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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
Note: EPA no longer updates this information, but it may be useful as a reference or resource.
[Federal Register: January 30, 2004 (Volume 69, Number 20)]
[Proposed Rules]
[Page 4651-4752]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr30ja04-12]
[[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, maxwell.bill@epa.gov.
[[Page 4653]]
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.
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\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.regulations.gov/ 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
[[Page 4654]]
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 a-and-r-docket@epa.gov, Attention
Docket ID No. OAR-2002-0056. In contrast to EPA's electronic public
docket, EPA's e-mail system is not an anonymous access system. If you
send an e-mail comment directly to the Docket without going through
EPA's electronic public docket, EPA's e-mail system automatically
captures your e-mail address. E-mail addresses that are automatically
captured by EPA's e-mail system are included as part of the comment
that is placed in the official public docket and made available in
EPA's electronic public docket.
You may submit comments on a disk or CD-ROM that you mail to the
mailing address identified below. These electronic submissions will be
accepted in WordPerfect or ASCII file format. Avoid the use of special
characters and any form of encryption.
By Mail. Send your comments (in duplicate if possible) to EPA
Docket Center (Air Docket), U.S. EPA West (6102T), Room B-108, 1200
Pennsylvania Ave., NW., Washington, DC, 20460, Attention Docket ID No.
OAR-2002-0056. The EPA requests a separate copy also be sent to the
contact person listed above (see FOR FURTHER INFORMATION CONTACT).
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
[[Page 4655]]
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.
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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\
---------------------------------------------------------------------------
\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
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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