methods are acceptable as long as they do 
not affect sample volume measurement.
    6.1.5 Vacuum Pump. A leak tight vacuum pump capable of 
delivering a controlled extraction flow rate between 0.1 to 0.8 
liters per minute.
    6.1.6 Dry Gas Meter. Use a dry gas meter that is calibrated 
according to the procedures in 40 CFR part 60, appendix A, Method 5, 
to measure the total sample volume collected. The dry gas meter must 
be sufficiently accurate to measure the sample volume within 2 
percent, calibrated at the selected flow rate and conditions 
actually encountered during sampling, and equipped with a 
temperature sensor capable of measuring typical meter temperatures 
accurately to within 3C (5.4F).
    6.2 Sample Analysis Equipment. Laboratory equipment as described 
in Method 1631, Sections 6.3 to 6.7 is required for analysis by AF. 
For analysis by AA, refer to Method 29 or ASTM Method 6784-02.

[[Page 4738]]



          Table 324-1.--Sorbent Trap and Sampling Requirements.
------------------------------------------------------------------------
    Item to be determined      Small sorbent trap    Large sorbent trap
------------------------------------------------------------------------
Sampling Target: Hg Loading   Minimum = 0.025.....  Minimum = 0.10 [mu]g/
 Range, [mu]g.                [mu]g/trap Maximum =   trap
                               150 [mu]g/trap.      Maximum = 1800 [mu]g/
                                                     trap
Sampling Duration Required:   Minimum = 30 minutes  Minimum = 24 hours
 limits on sample times.      Maximum = 24 hours..  Maximum = 10 days
Sampling Temperature          200 to 375F.             thn-eq>F
Sampling Rate Required......  0.2 to 0.6 L/min;     0.2 to 0.6 L/min;
                               start at 0.4 L/min    start at 0.4 L/min
                               Must be constant      Must be constant
                               proportion within +/  proportion of stack
                               - 25% if greater      flowrate within +/-
                               than 12 hours;        25%
                               constant rate
                               within +/- 25 % if
                               less than 12 hours.
------------------------------------------------------------------------

    7.0 Analysis by AF, Reagents and Standards.
    For analysis by AF, use Method 1631, Sections 7.1-7.3 and 7.5-
7.12 for laboratory reagents and standards. Refer to Method 29 or 
ASTM Method 6784-02 for analysis by AA.
    7.1 Reagent Water. Same as Method 1631, Section 7.1.
    7.2 Air. Same as Method 1631, Section 7.2.
    7.3 Hydrochloric Acid. Same as Method 1631, Section 7.3.
    7.4 Stannous Chloride. Same as Method 1631, Section 7.5.
    7.5 Bromine Monochloride (BrCl, 0.01N). Same as Method 1631, 
Section 7.6.
    7.6 Hg Standards. Same as Method 1631, Sections 7.7 to 7.11.
    7.7 Nitric Acid. Reagent grade, low Hg.
    7.8 Sulfuric Acid. Reagent grade, low Hg.
    7.9 Nitrogen. Same as Method 1631, Section 7.12.
    7.10 Argon. Same as Method 1631, Section 7.13.
    8.0 Sample Collection and Transport.
    8.1 Pre-Test.
    8.1.1 Site information should be obtained in accordance with 
Method 1 (40 CFR part 60, appendix A). Identify a location that has 
been shown to be free of stratification for SO2 and 
NOX through concentration measurement traverses for those 
gases. An estimation of the expected Hg concentration is required to 
establish minimum sample volumes. Based on estimated minimum sample 
volume and normal sample rates for each size trap used, determine 
sampling duration with the data provided in Table 324-1.
    8.1.2 Sorbent traps must be obtained from a reliable source such 
that high quality control and trace cleanliness are maintained. 
Method detection limits will be adversely affected if adequate 
cleanliness is not maintained. Sorbent traps should be handled only 
with powder-free low Hg gloves (vinyl, latex, or nitrile are 
acceptable) that have not touched any other surface. The sorbent 
traps should not be removed from their clean storage containers 
until after the preliminary leak check has been completed. Field 
efforts at clean handling of the sorbent traps are key to the 
success of this method.
    8.1.3 Assemble the sample train according to Figure 324-1, 
except omit the sorbent trap.
    8.1.4 Preliminary Leak Check. Perform system leak check without 
the single or dual sorbent traps in place. This entails plugging the 
end of the probe to which each sorbent trap will be affixed, and 
using the vacuum pump to draw a vacuum in each sample train. Adjust 
the vacuum in the sample train to 15 inches Hg. A rotameter on the 
dry gas meter will indicate the leakage rate. The leakage rate must 
be less than 2 percent of the planned sampling rate.
    8.1.5 Release the vacuum in the sample train, turn off the pump, 
and affix the sorbent trap to the end of the probe, using clean 
handling procedures. Leave the flue gas end of the sorbent trap 
plugged.
    8.1.6 Pre-test Leak Check. Perform a leak check with the Sorbent 
trap in place. Use the sampling vacuum pump to draw a vacuum in the 
sample train. Adjust the vacuum in the sample train to 15 inches Hg. 
A rotameter on the dry gas meter will indicate the leakage rate. 
Record the leakage rate. The leakage rate must be less than 2 
percent of the planned sampling rate. Once the leak check passes 
this criterion, carefully release the vacuum in the sample train 
(the sorbent trap must not be exposed to abrupt changes in pressure 
or to backflow), then re-cap the flue gas end of the sorbent trap 
until the probe is ready for insertion. The sorbent trap packing 
beds must be undisturbed by the leak test to prevent gas channeling 
through the media during sampling.
    8.1.7 Use temperature controllers to heat the portions of the 
trains that require it. The sorbent trap must be maintained between 
200 and 375 F during sampling.
    8.1.8 Gas temperature and static pressure must be considered 
prior to sampling in order to maintain proper safety precautions 
during sampling.
    8.2 Sample Collection.
    8.2.1 Remove the plug from the end of a sorbent trap and store 
it in a clean sorbent trap storage container. Remove the sample duct 
port cap and insert the probe. Secure the probe and ensure that no 
leakage occurs between the duct and environment.
    8.2.2 Record initial data including the start time, starting dry 
gas meter readings, and the name of the field tester(s). Set the 
initial sample flow rate to 0.4 L/min (+/- 25 percent).
    8.2.3 For constant-flow sampling (samples less than 12 hours in 
duration), every 10-15 minutes during the sampling period: record 
the time, the sample flow rate, the gas meter readings, the duct 
temperature, the flow meter temperatures, temperatures of heated 
equipment such as the vacuum lines and the probes (if heated), and 
the sampling vacuum reading. Adjust the sample rate as needed, 
maintaining constant sampling within +/- 25 percent of the initial 
reading.
    8.2.4 For constant proportion sampling (samples 12 hours or 
greater in duration), every hour during the sampling period: record 
the time, the sample flow rate, the gas meter readings, the duct 
temperature, the flow meter temperatures, temperatures of heated 
equipment such as the vacuum lines and the probes (if heated), and 
the sampling vacuum readings. Also record the stack flow rate 
reading, whether provided as a CEM flow monitor signal, a pitot 
probe or other direct flow indication, or a plant input signal. 
Adjust the sampling rate to maintain proportional sampling within +/
- 25 percent relative to the total stack flowrate.
    8.2.5 Obtain and record operating data for the facility during 
the test period, including total stack flowrate and the oxygen 
concentration at the flue gas test location. Barometric pressure 
must be obtained for correcting sample volume to standard 
conditions.
    8.2.6 Post Test Leak Check. When sampling is completed, turn off 
the sample pump, remove the probe from the port and carefully re-
plug the end of the sorbent trap. Perform leak check by turning on 
the sampling vacuum pumps with the plug in place. The rotameter on 
the dry gas meters will indicate the leakage rates. Record the 
leakage rate and vacuum. The leakage rate must be less than 2 
percent of the actual sampling rate. Following the leak check, 
carefully release the vacuum in the sample train.
    8.2.7 Sample Recovery. Recover each sampled sorbent trap by 
removing it from the probe, plugging both ends with the clean caps 
provided with the sorbent trap, and then wiping any dirt off the 
outside of the sorbent trap. Place the sorbent trap into the clean 
sample storage container in which it was provided, along with the 
data sheet that includes the post-test leak check, final volume, and 
test end time.
    8.3 Quality Control Samples and Requirements.
    8.3.1 Field blanks. Refer to Table 324-2.
    8.3.2 Duplicate (paired or side by side) samples. Refer to 
Section 8.6.6 of Performance Specification 12A of 40 CFR part 60, 
appendix B for this criteria.
    8.3.3 Breakthrough performance data (``B'' bed in each trap, or 
second traps behind). Refer to Table 324-2.
    8.3.4 Field spikes (sorbent traps spiked with Hg in the lab and 
periodically sampled in the field to determine overall accuracy). 
Refer to Table 324-2.

[[Page 4739]]

    8.3.5 Laboratory matrix and matrix spike duplicates. Refer to 
Table 324-2.
    9.0 Quality Control.
    Table 324-2 summarizes the major quantifiable QC components.

                                    Table 324-2.--Quality Control for Samples
----------------------------------------------------------------------------------------------------------------
         QA/QC specification             Acceptance criteria           Frequency            Corrective action
----------------------------------------------------------------------------------------------------------------
Leak-check...........................  <2% of sampling rate...  Pre and post-sampling..  Pre-sampling: repair
                                                                                          leak. Post-sampling:
                                                                                          Flag data and repeat
                                                                                          run if for regulatory
                                                                                          compliance.
Sample Flow Rate for samples less      0.4 L/min initially and  Throughout run every 10- Adjust when data is
 than 12 hours in duration.             +/- 25% of initial       15 minutes.              recorded.
                                        rate throughout run.
Sample Flow Rate for samples greater   0.4 L/min initially and  Throughout run every     Adjust when data is
 than 12 hours in duration.             maintain +/- 25% of      hour.                    recorded.
                                        ratio to flue gas flow
                                        rate throughout
                                        sampling.
Sorbent trap laboratory blank (same    <5 ng/trap and a         3 per analysis set of    .......................
 lot as samples).                       standard deviation of    20 sorbent traps.
                                        <1.0 ng/trap (n=3).
Sorbent trap field blank (same lot as  <5 ng/trap and a         1 per every 10 field     .......................
 samples).                              standard deviation of    samples collected.
                                        <1.0 ng/trap (n=3) OR
                                        <5% of average sample
                                        collected.
B-Trap Bed Analysis..................  <2% of A-Trap Bed Value  Every sample...........  .......................
                                        OR < 5 ng/trap.
Paired Train Results.................  Same as Section 8.6.6                             .......................
                                        of PS-12A of 40 CFR
                                        Part 60, Appendix B.
Field Spikes.........................  80% to 120% recovery...  For long-term            If the first 4 field
                                                                 regulatory monitoring,   spikes do not meet the
                                                                 1 per every 3 samples    +/- 20% criteria, take
                                                                 for the first 12         corrective sampling
                                                                 samples.                 and laboratory
                                                                                          measures and repeat at
                                                                                          the 1 per every 3
                                                                                          sample rate until the
                                                                                          +/- 20% criteria is
                                                                                          met.
Laboratory matrix and matrix spike     85% to 115% recovery...  1 per every 10 or 20     .......................
 duplicates.                                                     samples--to be
                                                                 determined.
----------------------------------------------------------------------------------------------------------------

    10.0 Calibration and Standards.
    Same as Sections 10.1, 10.2 and 10.4 of Method 1631.
    10.1 Calibration and Standardization. Same as Sections 10.1 and 
10.4 of Method 1631.
    10.2 Bubbler System. Same as Section 10.2 of M1631.
    10.3 Flow-Injection System. Not applicable.
    11.0 Analytical Procedures.
    11.1 Preparation Step. The sorbent traps are received and 
processed in a low-Hg environment (class-100 laminar-flow hood and 
gaseous Hg air concentrations below 20 ng/m3) following 
clean-handling procedures. Any dirt or particulate present on the 
exterior of the trap must be removed to avoid contamination of the 
sample. The sorbent traps are then opened and the sorbent bed(s) 
transferred to an appropriate sized trace-clean vessel. It is 
recommended that the height of the trace-clean vessel be at least 3 
times the diameter to facilitate a refluxing action.
    11.2 Leaching Step. The sorbent trap is then subjected to a hot-
acid leach using a 70:30 ratio mixture of concentrated 
HNO3/H2SO4. The acid volume must be 
40 percent of the expected end volume of the digest after dilution. 
The HNO3/H2SO4 acid to carbon ratio 
should be approximately 35:1. The leachate is then heated to a 
temperature of 50 to 60C for 1.5 to 2.0 hours in the 
finger-tight capped vessels. This process may generate significant 
quantities of noxious and corrosive gasses and must only be 
performed in a well-ventilated fume hood. Care must be taken to 
prevent excessive heated leaching of the samples as this will begin 
to break down the charcoal material.
    11.3 Dilution Step. After the leached samples have been removed 
from the hot plate and allowed to cool to room temperature, they are 
brought to volume with a 5 percent (v/v) solution of 0.01 N BrCl. As 
the leaching digest contains a substantial amount of dissolved 
gasses, add the BrCl slowly, especially if the samples are still 
warm. As before, this procedure must be performed in a properly 
functioning fume hood. The sample is now ready for analysis.
    11.4 Hg Reduction and Purging. (Reference Section 11.2 of M1631 
except that NH2OH is not used.)
    11.4.1 Bubbler System. Pipette an aliquot of the digested sample 
into the bubbler containing pre-blanked reagent water and a soda 
lime trap connected to the exhaust port. Add stannous chloride 
(SnCl2) to reduce the aliquot and then seal the bubbler. 
Connect gold sample traps to the end of the soda lime trap as shown 
in Figures 1 and 2 of Method 1631. Finally, connect the 
N2 lines and purge for 20 minutes. The sample trap can 
then be added into the analytical train. M1631, Section 11.2.1.
    11.4.2 Flow Injection System. If required.
    11.5 Desorption of Hg from the gold trap, and peak evaluation. 
Use Section 11.3 and 11.4 in M1631.
    11.6 Instrument Calibration. Analyze the standards by AA or AF 
following the guidelines specified by the instrument manufacturer. 
Construct a calibration curve by plotting the absorbances of the 
standards versus [mu]g/l Hg. The R2 for the calibration 
curve should be 0.999 or better. If the curve does not have an 
R2 value equal to or better than 0.999 then the curve 
should be rerun. If the curve still does not meet this criteria then 
new standards should be prepared and the instrument recalibrated. 
All calibration points contained in the curve must be within 10 
percent of the calibration value when the calibration curve is 
applied to the calibration standards.
    11.7 Sample Analysis. Analyze the samples in duplicate following 
the same procedures used for instrument calibration. From the 
calibration curve, determine sample Hg concentrations. To determine 
total Hg mass in each sample fraction, refer to calculations in 
Section 15. Record all sample dilutions.
    11.8 Continued Calibration Performance. To verify continued 
calibration performance, a continuing calibration check standard 
should be run every 10 samples. The measured Hg concentration of the 
continuing calibration check standard must be within 10 percent of 
the expected value.
    11.9 Measurement Precision. The QA/QC for the analytical portion 
of this method is that every sample, after it has been prepared, is 
to be analyzed in duplicate with every tenth sample analyzed in 
triplicate. These results must be within 10 percent of each other. 
If this is not the case, then the instrument must be recalibrated 
and the samples reanalyzed.
    11.10 Measurement Accuracy. Following calibration, an 
independently prepared standard (not from same calibration stock 
solution) should be analyzed. In addition, after every ten samples, 
a known spike sample (standard addition) must be analyzed.

[[Page 4740]]

The measured Hg content of the spiked samples must be within 10 
percent of the expected value.
    11.11 Independent QA/QC Checks. It is suggested that the QA/QC 
procedures developed for a test program include submitting, on 
occasion, spiked Hg samples to the analytical laboratory by either 
the prime contractor, if different from the laboratory, or an 
independent organization. The measured Hg content of reference 
samples must be within 15 percent of the expected value. If this 
limit is exceeded, corrective action (e.g., re-calibration) must be 
taken and the samples re-analyzed.
    11.12 Quality Assurance/Quality Control. For this method, it is 
important that both the sampling team and analytical people be very 
well trained in the procedures. This is a complicated method that 
requires a high-level of sampling and analytical experience. For the 
sampling portion of the QA/QC procedure, both solution and field 
blanks are required. It should be noted that if high-quality 
reagents are used and care is taken in their preparation and in the 
train assembly, there should be little, if any, Hg measured in 
either the solution or field blanks.
    11.13 Solution Blanks. Solution blanks must be taken and 
analyzed every time a new batch of solution is prepared. If Hg is 
detected in these solution blanks, the concentration is subtracted 
from the measured sample results. The maximum amount that can be 
subtracted is 10 percent of the measured result or 10 times the 
detection limit of the instrument which ever is lower. If the 
solution blanks are greater than 10 percent the data must be flagged 
as suspect.
    11.14 Field Blanks. A field blank is performed by assembling a 
sample train, transporting it to the sampling location during the 
sampling period, and recovering it as a regular sample. These data 
are used to ensure that there is no contamination as a result of the 
sampling activities. A minimum of one field blank at each sampling 
location must be completed for each test site. Any Hg detected in 
the field blanks cannot be subtracted from the results. Whether or 
not the Hg detected in the field blanks is significant is determined 
based on the QA/QC procedures established prior to the testing. At a 
minimum, if field blanks exceed 30 percent of the measured value at 
the corresponding location, the data must be flagged as suspect.
    12.0 Calculations and Data Analysis.
    Use Section 12 in M1631.
    13.0 Constant Proportion Sampling.
    Calculate the Sample Rate/Stack Flow = ``x.'' ``X'' must be 
maintained within 0.75 ``x'' to 1.25 ``x'' for sampling times in 
excess of 12 hours. For mass emission rate calculations, use the 
flow CEM total measured flow corresponding to the sorbent trap 
sample time period.
    14.0 Sampling and Data Summary Calculations.
    Refer to 40 CFR part 60, appendix A, Methods 2, 4, and 5 for 
example calculations.
    15.0 Pollution Prevention.
    Refer to Section 13 in Method 1631.
    16.0 Waste Management.
    Refer to Section 14 in Method 1631.
    17.0 Bibliography.
    17.1 EPA Method 1631, Revision E ``Mercury in Water by 
Oxidation, Purge and Trap, and Cold Vapor Atomic Fluorescence 
Spectrometry,'' August 2002.
    17.2 ``Comparison of Sampling Methods to Determine Total and 
Speciated Mercury in Flue Gas,'' CRADA F00-038 Final Report, DOE/
NETL-2001/1147, January 4, 2001.
    17.3 40 CFR part 60, appendix A, ``Method 29--Determination of 
Metals Emissions from Stationary Sources.''
    17.4 40 CFR part 60, appendix B, ``Performance Specification 
12A, Specification and Test Procedures for Total Vapor Phase Mercury 
Continuous Emission Monitoring Systems in Stationary Sources.''
    17.5 ASTM Method D6784-02, ``Standard Test Method for Elemental, 
Oxidized, Particle-bound and Total Mercury in Flue Gas Generated 
from Coal-Fired Stationary Sources (Ontario Hydro Method).''

Option 2--Proposed Amendments to Parts 60 and 63

PART 60--[AMENDED]

    1. The authority citation for part 60 continues to read as follows:

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

    2. Section 60.17 is amended by adding paragraph (a)(65) to read as 
follows:


Sec. 60.17  Incorporations by Reference.

* * * * *
    (a) * * *
    (65) ASTM D6784-02, Standard Test Method for Elemental, Oxidized, 
Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired 
Stationary Sources (Ontario Hydro Method), for appendix B to part 60, 
Performance Specification 12A.
* * * * *

Subpart Da--[Amended]

    3. Subpart Da is amended by:
    a. Redesignate Sec. 60.49a as Sec. 60.51a;
    b. Redesignate Sec. 60.48a as Sec. 60.50a;
    c. Redesignate Sec. 60.47a as Sec. 60.49a;
    d. Redesignate Sec. 60.46a as Sec. 60.48a;
    e. Redesignate Sec. 60.45a as Sec. 60.47a; and
    f. Adding new Sec.Sec. 60.45a and 60.46a to read as follows:


Sec. 60.45a  Standard for Mercury

    (a) For each coal-fired electric utility steam generating unit 
other than an integrated gasification combined cycle (IGCC) electric 
utility steam generating unit, you must meet each mercury (Hg) 
emissions limit in paragraphs (a)(1) through (5) of this section that 
applies to you. The Hg emissions limits in paragraphs (a)(1) through 
(5) of this section are based on a 12-month rolling average using the 
procedures in Sec. 60.50a(h).
    (1) For each coal-fired electric utility steam generating unit that 
burns only bituminous coal, you must not discharge into the atmosphere 
any gases from a new affected source which contain Hg in excess of 6.0 
x 10 -6 pound per Megawatt hour (lb/MWh) or 0.0060 lb/
gigawatt-hour (GWh) on an output basis. The SI equivalent is 0.00075 
nanograms per joule (ng/J).
    (2) For each coal-fired electric utility steam generating unit that 
burns only subbituminous coal, you must not discharge into the 
atmosphere any gases from a new affected source which contain Hg in 
excess of 20 x 10 -6 lb/MWh or 0.020 lb/GWh on an output 
basis. The SI equivalent is 0.0025 ng/J.
    (3) For each coal-fired electric utility steam generating unit that 
burns only lignite, you must not discharge into the atmosphere any 
gases from a new affected source which contain Hg in excess of 62 x 10 
-6 lb/MWh or 0.062 lb/GWh on an output basis. The SI 
equivalent is 0.0078 ng/J.
    (4) For each coal-burning electric utility steam generating unit 
that burns only coal refuse, you must not discharge into the atmosphere 
any gases from a new affected source which contain Hg in excess of 1.1 
x 10 -6 lb/MWh or 0.0011 lb/GWh on an output basis. The SI 
equivalent is 0.00087 ng/J.
    (5) For each coal-fired electric utility steam generating unit that 
burns a blend of coals from different coal ranks (i.e., bituminous 
coal, subbituminous coal, lignite) or a blend of coal and coal refuse, 
you must not discharge into the atmosphere any gases from a new 
affected source that contain Hg in excess of the monthly unit-specific 
Hg emissions limit established according to paragraph (a)(5)(i) or (ii) 
of this section, as applicable to your unit.
    (i) If you operate a coal-fired electric utility steam generating 
unit that burns a blend of coals from different coal ranks or a blend 
of coal and coal refuse, you must not discharge into the atmosphere any 
gases from a new affected source that contain Hg in excess of the 
computed weighted Hg emissions limit based on the proportion of energy 
output (in Btu) contributed by each coal-rank burned during the 
compliance period and its applicable Hg emissions limit in paragraphs 
(a)(1) through (4) of this section as determined using Equation 1 of 
this section. You must meet the weighted Hg emissions limit calculated 
using Equation 1 of this section by calculating the unit emission rate 
based on the total Hg loading of the unit and the total Btu or megawatt 
hours contributed by all fuels burned during the compliance period.

[[Page 4741]]

[GRAPHIC] [TIFF OMITTED] TP30JA04.020


Where:

ELb = Total allowable Hg in lb/MWh that can be emitted to 
the atmosphere from any affected source being averaged under the 
blending provision.
ELi = Hg emissions limit for the subcategory that applies to 
affected source i, lb/MWh.
HHi = Electricity output from affected source i during the 
production period related to the corresponding Hi that falls 
within the compliance period, gross MWh generated by the electric 
utility steam generating unit.
n = Number of coal ranks being averaged for an affected source.

    (ii) If you operate a coal-fired electric utility steam generating 
unit that burns a blend of coals from different coal ranks or a blend 
of coal and coal refuse together with one or more non-regulated, 
supplementary fuels, you must not discharge into the atmosphere any 
gases from the unit that contain Hg in excess of the computed weighted 
Hg emission limit based on the proportion of electricity output (in 
MWh) contributed by each coal rank burned during the compliance period 
and its applicable Hg emissions limit in paragraphs (a)(1) through (4) 
of this section as determined using Equation 1 of this section. You 
must meet the weighted Hg emissions limit calculated using Equation 1 
of this section by calculating the unit emission rate based on the 
total Hg loading of the unit and the total megawatt hours contributed 
by both regulated and nonregulated fuels burned during the compliance 
period.
    (b) For each IGCC electric utility steam generating unit, you must 
not discharge into the atmosphere any gases from a new affected source 
which contain Hg in excess of 20 x 10-\6\ lb/MWh or 0.020 
lb/GWh on an output basis. The SI equivalent is 0.0025 ng/J. This Hg 
emissions limit is based on a 12-month rolling average using the 
procedures in Sec. 60.50a(g).


Sec. 60.46a  Standard for Nickel

    (a) On and after the date on which the initial performance test 
required to be conducted under Sec. 60.8 is completed, the owner or 
operator of each oil-fired unit subject to the provisions of this 
subpart shall not discharge into the atmosphere any gases from an oil-
fired electric utility steam generating unit which contain Ni in excess 
of 0.0008 lb/MWh on an output basis. The SI equivalent is 0.010 ng/J.
    (b) The emissions limit for an oil-fired electric utility steam 
generating unit in paragraph (a) of this section does not apply if the 
owner or operator uses distillate oil as fuel. Except as noted in 
paragraph (e) of this section, the emissions limit in paragraph (a) of 
this section will apply immediately if the owner or operator 
subsequently uses a fuel other than distillate oil.
    (c) If you use an ESP to meet a Ni emissions limit in this subpart, 
you must operate the ESP such that the hourly average voltage and 
secondary current (or total power input) do not fall below the limit 
established in the initial or subsequent performance test.
    (d) If you use a control device or combination of control devices 
other than an ESP to meet the Ni emissions limit, or you wish to 
establish and monitor an alternative operating limit and alternative 
monitoring parameters for an ESP, you must apply to the Administrator 
for approval of alternative monitoring under Sec. 60.13(i).
    (e) If you comply with the requirements in Sec. 60.46a(b) for 
switching fuel, and you must switch fuel because of an emergency, you 
must notify the Administrator in writing within 30 days of using a fuel 
other than distillate oil.
    4. Newly redesignated Sec. 60.48a is amended by:
    a. Revising paragraph (c);
    b. In paragraph (h) by revising the existing references from ``Sec. 
60.47a'' to ``Sec. 60.49a'';
    c. In paragraph (i) by revising the existing references for 
``Sec.Sec. 60.47a(c),'' ``60.47a(l),'' and ``60.47a(k)'' to ``Sec.Sec. 
60.49a(c),'' ``60.49a(l),'' and ``60.49a(k),'' respectively;
    d. In paragraph (j)(2) by revising the existing references from 
``Sec. 60.47a'' to ``Sec. 60.49a'' twice;
    e. In paragraph (k)(2)(ii) by revising the existing references from 
``Sec. 60.47a'' and ``60.47a(l)'' to ``Sec. 60.49a'' and ``60.49a(l),'' 
respectively; in paragraph (k)(2)(iii) by revising the existing 
references from ``Sec. 60.47a(k)'' to ``Sec. 60.49a(k)''; and in 
paragraph (k)(2)(iv) by revising the existing references from ``Sec. 
60.47a(l)'' to ``Sec. 60.49a(l)''; and
    f. Adding new paragraphs (m) and (n).
    The revision and additions read as follows:


Sec. 60.48a  Compliance provisions.

* * * * *
    (c) The particulate matter emission standards under Sec. 60.42a, 
the nitrogen oxides emission standards under Sec. 60.44a, the Hg 
emission standards under Sec. 60.45a, and the Ni emission standards 
under Sec. 60.46a apply at all times except during periods of startup, 
shutdown, or malfunction.
* * * * *
    (m) Compliance provisions for sources subject to Sec. 60.45a. The 
owner or operator of an affected facility subject to Sec. 60.45a (new 
sources constructed after January 30, 2004) shall calculate Hg 
emissions by multiplying the average hourly Hg output concentration 
measured according to the provisions of Sec. 60.49a(c) by the average 
hourly flow rate measured according to the provisions of Sec. 60.49a(l) 
and divided by the average hourly gross heat rate measured according to 
the provisions in Sec. 60.49a(k).
    (n) Compliance provisions for sources subject to Sec. 60.46a. (1) 
The owner or operator of an affected facility subject to Sec. 60.46a(a) 
(new source constructed after January 30, 2004) shall calculate Ni 
emissions rate according to the procedures outlined in Sec. 60.50a(i).
    5. Newly redesignated Sec. 60.49a is amended by:
    a. In paragraph (c)(2) by revising the existing references from 
``Sec. 60.49a'' to ``Sec. 60.51a'' twice;
    b. In paragraph (g) by revising the existing reference from ``Sec. 
60.46a'' to ``Sec. 60.48a.''
    c. Revising paragraph (k) introductory text; and
    d. Adding new paragraphs (p) through (s).
    The revision and additions read as follows:


Sec. 60.49a  Emission monitoring.

* * * * *
    (k) The procedures specified in paragraphs (k)(1) through (3) of 
this section shall be used to determine compliance with the output-
based standards under Sec.Sec. 60.42a(c), 60.43a(i), 60.44a(d)(1), 
60.44a(e), 60.45a, and 60.46a.
* * * * *
    (p) The owner or operator of an affected facility demonstrating 
compliance with an Hg limit in Sec. 60.45a shall install and operate a 
continuous emissions monitoring system (CEMS) to measure and record the 
concentration of Hg in the exhaust gases from each stack according to 
the requirements in paragraphs (p)(1) through (3) of this section.
    (1) The owner or operator must install, operate, and maintain each 
CEMS according to Performance Specification 12A in 40 CFR part 60, 
appendix B.
    (2) The owner or operator must conduct a performance evaluation of

[[Page 4742]]

each CEMS according to the requirements of Sec. 60.13 and Performance 
Specification 12A in 40 CFR part 60, appendix B.
    (3) The owner or operator must operate each CEMS according to the 
requirements in paragraphs (p)(3)(i) through (iv) of this section.
    (i) As specified in Sec. 60.13(e)(2), each CEMS must complete a 
minimum of one cycle of operation (sampling, analyzing, and data 
recording) for each successive 15-minute period.
    (ii) The owner or operator must reduce CEMS data as specified in 
Sec. 60.13(h).
    (iii) Each CEMS must determine and record the 1-hour average 
emissions using all the hourly averages collected for periods during 
which the CEMS is not out of control.
    (iv) The owner or operator must record the results of each 
inspection, calibration, and validation check.
    (4) Mercury CEMS data collection must conform to paragraphs 
(p)(4)(i) through (iv) of this section.
    (i) A complete day of data for continuous monitoring is 18 hours or 
more in a 24-hour period.
    (ii) A complete month of data for continuous monitoring is 21 days 
or more in a calendar month.
    (iii) If you collect less than 21 days of continuous emissions 
data, you must discard the data collected that month and replace the 
data with the mean of the individual monthly emission rate values 
determined in the last 12 months.
    (iv) If you collect less than 21 days per monthly period of 
continuous data again in that same 12-month rolling average cycle, you 
must discard the data collected that month and replace that data with 
the highest individual monthly emission rate determined in the last 12 
months.
    (q) As an alternative to the CEMS required in paragraph (p) of this 
section, the owner or operator must monitor Hg emissions using Method 
324 in 40 CFR part 63, appendix A.
    (r) The owner or operator of an affected facility which uses an ESP 
to meet a Ni limit in Sec. 60.46a shall install and operate a 
continuous parameter monitoring system (CPMS) to measure and record the 
voltage and secondary current (or total power input) to the control 
device according to the requirements in paragraphs (r)(1) through (3) 
of this section.
    (1) Each CPMS must complete a minimum of one cycle of operation for 
each successive 15-minute period. The owner or operator must have a 
minimum of four successive cycles of operation to have a valid hour of 
data.
    (2) Each CPMS must determine the 1-hour block average of all 
recorded readings.
    (3) The owner or operator must record the results of each 
inspection, calibration, and validation check for a CPMS.
    (s) The owner or operator shall prepare and submit to the 
Administrator for approval a unit-specific monitoring plan for each 
monitoring system. The owner or operator shall comply with the 
requirements in your plan. The plan must address the requirements in 
paragraphs (s)(1) through (6) of this section.
    (1) Installation of the CMS sampling probe or other interface at a 
measurement location relative to each affected process unit such that 
the measurement is representative of control of the exhaust emissions 
(e.g., on or downstream of the last control device);
    (2) Performance and equipment specifications for the sample 
interface, the pollutant concentration or parametric signal analyzer, 
and the data collection and reduction systems;
    (3) Performance evaluation procedures and acceptance criteria 
(e.g., calibrations);
    (4) Ongoing operation and maintenance procedures in accordance with 
the general requirements of Sec. 60.13(d);
    (5) Ongoing data quality assurance procedures in accordance with 
the general requirements of Sec. 60.13; and
    (6) Ongoing recordkeeping and reporting procedures in accordance 
with the general requirements of Sec. 60.7.
    6. Newly redesignated Sec. 60.50a is amended by:
    a. In paragraph (c)(5) by revising the existing references from 
``Sec. 60.47a(b) and (d)'' to ``Sec. 60.49a(b) and (d),'' respectively;
    b. In paragraph (d)(2) by revising the existing references from 
``Sec. 60.47a(c) and (d)'' to ``Sec. 60.49a(c) and (d),'' respectively;
    c. In paragraph (e)(2) by revising the existing reference from 
``Sec. 60.46a(d)(1)'' to ``Sec. 60.48a(d)(1)''; and
    d. Adding new paragraphs (g) through (j).
    The additions read as follows:


Sec. 60.50a  Compliance determination procedures and methods.

* * * * *
    (g) For the purposes of determining compliance with the emission 
limits in Sec.Sec. 60.45a and 60.46a, the owner or operator of an 
electric utility steam generating unit which is also a cogeneration 
unit shall use the procedures in paragraphs (g)(1) and (2) of this 
section to calculate emission rates based on electrical output to the 
grid plus half of the equivalent electrical energy in the unit's 
process stream.
    (1) All conversions from Btu/hr unit input to MWe unit output must 
use equivalents found in 40 CFR 60.40(a)(1) for electric utilities 
(i.e., 250 million Btu/hr input to an electric utility steam generating 
unit is equivalent to 73 MWe input to the electric utility steam 
generating unit); 73 MWe input to the electric utility steam generating 
unit is equivalent to 25 MWe output from the boiler electric utility 
steam generating unit; therefore, 250 million Btu input to the electric 
utility steam generating unit is equivalent to 25 MWe output from the 
electric utility steam generating unit).
    (2) Use the Equation 1 of this section to determine the 
cogeneration Hg or Ni emission rate over a specific compliance period.
[GRAPHIC] [TIFF OMITTED] TP30JA04.021


Where:

ERcogen = Cogeneration Hg or Ni emission rate over a 
compliance period in lb/MWh;
E = Mass of Hg or Ni emitted from the stack over the same compliance 
period (lb);
Vgrid = Amount of energy sent to the grid over the same 
compliance period (MWh); and
Vprocess = Amount of energy converted to steam for process 
use over the same compliance period (MWh).

    (h) The owner or operator shall determine compliance with the Hg 
limit in Sec. 60.45a according to the procedures

[[Page 4743]]

in paragraphs (h)(1) through (3) of this section.
    (1) The owner or operator shall demonstrate compliance by 
calculating the arithmetic average of all weekly emission rates for Hg 
for the 12 successive calendar months, except for data obtained during 
startup, shutdown, or malfunction.
    (2) If a CEMS is used to demonstrate compliance, follow the 
procedures in paragraphs (h)(2)(i) through (ii) of this section to 
determine the 12-month rolling average.
    (i) Calculate the total mass of Hg emissions over a month (M), in 
micrograms ([mu]g), using Equation 2 of this section.
[GRAPHIC] [TIFF OMITTED] TP30JA04.022


Where:

M = Total mass of Hg emissions, ([mu]g);
C = Concentration of Hg recorded by CEMS per Performance Specification 
12A (40 CFR part 60, appendix B), micrograms per dry standard cubic 
meter ([mu]g/dscm);
V = Volumetric flow rate recorded at the same frequency as the CEMS 
reading for the Hg concentration indicated in PS-12A, cubic meters per 
hour (dscm/hr); and
t = total time period over which mass measurements are collected, (hr).

    (ii) Calculate the Hg emission rate for an output-based limit (lb/
hr) using Equation 3 of this section:
[GRAPHIC] [TIFF OMITTED] TP30JA04.035


Where:

ER = Hg emission rate, (lb/hr);
M = Total mass of Hg emissions, ([mu]g);
Conversion factor = 2.205 x 10-\9\; and
TPoutput-based = Total power, megawatt-hours (MWh).

    (3) If you use Method 324 (40 CFR part 63, appendix B), determine 
the 12-month rolling average Hg emission rate according to the 
applicable procedures in paragraphs (h)(3)(i) through (iv) of this 
section.
    (i) Sum the Hg concentrations for the emission rate period, ([mu]g/
dscm).
    (ii) Calculate the total volumetric flow rate for the emission rate 
period, (dscm).
    (iii) Multiply the total Hg concentration times the total 
volumetric rate to obtain the total mass of Hg for the emission rate 
period in micrograms.
    (iv) Calculate the Hg emission rate for an output-based limit (lb/
hr) using Equation 3 of this section.
    (i) The owner or operator shall determine compliance with the Ni 
limit in Sec. 60.46a according to the procedures in paragraphs (i)(1) 
through (2) of this section.
    (1) Ni emissions concentration for compliance under Sec. 60.46a is 
determined by the three-run average (nominal 1-hour runs) by Method 29 
of 40 CFR part 60, Appendix A, for the initial and subsequent 
performance tests.
    (2) Use the applicable procedures in paragraphs (2)(i) through (v) 
of this section to convert the Method 29 Ni emissions measurement to 
the output-based format for comparison to the Sec. 60.46a Ni emission 
limit.
    (i) Sum the Ni concentrations obtained from the Method 29 test 
runs, milligrams per dscm (mg/dscm).
    (ii) Calculate the total volumetric flow rate obtained during the 
Method 29 test runs, (dscm).
    (iii) Multiply the total Ni concentration times the total 
volumetric flow rate for the duration of the initial compliance testing 
period to obtain the total mass of Ni in milligrams.
    (iv) Calculate the output-based Ni emissions rate in a lb/ format 
using Equation 4 of this section.
[GRAPHIC] [TIFF OMITTED] TP30JA04.023


Where:

ER = Ni emission rate, (lb/hr);
M = Total mass of Ni emissions, (mg);
Conversion factor = 2.205 x 10-\6\; and
TPoutput-based = Total power, (MWh).

    (3) Compliance with the Ni emission limits under Sec. 60.46a is 
determined by the three-run average (nominal 1-hour runs) by Method 29 
for the initial and subsequent performance tests.
    (j) Quarterly accuracy determinations and daily calibration drift 
tests for gaseous Hg CEMS shall be performed in accordance with 
Procedure 1 (appendix F of 40 CFR part 60). Annual RATAs for Hg sorbent 
trap monitoring systems shall also be performed in accordance with 
Procedure 1.
    7. Newly redesignated Sec. 60.51a is amended by:
    a. Revising paragraph (a);
    b. In paragraph (c) introductory text by revising the existing 
references from ``Sec. 60.47a'' and ``Sec. 60.46a(h)'' to ``Sec. 
60.49a'' and ``Sec. 60.48a(h),'' respectively;
    c. In paragraph (d)(1) by revising the existing reference from 
``Sec. 60.46a(d)'' to ``Sec. 60.48a(d)''; and
    d. In paragraph (e)(1) by revising the existing reference from 
``Sec. 60.48a'' to ``Sec. 60.50a.''
    The revisions and additions read as follows:


Sec. 60.51a  Reporting requirements.

    (a) For sulfur dioxide, nitrogen oxides, particulate matter, Hg, 
and Ni emissions, the performance test data from the initial and 
subsequent performance test and from the performance evaluation of the 
continuous monitors (including the transmissometer) are submitted to 
the Administrator.
* * * * *
    8. Section 60.52a is added to read as follows:


Sec. 60.52a  Recordkeeping Requirements

    The owner or operator of an affected facility subject to the 
emissions limitations in Sec. 60.45a or Sec. 60.46a shall maintain 
records of all information needed to demonstrate compliance including 
performance tests, monitoring data, fuel analyses, and calculations.

Subpart GGGG--[Added]

    9. Part 60 is amended by adding subpart GGGG to read as follows:

Subpart GGGG--Emission Guidelines and Compliance Times for Oil-
fired Electric Utility Steam Generating Units

Sec.
60.4000 Scope
60.4005 Definitions
60.4010 Designated Facilities
60.4015 Emission Guidelines for Oil-fired Electric Utility Steam 
Generating Units
60.4020 Compliance Provisions and Performance Testing
60.4025 Reporting and Recordkeeping Guidelines
60.4030 Compliance Times


Sec. 60.4000  Scope

    This subpart contains emission guidelines and compliance times for 
the control of certain designated pollutants from certain designated 
electric utility steam generating units in accordance with section 
111(d) of the Act and subpart B of this part.


Sec. 60.4005  Definitions

    Terms used but not defined in this subpart have the meaning given 
them in the Act and in subparts A, B, and Da of this part.


Sec. 60.4010  Designated Facilities

    (a) The designated facility to which the emission guidelines apply 
is each existing electric utility steam generating unit for which 
construction, reconstruction or modification was commenced before 
January 30, 2004.
    (b) Physical or operational changes made to an existing electric 
utility steam generating unit solely to comply with an emission 
guideline are not considered a modification or reconstruction and

[[Page 4744]]

would not subject an existing electric utility steam generating unit to 
the requirements of subpart Da (see Sec. 60.40a of subpart Da).


Sec. 60.4015  Emission Guidelines for Oil-fired Electric Utility Steam 
Generating Units

    For approval, a State plan shall include emission limits for nickel 
(Ni) at least as protective as the provisions specified in paragraphs 
(a) and (b) of this section.
    (a) The emission limit for Ni contained in the gases discharged to 
the atmosphere from a designated facility is 210 pounds of Ni per 
trillion Btu (lb/TBtu) in an input-based format and 0.002 pounds of Ni 
per megawatt hour (lb/MWh) in an output-based format. The SI equivalent 
is 0.25 ng/J.
    (b) The emission limit for Ni for oil-fired electric utility steam 
generating units does not apply if the owner/operator permanently uses 
distillate oil as fuel. Except as provided in paragraph (5) of this 
section, the emissions limit for Ni for oil-fired electric utility 
steam generating units will immediately apply if the owner/operator 
subsequently uses a fuel other than distillate oil.
    (c) If you use an electrostatic precipitator (ESP) to meet a Ni 
emissions limit in this part, you must operate the ESP such that the 
hourly average voltage and secondary current (or total power input) do 
not fall below the limit established in the initial or subsequent 
performance test.
    (d) If you use a control device or combination of control devices 
other than an ESP to meet the Ni emissions limit, or you wish to 
establish and monitor an alternative operating limit and alternative 
monitoring parameters for an ESP, you must apply to the Administrator 
for approval of alternative monitoring under Sec. 60.13(i).
    (e) If you comply with the requirements in Sec. 60.4015(b) for 
switching fuel, and you must switch fuel because of an emergency, you 
must notify the Administrator in writing within 30 days of using a fuel 
other than distillate oil.


Sec. 60.4020  Compliance Provisions and Performance Testing

    For approval, a State plan shall include the performance testing 
compliance demonstration requirements as listed in paragraphs (a) and 
(b) of this section.
    (a) Affected facilities will conduct a performance test to 
demonstrate compliance with this section no later than 180 days after 
the initial startup or 180 days after publication of the final 
amendments, whichever is later and annually thereafter. The performance 
test is to be conducted using Method 29 of appendix A of this part to 
determine Ni emission concentration in the flue gas stream. The Ni 
emissions concentration for compliance under this part is determined by 
the three-run average (nominal 1-hour runs) using Method 29 of appendix 
A of this part for the initial and subsequent performance tests.
    (b) The owner or operator shall demonstrate compliance with the Ni 
limit in Sec. 60.46a according to the procedures in this paragraph to 
convert the Method 29 Ni measurement from the performance test to the 
selected format for comparison to the applicable Sec. 60.46a Ni 
emission limits.
    (1) Sum the Ni concentrations obtained from the Method 29 test 
runs, milligrams per dscm (mg/dscm).
    (2) Calculate the total volumetric flow obtained during the Method 
29 test runs, (dscm).
    (3) Multiply the total Ni concentration times the total volumetric 
flow for the duration of the initial compliance testing period to 
obtain the total mass of Ni in milligrams.
    (4) Calculate the input-based Ni emissions rate in a lb/TBtu format 
using Equation 1 of this section.
[GRAPHIC] [TIFF OMITTED] TP30JA04.024


Where:

ER = Ni emissions rate, (lb/TBtu);
M = Total mass of Ni emissions, (mg);
Conversion factor = 2.205 x 10-6; used to convert milligrams 
to pounds; and
TPinput-based = Total power, (TBtu).

    (5) Calculate the output-based Ni emissions rate in a lb/MWh format 
using Equation 2 of this section.
[GRAPHIC] [TIFF OMITTED] TP30JA04.025

Where:

ER = Ni emissions rate, (lb/MWh);
M = Total mass of Ni emissions, (mg);
Conversion factor = 2.205 x 10-6; and
TPoutput-based = Total power, (MWh).


Sec. 60.4025  Reporting and Recordkeeping Guidelines

    For approval, a State plan shall include the reporting and 
recordkeeping provisions listed in Sec. 60.52a of subpart Da of this 
part, as applicable.


Sec. 60.4030  Compliance Times

    (a) Except as provided for under paragraph (b) of this section, 
planning, awarding of contracts, and installation of electric utility 
steam generating unit air emission control equipment capable of meeting 
the emission guidelines established under Sec. 60.4015 shall be 
accomplished within 30 months after the effective date of a State 
emission standard for electric utility steam generating units.

APPENDIX B PART 60

    10. Appendix B to part 60 is amended by adding in numerical 
order new Performance Specification 12A to read as follows:

Performance Specification 12a--Specifications and Test Procedures for 
Total Vapor Phase Mercury Continuous Emission Monitoring Systems in 
Stationary Sources

    1.0 Scope and Application
    1.1 Analyte.

------------------------------------------------------------------------
                           Analyte                              CAS No.
------------------------------------------------------------------------
Mercury (Hg)................................................   7439-97-6
------------------------------------------------------------------------

    1.2 Applicability.
    1.2.1 This specification is for evaluating the acceptability of 
total vapor phase Hg continuous emission monitoring systems (CEMS) 
installed on the exit gases from fossil fuel fired boilers at the 
time of or soon after installation and whenever specified in the 
regulations. The Hg CEMS must be capable of measuring the total 
concentration in [mu]g/m3 (regardless of speciation) of 
vapor phase Hg, and recording that concentration on a dry basis, 
corrected to 20 degrees C and 7 percent CO2. Particle 
bound Hg is not included. The CEMS must include a) a diluent 
(CO2) monitor, which must meet Performance Specification 
3 in 40 CFR part 60, appendix B, and b) an automatic sampling 
system. Existing diluent and flow monitoring equipment can be used.
    This specification is not designed to evaluate an installed 
CEMS's performance over an extended period of time nor does it 
identify specific calibration techniques and auxiliary procedures to 
assess the CEMS's performance. The source owner or operator, 
however, is responsible to calibrate, maintain, and operate the CEMS 
properly. The Administrator may require, under CAA section 114, the 
operator to conduct CEMS performance evaluations at other times 
besides the initial test to evaluate the CEMS performance. See 40 
CFR 60.13(c).
    2.0 Summary of Performance Specification
    Procedures for measuring CEMS relative accuracy, measurement 
error and drift are outlined. CEMS installation and measurement 
location specifications, and data reduction procedures are included. 
Conformance of the CEMS with the Performance Specification is 
determined.
    3.0 Definitions
    3.1 Continuous Emission Monitoring System (CEMS) means the total 
equipment required for the determination of a pollutant 
concentration. The system consists of the following major 
subsystems:
    3.2 Sample Interface means that portion of the CEMS used for one 
or more of the following: sample acquisition, sample transport, 
sample conditioning, and protection of the monitor from the effects 
of the stack effluent.

[[Page 4745]]

    3.3 Hg Analyzer means that portion of the CEMS that measures the 
total vapor phase Hg mass concentration and generates a proportional 
output.
    3.4 Diluent Analyzer (if applicable) means that portion of the 
CEMS that senses the diluent gas (CO2) and generates an 
output proportional to the gas concentration.
    3.5 Data Recorder means that portion of the CEMS that provides a 
permanent electronic record of the analyzer output. The data 
recorder can provide automatic data reduction and CEMS control 
capabilities.
    3.6 Span Value means the upper limit of the intended Hg 
concentration measurement range. The span value is a value equal to 
two times the emission standard.
    3.7 Measurement Error (ME) means the difference between the 
concentration indicated by the CEMS and the known concentration 
generated by a reference gas when the entire CEMS, including the 
sampling interface, is challenged. An ME test procedure is performed 
to document the accuracy and linearity of the CEMS at several points 
over the measurement range.
    3.8 Upscale Drift (UD) means the difference in the CEMS output 
responses to a Hg reference gas when the entire CEMS, including the 
sampling interface, is challenged after a stated period of operation 
during which no unscheduled maintenance, repair, or adjustment took 
place.
    3.9 Zero Drift (ZD) means the difference in the CEMS output 
responses to a zero gas when the entire CEMS, including the sampling 
interface, is challenged after a stated period of operation during 
which no unscheduled maintenance, repair, or adjustment took place.
    3.10 Relative Accuracy (RA) means the absolute mean difference 
between the pollutant concentration(s) determined by the CEMS and 
the value determined by the reference method (RM) plus the 2.5 
percent error confidence coefficient of a series of tests divided by 
the mean of the RM tests or the applicable emission limit.
    4.0 Interferences [Reserved]
    5.0 Safety
    The procedures required under this performance specification may 
involve hazardous materials, operations, and equipment. This 
performance specification may not address all of the safety problems 
associated with these procedures. It is the responsibility of the 
user to establish appropriate safety and health practices and 
determine the applicable regulatory limitations prior to performing 
these procedures. The CEMS user's manual and materials recommended 
by the reference method should be consulted for specific precautions 
to be taken.
    6.0 Equipment and Supplies
    6.1 CEMS Equipment Specifications.
    6.1.1 Data Recorder Scale. The CEMS data recorder output range 
must include zero and a high level value. The high level value must 
be approximately 2 times the Hg concentration corresponding to the 
emission standard level for the stack gas under the circumstances 
existing as the stack gas is sampled. If a lower high level value is 
used, the CEMS must have the capability of providing multiple high 
level values (one of which is equal to the span value) or be capable 
of automatically changing the high level value as required (up to 
specified high level value) such that the measured value does not 
exceed 95 percent of the high level value.
    6.1.2 The CEMS design should also provide for the determination 
of response drift at both the zero and mid-level value. If this is 
not possible or practical, the design must allow these 
determinations to be conducted at a low-level value (zero to 20 
percent of the high-level value) and at a value between 50 and 100 
percent of the high-level value.
    6.2 Reference Gas Delivery System. The reference gas delivery 
system must be designed so that the flowrate of reference gas 
introduced to the CEMS is the same at all three challenge levels 
specified in Section 7.1 and at all times exceeds the flow 
requirements of the CEMS.
    6.3 Other equipment and supplies, as needed by the applicable 
reference method used. See Section 8.6.2.
    7.0 Reagents and Standards
    7.1 Reference Gases.
    7.1.1 Zero--N2 or Air. Less than 0.1 [mu]g Hg/m\3\.
    7.1.2 Mid-level Hg\0\ and HgCl2. 40 to 60 percent of 
span.
    7.1.3 High-level Hg\0\ and HgCl2. 80 to 100 percent 
of span.
    7.2 Reagents and Standards. May be required for the reference 
methods. See Section 8.6.2.
    8.0 Performance Specification Test Procedure
    8.1 Installation and Measurement Location Specifications.
    8.1.1 CEMS Installation. Install the CEMS at an accessible 
location downstream of all pollution control equipment. Since the Hg 
CEMS sample system normally extracts gas from a single point in the 
stack, use a location that has been shown to be free of 
stratification for SO2 and NOX through 
concentration measurement traverses for those gases. If the cause of 
failure to meet the RA test requirement is determined to be the 
measurement location and a satisfactory correction technique cannot 
be established, the Administrator may require the CEMS to be 
relocated.
    Measurement locations and points or paths that are most likely 
to provide data that will meet the RA requirements are listed below.
    8.1.2 Measurement Location. The measurement location should be 
(1) at least eight equivalent diameters downstream of the nearest 
control device, point of pollutant generation, bend, or other point 
at which a change of pollutant concentration or flow disturbance may 
occur, and (2) at least two equivalent diameters upstream from the 
effluent exhaust. The equivalent duct diameter is calculated as per 
40 CFR part 60, appendix A, Method 1.
    8.1.3 Hg CEMS Sample extraction Point. Use a sample extraction 
point (1) no less than 1.0 meter from the stack or duct wall, or (2) 
within the centroidal velocity traverse area of the stack or duct 
cross section.
    8.2 Reference Method (RM) Measurement Location and Traverse 
Points. The RM measurement location should be at a point or points 
in the same stack cross sectional area as the CEMS is located, 
according to the criteria above. The RM and CEMS locations need not 
be immediately adjacent. They should be as close as possible without 
causing interference with one another.
    8.3 Measurement Error (ME) Test Procedure. The Hg CEMS must be 
constructed to permit the introduction of known (NIST traceable) 
concentrations of elemental mercury (Hg\0\) and mercuric chloride 
(HgCl2) separately into the sampling system of the CEMS 
immediately preceding the sample extraction filtration system such 
that the entire CEMS can be challenged. Inject sequentially each of 
the three reference gases (zero, mid-level, and high level) for each 
Hg species. CEMS measurements of each reference gas shall not differ 
from their respective reference values by more than 5 percent of the 
span value. If this specification is not met, identify and correct 
the problem before proceeding.
    8.4 Upscale Drift (UD) Test Procedure.
    8.4.1 UD Test Period. While the affected facility is operating 
at more than 50 percent of normal load, or as specified in an 
applicable subpart, determine the magnitude of the UD once each day 
(at 24-hour intervals) for 7 consecutive days according to the 
procedure given in Sections 8.4.2 through 8.4.3.
    8.4.2 The purpose of the UD measurement is to verify the ability 
of the CEMS to conform to the established CEMS response used for 
determining emission concentrations or emission rates. Therefore, if 
periodic automatic or manual adjustments are made to the CEMS zero 
and response settings, conduct the UD test immediately before these 
adjustments, or conduct it in such a way that the UD can be 
determined.
    8.4.3 Conduct the UD test at the mid-level point specified in 
Section 7.1. Evaluate upscale drift for elemental Hg 
(Hg0) only. Introduce the reference gas to the CEMS. 
Record the CEMS response and subtract the reference value from the 
CEM value (see example data sheet in Figure 12A-1).
    8.5 Zero Drift (ZD) Test Procedure.
    8.5.1 ZD Test Period. While the affected facility is operating 
at more than 50 percent of normal load, or as specified in an 
applicable subpart, determine the magnitude of the ZD once each day 
(at 24-hour intervals) for 7 consecutive days according to the 
procedure given in Sections 8.5.2 through 8.5.3.
    8.5.2 The purpose of the ZD measurement is to verify the ability 
of the CEMS to conform to the established CEMS response used for 
determining emission concentrations or emission rates. Therefore, if 
periodic automatic or manual adjustments are made to the CEMS zero 
and response settings, conduct the ZD test immediately before these 
adjustments, or conduct it in such a way that the ZD can be 
determined.
    8.5.3 Conduct the ZD test at the zero level specified in Section 
7.1. Introduce the zero gas to the CEMS. Record the CEMS response 
and subtract the zero value from the CEM value (see example data 
sheet in Figure 12A-1).
    8.6 Relative Accuracy (RA) Test Procedure.

[[Page 4746]]

    8.6.1 RA Test Period. Conduct the RA test according to the 
procedure given in Sections 8.6.2 through 8.6.6 while the affected 
facility is operating at normal full load, or as specified in an 
applicable subpart. The RA test can be conducted during the UD test 
period.
    8.6.2 Reference Method (RM). Unless otherwise specified in an 
applicable subpart of the regulations, use either Method 29 in 
appendix A to 40 CFR part 60, or ASTM Method D 6784-02 (incorporated 
by reference in Sec. 60.17) as the RM for Hg. Do not include the 
filterable portion of the sample when making comparisons to the CEMS 
results. Conduct all RM tests with paired or duplicate sampling 
systems.
    8.6.3 Sampling Strategy for RM Tests. Conduct the RM tests in 
such a way that they will yield results representative of the 
emissions from the source and can be compared to the CEMS data. It 
is preferable to conduct the diluent (if applicable), moisture (if 
needed), and Hg measurements simultaneously. However, diluent and 
moisture measurements that are taken within an hour of the Hg 
measurements can used to adjust the results to a consistent basis. 
In order to correlate the CEMS and RM data properly, note the 
beginning and end of each RM test period for each paired RM run 
(including the exact time of day) on the CEMS chart recordings or 
other permanent record of output.
    8.6.4 Number and length of RM Tests. Conduct a minimum of nine 
paired sets of all necessary RM test runs that meet the relative 
standard deviation criteria of this PS. Use a minimum sample run 
time of 2 hours for each pair.

    Note: More than nine paired sets of RM tests can be performed. 
If this option is chosen, test results can be rejected so long as 
the total number of paired RM test results used to determine the 
CEMS RA is greater than or equal to nine. However, all data must be 
reported, including the rejected data.

    8.6.5 Correlation of RM and CEMS Data. Correlate the CEMS and 
the RM test data as to the time and duration by first determining 
from the CEMS final output (the one used for reporting) the 
integrated average pollutant concentration or emission rate for each 
pollutant RM test period. Consider system response time, if 
important, and confirm that the results are on a consistent 
moisture, temperature, and diluent concentration basis with the 
paired RM test. Then, compare each integrated CEMS value against the 
corresponding average of the paired RM values.
    8.6.6 Paired RM Outliers.
    8.6.6.1 Outliers are identified through the determination of 
precision and any systematic bias of the paired RM tests. Data that 
do not meet this criteria should be flagged as a data quality 
problem. The primary reason for performing dual RM sampling is to 
generate information to quantify the precision of the RM data. The 
relative standard deviation (RSD) of paired data is the parameter 
used to quantify data precision. Determine RSD for two 
simultaneously gathered data points as follows:
[GRAPHIC] [TIFF OMITTED] TP30JA04.026

where Ca and Cb are concentration values determined from trains A 
and B respectively. For RSD calculation, the concentration units are 
unimportant so long as they are consistent.
    8.6.6.2 A minimum precision criteria for RM Hg data is that RSD 
for any data pair must be [le]10 percent as long as the mean Hg 
concentration is greater than 1.0 [mu]g/m3. If the mean 
Hg concentration is less than or equal to 1.0 [mu]g/m3, 
the RSD must be [le]20 percent. Pairs of RM data exceeding these RSD 
criteria should be eliminated from the data set used to develop a Hg 
CEMS correlation or to assess CEMS RA.
    8.6.7 Calculate the mean difference between the RM and CEMS 
values in the units of the emission standard, the standard 
deviation, the confidence coefficient, and the RA according to the 
procedures in Section 12.0.
    8.7 Reporting. At a minimum (check with the appropriate EPA 
Regional Office, State, or local Agency for additional requirements, 
if any), summarize in tabular form the results of the RD tests and 
the RA tests or alternative RA procedure, as appropriate. Include 
all data sheets, calculations, charts (records of CEMS responses), 
reference gas concentration certifications, and any other 
information necessary to confirm that the performance of the CEMS 
meets the performance criteria.
    9.0 Quality Control [Reserved]
    10.0 Calibration and Standardization [Reserved]
    11.0 Analytical Procedure
    Sample collection and analysis are concurrent for this 
Performance Specification (see Section 8.0). Refer to the RM 
employed for specific analytical procedures.
    12.0 Calculations and Data Analysis
    Summarize the results on a data sheet similar to that shown in 
Figure 2-2 for Performance Specification 2.
    12.1 Consistent Basis. All data from the RM and CEMS must be on 
a consistent dry basis and, as applicable, on a consistent diluent 
basis. Correct the RM and CEMS data for moisture and diluent as 
follows:
    12.1.1 Moisture Correction (as applicable). Correct each wet RM 
run for moisture with the corresponding Method 4 data; correct each 
wet CEMS run using the corresponding CEMS moisture monitor date 
using Equation 12A-2.
[GRAPHIC] [TIFF OMITTED] TP30JA04.027

    12.1.2 Correction to Units of Standard (as applicable). Correct 
each dry RM run to the units of the emission standard with the 
corresponding Method 3B data; correct each dry CEMS run using the 
corresponding CEMS diluent monitor data as follows:
    12.1.3 Correct to Diluent Basis. The following is an example of 
concentration (ppm) correction to 7 percent oxygen.
[GRAPHIC] [TIFF OMITTED] TP30JA04.028


[[Page 4747]]


    The following is an example of mass/gross calorific value (lbs/
million Btu) correction. lbs/MMBtu = Conc(dry) (F-factor) 
((20.9/(20.9--percent O2))
    12.2 Arithmetic Mean. Calculate the arithmetic mean of the 
difference, d, of a data set as follows:
[GRAPHIC] [TIFF OMITTED] TP30JA04.029

Where:

n = Number of data points.

    12.3 Standard Deviation. Calculate the standard deviation, 
Sd, as follows:
[GRAPHIC] [TIFF OMITTED] TP30JA04.030

Where:
[GRAPHIC] [TIFF OMITTED] TP30JA04.031

    12.4 Confidence Coefficient. Calculate the 2.5 percent error 
confidence coefficient (one-tailed), CC, as follows:
[GRAPHIC] [TIFF OMITTED] TP30JA04.032

    12.5 Relative Accuracy. Calculate the RA of a set of data as 
follows:

Where:

[verbar]d[verbar] = Absolute value of the mean differences (from 
Equation 12A-4).
[verbar]CC[verbar] = Absolute value of the confidence coefficient 
(from Equation 12A-6).
RM = Average RM value. In cases where the average emissions for the 
test are less than 50 percent of the applicable standard, substitute 
the emission standard value in the denominator of Eq. 12A-7 in place 
of R[bond]M[bond]. In all other cases, use R[bond]M[bond]

    13.0 Method Performance
    13.1 Measurement Error (ME). ME is assessed at mid-level and 
high-level values as given below using standards for both 
Hg0 and HgCl2. The mean difference between the 
indicated CEMS concentration and the reference concentration value 
for each standard shall be no greater than 5 percent of span. The 
same difference for the zero reference gas
[GRAPHIC] [TIFF OMITTED] TP30JA04.033

 shall be no greater than 5 percent of span.
    13.2 Upscale Drift (UD). The CEMS design must allow the 
determination of UD of the analyzer. The CEMS response can not drift 
or deviate from the benchmark value of the reference standard by 
more than 5 percent of span for the mid level value. Evaluate 
upscale drift for Hg0 only.
    13.3 Zero Drift (ZD). The CEMS design must allow the 
determination of drift at the zero level. This drift shall not 
exceed 5 percent of span.
    13.4 Relative Accuracy (RA). The RA of the CEMS must be no 
greater than 20 percent of the mean value of the RM test data in 
terms of units of the emission standard, or 10 percent of the 
applicable standard, whichever is greater.
    14.0 Pollution Prevention. [Reserved]
    15.0 Waste Management. [Reserved]
    16.0 Alternative Procedures. [Reserved]
    17.0 Bibliography.
    17.1 40 CFR part 60, appendix B, ``Performance Specification 2--
Specifications and Test Procedures for SO2 and 
NOX Continuous Emission Monitoring Systems in Stationary 
Sources.''
    17.2 40 CFR part 60, appendix A, ``Method 29--Determination of 
Metals Emissions from Stationary Sources.''
    17.3 ASTM Method D6784-02, ``Standard Test Method for Elemental, 
Oxidized, Particle-Bound and Total Mercury in Flue Gas Generated 
from Coal-Fired Stationary Sources (Ontario Hydro Method).''
    18.0 Tables and Figures.

                                             Table 12A-1.--t-Values.
----------------------------------------------------------------------------------------------------------------
                           n a                               t0.975      n a       t0.975      n a       t0.975
----------------------------------------------------------------------------------------------------------------
2........................................................     12.706          7      2.447         12      2.201
3........................................................      4.303          8      2.365         13      2.179
4........................................................      3.182          9      2.306         14      2.160
5........................................................      2.776         10      2.262         15      2.145
6........................................................      2.571         11      2.228         16     2.131
----------------------------------------------------------------------------------------------------------------
a The values in this table are already corrected for n-1 degrees of freedom. Use n equal to the number of
  individual values.


------------------------------------------------------------------------
                              Reference    CEMS
             Day    Date and    value      value   Measurement    Drift
                      time       (C)        (M)       error
------------------------------------------------------------------------
Zero
 Level
         -----------
 
         -----------
 
         -----------
 
         -----------
Mid-
 level
         -----------
 
         -----------

[[Page 4748]]

 
 
         -----------
 
         -----------
High-
 level
         -----------
 
         -----------
 
         -----------
 
---------
           Figure 12A-1.--Zero and Upscale Drift Determination

PART 63--[AMENDED]

    11. The authority citation for part 63 continues to read as 
follows:

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

    12. Section 63.14 is amended by adding paragraph (b)(35) to read as 
follows:


Sec. 63.14  Incorporations by Reference.

* * * * *
    (b) * * *
    (35) ASTM D6784-02, Standard Test Method for Elemental, Oxidized, 
Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired 
Stationary Sources (Ontario Hydro Method), for appendix B to part 63, 
Method 324.
* * * * *

APPENDIX B PART 63

    13. Appendix B to part 63 is amended by adding in numerical 
order new Method 324 to read as follows:

Method 324--Determination of Vapor Phase Flue Gas Mercury Emissions 
From Stationary Sources Using Dry Sorbent Trap Sampling

    1.0 Introduction.
    This method describes sampling criteria and procedures for the 
continuous sampling of mercury (Hg) emissions in combustion flue gas 
streams using sorbent traps. Analysis of each trap can be by cold 
vapor atomic fluorescence spectrometry (AF) which is described in 
this method, or by cold vapor atomic absorption spectrometry (AA). 
Only the AF analytical method is detailed in this method, with 
reference being made to other published methods for the AA 
analytical procedure. The Electric Power Research Institute has 
investigated the AF analytical procedure in the field with the 
support of ADA-ES and Frontier Geosciences, Inc. The AF procedure is 
based on EPA Method 1631, Revision E: Mercury in Water by Oxidation, 
Purge and Trap, and Cold Vapor Atomic Fluorescence Spectrometry. 
Persons using this method should have a thorough working knowledge 
of Methods 1, 2, 3, 4 and 5 of 40 CFR part 60, appendix A.
    1.1 Scope and Application.
    1.1.1 Analytes. The analyte measured by this method is total 
vapor-phase Hg, which represents the sum of elemental (CAS Number 
7439-97-6) and oxidized forms of Hg, mass concentration (micrograms/
dscm) in flue gas samples.
    1.1.2 Applicability. This method is applicable to the 
determination of vapor-phase Hg concentrations ranging from 0.03 
[mu]g/dncm to 100 [mu]g/dncm in low-dust applications, including 
controlled and uncontrolled emissions from stationary sources, only 
when specified within the regulations. When employed to demonstrate 
compliance with an emission regulation, paired sampling is to be 
performed as part of the method quality control procedure. The 
method is appropriate for flue gas Hg measurements from combustion 
sources. Very low Hg concentrations will require greater sample 
volumes. The method can be used over any period from 30 minutes to 
several days in duration, provided appropriate sample volumes are 
collected and all the quality control criteria in Section 9.0 are 
met. When sampling for periods greater than 12 hours, the sample 
rate is required to be maintained at a constant proportion to the 
total stack flowrate, 25 percent to ensure 
representativeness of the sample collected.
    2.0 Summary of Method.
    Known volumes of flue gas are extracted from a duct through a 
single or paired sorbent trap with a nominal flow rate of 0.2 to 0.6 
liters per minute through each trap. Each trap is then acid leached 
and the resulting leachate is analyzed by cold vapor atomic 
fluorescence spectrometry (CVAFS) detection. The AF analytical 
procedure is described in detail in EPA Method 1631. Analysis by AA 
can be performed by existing recognized procedures, such as that 
contained in ASTM Method D6784-02 (incorporated by reference, see 
Sec. 63.14) or EPA Method 29.
    3.0 Definitions. [Reserved]
    4.0 Clean Handling and Contamination.
    During preparation of the sorbent traps, as well as transport, 
field handling, sampling, recovery, and laboratory analysis, special 
attention must be paid to cleanliness procedures. This is to avoid 
Hg contamination of the samples, which generally contain very small 
amounts of Hg. For specifics on how to avoid contamination, Section 
4 of Method 1631 should be well understood.
    5.0 Safety.
    5.1 Site hazards must be prepared for in advance of applying 
this method in the field. Suitable clothing to protect against site 
hazards is required, and requires advance coordination with the site 
to understand the conditions and applicable safety policies. At a 
minimum, portions of the sampling system will be hot, requiring 
appropriate gloves, long sleeves, and caution in handling this 
equipment.
    5.2 Laboratory safety policies are to minimize risk of chemical 
exposure and to properly handle waste disposal. Personnel will don 
appropriate laboratory attire according to a Chemical Hygiene Plan 
established by the laboratory. This includes, but is not limited to, 
laboratory coat, safety goggles, and nitrile gloves under clean 
gloves.
    5.3 The toxicity or carcinogenicity of reagents used in this 
method has not been fully established. The procedures required in 
this method may involve hazardous materials, operations, and 
equipment. This method may not address all of the safety problems 
associated with these procedures. It is the responsibility of the 
user to establish appropriate safety and health practices and 
determine the applicable regulatory limitations prior to performing 
these procedures. Each chemical should be regarded as a potential 
health hazard and exposure to these compounds should be minimized. 
Chemists should refer to the MSDS for each chemical with which they 
are working.
    5.4 Any wastes generated by this procedure must be disposed of 
according to a hazardous materials management plan that details and 
tracks various waste streams and disposal procedures.
    6.0 Equipment and Supplies.
    6.1 Hg Sampling Train. A Schematic of a single trap sampling 
train used for this method is shown in Figure 324-1. Where this 
method is used to collect data to demonstrate compliance with a 
regulation, it must be performed with paired sorbent trap equipment.

[[Page 4749]]



 
 
 
        Figure 324-1. Hg Sampling Train illustrating Single Trap.
 

[GRAPHIC] [TIFF OMITTED] TP30JA04.034

    6.1.1 Sorbent Trap. Use sorbent traps with separate main and 
backup sections in series for collection of Hg. Selection of the 
sorbent trap shall be based on: (1) Achievement of the performance 
criteria of this method, and (2) data is available to demonstrate 
the method can pass the criteria in EPA Method 301 when used in this 
method and when the results are compared with those from EPA Method 
29, EPA Method 101A, or ASTM Method 6784-02 for the measurement of 
vapor-phase Hg in a similar flue gas matrix. Appropriate traps are 
referred to as ``sorbent trap'' throughout this method. The method 
requires the analysis of Hg in both main and backup portions of the 
sorbent within each trap. The sorbent trap should be obtained from a 
reliable source that has clean handling procedures in place for 
ultra low-level Hg analysis. This will help assure the low Hg 
environment required to manufacture sorbent traps with low blank 
levels of Hg. Sorbent trap sampling requirements or needed 
characteristics are shown in Table 324-1. Blank/cleanliness and 
other requirements are described in Table 324-2. The sorbent trap is 
supported on a probe and inserted directly into the flue gas stream, 
as shown on Figure 324-1. The sampled sorbent trap is the entire Hg 
sample.
    6.1.2 Sampling Probe. The probe assembly shall have a leak-free 
attachment to the sorbent trap. For duct temperatures from 200 to 
375F, no heating is required. For duct temperatures 
less than 200F, the sorbent tube must be heated to at 
least 200F or higher to avoid liquid condensation in 
the sorbent trap by using a heated probe. For duct temperatures 
greater than 375F, a large sorbent trap must be used, 
as shown in Table 324-1, and no heating is required. A thermocouple 
is used to monitor stack temperature.
    6.1.3 Umbilical Vacuum Line. A 250 F heated 
umbilical line shall be used to convey to the moisture knockout the 
sampled gas that has passed through the sorbent trap and probe 
assembly.
    6.1.4 Moisture Knockout. Impingers and desiccant can be combined 
to dry the sample gas prior to entering the dry gas meter. 
Alternative sample drying methods are acceptable as long as they do 
not affect sample volume measurement.
    6.1.5 Vacuum Pump. A leak tight vacuum pump capable of 
delivering a controlled extraction flow rate between 0.1 to 0.8 
liters per minute.
    6.1.6 Dry Gas Meter. Use a dry gas meter that is calibrated 
according to the procedures in 40 CFR part 60, appendix A, Method 5, 
to measure the total sample volume collected. The dry gas meter must 
be sufficiently accurate to measure the sample volume within 2 
percent, calibrated at the selected flow rate and conditions 
actually encountered during sampling, and equipped with a 
temperature sensor capable of measuring typical meter temperatures 
accurately to within 3 C (5.4 F).
    6.2 Sample Analysis Equipment. Laboratory equipment as described 
in Method 1631, Sections 6.3 to 6.7 is required for analysis by AF. 
For analysis by AA, refer to Method 29 or ASTM Method 6784-02.

          Table 324-1.--Sorbent Trap and Sampling Requirements
------------------------------------------------------------------------
    Item to be determined      Small sorbent trap    Large sorbent trap
------------------------------------------------------------------------
Sampling Target: Hg Loading   Minimum = 0.025       Minimum = 0.10 [mu]g/
 Range, ug.                    [mu]g/trap..          trap.
                              Maximum = 150 [mu]g/  Maximum = 1800 [mu]g/
                               trap.                 trap.
Sampling Duration Required:   Minimum = 30 minutes  Minimum = 24 hours.
 limits on sample times.      Maximum = 24 hours..  Maximum = 10 days.
Sampling Temperature          200 to 375 F.             thn-eq>F.
Sampling Rate Required......  0.2 to 0.6 L/min;     0.2 to 0.6 L/min;
                               start at 0.4 L/min.   start at 0.4 L/min.
                              Must be constant      Must be constant
                               proportion within     proportion of stack
                               25% if greater     25%.
                               constant rate
                               within 25%
                               if less than 12
                               hours.
------------------------------------------------------------------------


[[Page 4750]]

    7.0 Analysis by AF, Reagents and Standards.
    For analysis by AF, use Method 1631, Sections 7.1-7.3 and 7.5-
7.12 for laboratory reagents and standards. Refer to Method 29 or 
ASTM Method 6784-02 for analysis by AA.
    7.1 Reagent Water. Same as Method 1631, Section 7.1.
    7.2 Air. Same as Method 1631, Section 7.2.
    7.3 Hydrochloric Acid. Same as Method 1631, Section 7.3.
    7.4 Stannous Chloride. Same as Method 1631, Section 7.5.
    7.5 Bromine Monochloride (BrCl, 0.01N). Same as Method 1631, 
Section 7.6.
    7.6 Hg Standards. Same as Method 1631, Sections 7.7 to 7.11.
    7.7 Nitric Acid. Reagent grade, low Hg.
    7.8 Sulfuric Acid. Reagent grade, low Hg.
    7.9 Nitrogen. Same as Method 1631, Section 7.12.
    7.10 Argon. Same as Method 1631, Section 7.13.
    8.0 Sample Collection and Transport.
    8.1 Pre-Test.
    8.1.1 Site information should be obtained in accordance with 
Method 1 (40 CFR part 60, appendix A). Identify a location that has 
been shown to be free of stratification for SO2 and 
NOX through concentration measurement traverses for those 
gases. An estimation of the expected Hg concentration is required to 
establish minimum sample volumes. Based on estimated minimum sample 
volume and normal sample rates for each size trap used, determine 
sampling duration with the data provided in Table 324-1.
    8.1.2 Sorbent traps must be obtained from a reliable source such 
that high quality control and trace cleanliness are maintained. 
Method detection limits will be adversely affected if adequate 
cleanliness is not maintained. Sorbent traps should be handled only 
with powder-free low Hg gloves (vinyl, latex, or nitrile are 
acceptable) that have not touched any other surface. The sorbent 
traps should not be removed from their clean storage containers 
until after the preliminary leak check has been completed. Field 
efforts at clean handling of the sorbent traps are key to the 
success of this method.
    8.1.3 Assemble the sample train according to Figure 324-1, 
except omit the sorbent trap.
    8.1.4 Preliminary Leak Check. Perform system leak check without 
the single or dual sorbent traps in place. This entails plugging the 
end of the probe to which each sorbent trap will be affixed, and 
using the vacuum pump to draw a vacuum in each sample train. Adjust 
the vacuum in the sample train to 15 inches Hg. A rotameter on the 
dry gas meter will indicate the leakage rate. The leakage rate must 
be less than 2 percent of the planned sampling rate.
    8.1.5 Release the vacuum in the sample train, turn off the pump, 
and affix the sorbent trap to the end of the probe, using clean 
handling procedures. Leave the flue gas end of the sorbent trap 
plugged.
    8.1.6 Pre-test leak check. Perform a leak check with the Sorbent 
trap in place. Use the sampling vacuum pump to draw a vacuum in the 
sample train. Adjust the vacuum in the sample train to 15 inches Hg. 
A rotameter on the dry gas meter will indicate the leakage rate. 
Record the leakage rate. The leakage rate must be less than 2 
percent of the planned sampling rate. Once the leak check passes 
this criterion, carefully release the vacuum in the sample train 
(the sorbent trap must not be exposed to abrupt changes in pressure 
or to backflow), then re-cap the flue gas end of the sorbent trap 
until the probe is ready for insertion. The sorbent trap packing 
beds must be undisturbed by the leak test to prevent gas channeling 
through the media during sampling.
    8.1.7 Use temperature controllers to heat the portions of the 
trains that require it. The sorbent trap must be maintained between 
200 and 375 F during sampling.
    8.1.8 Gas temperature and static pressure must be considered 
prior to sampling in order to maintain proper safety precautions 
during sampling.
    8.2 Sample Collection.
    8.2.1 Remove the plug from the end of a sorbent trap and store 
it in a clean sorbent trap storage container. Remove the sample duct 
port cap and insert the probe. Secure the probe and ensure that no 
leakage occurs between the duct and environment.
    8.2.2 Record initial data including the start time, starting dry 
gas meter readings, and the name of the field tester(s). Set the 
initial sample flow rate to 0.4 L/min (+/-25 percent).
    8.2.3 For constant-flow sampling (samples less than 12 hours in 
duration), every 10-15 minutes during the sampling period: record 
the time, the sample flow rate, the gas meter readings, the duct 
temperature, the flow meter temperatures, temperatures of heated 
equipment such as the vacuum lines and the probes (if heated), and 
the sampling vacuum reading. Adjust the sample rate as needed, 
maintaining constant sampling within +/-25 percent of the initial 
reading.
    8.2.4 For constant proportion sampling (samples 12 hours or 
greater in duration), every hour during the sampling period: record 
the time, the sample flow rate, the gas meter readings, the duct 
temperature, the flow meter temperatures, temperatures of heated 
equipment such as the vacuum lines and the probes (if heated), and 
the sampling vacuum readings. Also record the stack flow rate 
reading, whether provided as a CEM flow monitor signal, a pitot 
probe or other direct flow indication, or a plant input signal. 
Adjust the sampling rate to maintain proportional sampling within +/
-25 percent relative to the total stack flowrate.
    8.2.5 Obtain and record operating data for the facility during 
the test period, including total stack flowrate and the oxygen 
concentration at the flue gas test location. Barometric pressure 
must be obtained for correcting sample volume to standard 
conditions.
    8.2.6 Post Test Leak Check. When sampling is completed, turn off 
the sample pump, remove the probe from the port and carefully re-
plug the end of the sorbent trap. Perform leak check by turning on 
the sampling vacuum pumps with the plug in place. The rotameter on 
the dry gas meters will indicate the leakage rates. Record the 
leakage rate and vacuum. The leakage rate must be less than 2 
percent of the actual sampling rate. Following the leak check, 
carefully release the vacuum in the sample train.
    8.2.7 Sample Recovery. Recover each sampled sorbent trap by 
removing it from the probe, plugging both ends with the clean caps 
provided with the sorbent trap, and then wiping any dirt off the 
outside of the sorbent trap. Place the sorbent trap into the clean 
sample storage container in which it was provided, along with the 
data sheet that includes the post-test leak check, final volume, and 
test end time.
    8.3 Quality Control Samples and Requirements.
    8.3.1 Field blanks. Refer to Table 324-2.
    8.3.2 Duplicate (paired or side by side) samples. Refer to 
Section 8.6.6 of Performance Specification 12A of 40 CFR part 60, 
appendix B for this criteria.
    8.3.3 Breakthrough performance data (``B'' bed in each trap, or 
second traps behind). Refer to Table 324-2.
    8.3.4 Field spikes (sorbent traps spiked with Hg in the lab and 
periodically sampled in the field to determine overall accuracy). 
Refer to Table 324-2.
    8.3.5 Laboratory matrix and matrix spike duplicates. Refer to 
Table 324-2.
    9.0 Quality Control.
    Table 324-2 summarizes the major quantifiable QC components.

                Table 324-2.--Quality Control for Samples
------------------------------------------------------------------------
      QA/QC            Acceptance                          Corrective
  specification         criteria          Frequency          action
------------------------------------------------------------------------
Leak-check.        <2% of sampling    Pre- and post-    Pre-sampling:
                    rate.              sampling.         repair leak.
                                                         Post sampling:
                                                         Flag data and
                                                         repeat run if
                                                         for regulatory
                                                         compliance.
Sample Flow Rate   0.4 L/min          Throughout run    Adjust when data
 for samples less   initially and      every 10-15       is recorded.
 than 12 hours in   25% of
                    initial rate
                    throughout run.
Sample Flow Rate   0.4 L/min          Throughout run    Adjust when data
 for samples        initially and      every hour.       is recorded.
 greater than 12    maintain 
 duration.          25% of ration of
                    flue gas flow
                    rate throughout
                    sampling.

[[Page 4751]]

 
Sorbent trap       <5 ng/trap and a   3 per analysis    ................
 laboratory blank   standard           set of 20
 (same lot as       deviation of       sorbent traps.
 samples).          <1:0 ng/trap
                    (n=3).
Sorbet trap field  <5 ng/trap and a   1 per every 10    ................
 blank (same lot    standard           field samples
 as samples)        deviation of       collected.
                    <1.0 ng/trap
                    (n=3) OR <5% of
                    average sample
                    collected.
B-Trap Bed         <2% of A-Trap Bed  Every sample.     ................
 Analysis.          Value OR < 5 ng/
                    trap.
Paired Train       Same as Section    ................  ................
 Results.           8.6.6 of PS-12A
                    of 40 CFR Par
                    60, Appendix B.
Field Spikes.      80% to 120%        For long-term     If the first 4
                    recovery.          regulatory        field spikes do
                                       monitoring, 1     not meet the
                                       per every 3       20%
                                       first 12          criteria, take
                                       samples.          corrective
                                                         sampling and
                                                         laboratory
                                                         measures and
                                                         repeat at the 1
                                                         per every 3
                                                         sample rate
                                                         until the 20% criteria
                                                         is met.
Laboratory matrix  85% to 115%        1 per every 10
 and matrix spike   recovery.          or 20 samples--
 duplicates.                           to be
                                       determined.
------------------------------------------------------------------------

    10.0 Calibration and Standards.
    Same as Sections 10.1, 10.2 and 10.4 of Method 1631.
    10.1 Calibration and Standardization. Same as Sections 10.1 and 
10.4 of Method 1631.
    10.2 Bubbler System. Same as Section 10.2 of M1631.
    10.3 Flow-Injection System. Not applicable.
    11.0 Analytical Procedures.
    11.1 Preparation Step. The sorbent traps are received and 
processed in a low-Hg environment (class-100 laminar-flow hood and 
gaseous Hg air concentrations below 20 ng/m3) following 
clean-handling procedures. Any dirt or particulate present on the 
exterior of the trap must be removed to avoid contamination of the 
sample. The sorbent traps are then opened and the sorbent bed(s) 
transferred to an appropriate sized trace-clean vessel. It is 
recommended that the height of the trace-clean vessel be at least 3 
times the diameter to facilitate a refluxing action.
    11.2 Leaching Step. The sorbent trap is then subjected to a hot-
acid leach using a 70:30 ratio mixture of concentrated 
HNO3/H2SO4. The acid volume must be 
40 percent of the expected end volume of the digest after dilution. 
The HNO3/H2SO4 acid to carbon ratio 
should be approximately 35:1. The leachate is then heated to a 
temperature of 50 to 60C for 1.5 to 2.0 hours in the 
finger-tight capped vessels. This process may generate significant 
quantities of noxious and corrosive gasses and must only be 
performed in a well-ventilated fume hood. Care must be taken to 
prevent excessive heated leaching of the samples as this will begin 
to break down the charcoal material.
    11.3 Dilution Step. After the leached samples have been removed 
from the hot plate and allowed to cool to room temperature, they are 
brought to volume with a 5 percent (v/v) solution of 0.01 N BrCl. As 
the leaching digest contains a substantial amount of dissolved 
gasses, add the BrCl slowly, especially if the samples are still 
warm. As before, this procedure must be performed in a properly 
functioning fume hood. The sample is now ready for analysis.
    11.4 Hg Reduction and Purging. (Reference Section 11.2 of M1631 
except that NH2OH is not used.)
    11.4.1 Bubbler System. Pipette an aliquot of the digested sample 
into the bubbler containing pre-blanked reagent water and a soda 
lime trap connected to the exhaust port. Add stannous chloride 
(SnCl2) to reduce the aliquot and then seal the bubbler. 
Connect gold sample traps to the end of the soda lime trap as shown 
in Figures 1 and 2 of Method 1631. Finally, connect the 
N2 lines and purge for 20 minutes. The sample trap can 
then be added into the analytical train. M1631, Section 11.2.1.
    11.4.2 Flow Injection System. If required.
    11.5 Desorption of Hg from the gold trap, and peak evaluation. 
Use Section 11.3 and 11.4 in M1631.
    11.6 Instrument Calibration. Analyze the standards by AA or AF 
following the guidelines specified by the instrument manufacturer. 
Construct a calibration curve by plotting the absorbances of the 
standards versus [mu]g/l Hg. The R2 for the calibration 
curve should be 0.999 or better. If the curve does not have an 
R2 value equal to or better than 0.999 then the curve 
should be rerun. If the curve still does not meet this criteria then 
new standards should be prepared and the instrument recalibrated. 
All calibration points contained in the curve must be within 10 
percent of the calibration value when the calibration curve is 
applied to the calibration standards.
    11.7 Sample Analysis. Analyze the samples in duplicate following 
the same procedures used for instrument calibration. From the 
calibration curve, determine sample Hg concentrations. To determine 
total Hg mass in each sample fraction, refer to calculations in 
Section 15. Record all sample dilutions
    11.8 Continued Calibration Performance. To verify continued 
calibration performance, a continuing calibration check standard 
should be run every 10 samples. The measured Hg concentration of the 
continuing calibration check standard must be within 10 percent of 
the expected value.
    11.9 Measurement Precision. The QA/QC for the analytical portion 
of this method is that every sample, after it has been prepared, is 
to be analyzed in duplicate with every tenth sample analyzed in 
triplicate. These results must be within 10 percent of each other. 
If this is not the case, then the instrument must be recalibrated 
and the samples reanalyzed.
    11.10 Measurement Accuracy. Following calibration, an 
independently prepared standard (not from same calibration stock 
solution) should be analyzed. In addition, after every ten samples, 
a known spike sample (standard addition) must be analyzed. The 
measured Hg content of the spiked samples must be within 10 percent 
of the expected value.
    11.11 Independent QA/QC Checks. It is suggested that the QA/QC 
procedures developed for a test program include submitting, on 
occasion, spiked Hg samples to the analytical laboratory by either 
the prime contractor, if different from the laboratory, or an 
independent organization. The measured Hg content of reference 
samples must be within 15 percent of the expected value. If this 
limit is exceeded, corrective action (e.g., re-calibration) must be 
taken and the samples re-analyzed.
    11.12 Quality Assurance/Quality Control. For this method, it is 
important that both the sampling team and analytical people be very 
well trained in the procedures. This is a complicated method that 
requires a high-level of sampling and analytical experience. For the 
sampling portion of the QA/QC procedure, both solution and field 
blanks are required. It should be noted that if high-quality 
reagents are used and care is taken in their preparation and in the 
train assembly, there should be little, if any, Hg measured in 
either the solution or field blanks.
    11.13 Solution Blanks. Solution blanks must be taken and 
analyzed every time a new batch of solution is prepared. If Hg is 
detected in these solution blanks, the concentration is subtracted 
from the measured sample results. The maximum amount that can be 
subtracted is 10 percent of the measured result or 10 times the 
detection limit of the instrument whichever is lower. If the 
solution blanks are greater

[[Page 4752]]

than 10 percent the data must be flagged as suspect.
    11.14 Field Blanks. A field blank is performed by assembling a 
sample train, transporting it to the sampling location during the 
sampling period, and recovering it as a regular sample. These data 
are used to ensure that there is no contamination as a result of the 
sampling activities. A minimum of one field blank at each sampling 
location must be completed for each test site. Any Hg detected in 
the field blanks cannot be subtracted from the results. Whether or 
not the Hg detected in the field blanks is significant is determined 
based on the QA/QC procedures established prior to the testing. At a 
minimum, if field blanks exceed 30 percent of the measured value at 
the corresponding location, the data must be flagged as suspect.
    12.0 Calculations and Data Analysis
    Use Section 12 in M1631.
    13.0 Constant Proportion Sampling
    Calculate the Sample Rate/Stack Flow = ``x.'' ``X'' must be 
maintained within 0.75 ``x'' to 1.25 ``x'' for sampling times in 
excess of 12 hours. For mass emission rate calculations, use the 
flow CEM total measured flow corresponding to the sorbent trap 
sample time period.
    14.0 Sampling and Data Summary Calculations
    Refer to 40 CFR part 60, appendix A, Methods 2, 4, and 5 for 
example calculations.
    15.0 Pollution Prevention
    Refer to Section 13 in Method 1631.
    16.0 Waste Management
    Refer to Section 14 in Method 1631.
    17.0 Bibliography
    17.1 EPA Method 1631, Revision E ``Mercury in Water by 
Oxidation, Purge and Trap, and Cold Vapor Atomic Fluorescence 
Spectrometry,'' August 2002.
    17.2 ``Comparison of Sampling Methods to Determine Total and 
Speciated Mercury in Flue Gas,'' CRADA F00-038 Final Report, DOE/
NETL-2001/1147, January 4, 2001.
    17.3 40 CFR part 60, appendix A, ``Method 29--Determination of 
Metals Emissions From Stationary Sources.''
    17.4 40 CFR part 60, appendix B, ``Performance Specification 
12A, Specification and Test Procedures for Total Vapor Phase Mercury 
Continuous Emission Monitoring Systems in Stationary Sources.''
    17.5 ASTM Method D6784-02, ``Standard Test Method for Elemental, 
Oxidized, Particle-bound and Total Mercury in Flue Gas Generated 
from Coal-Fired Stationary Sources (Ontario Hydro Method).''
[FR Doc. 04-1539 Filed 1-29-04; 8:45 am]
BILLING CODE 6560-50-P