[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 4651]]
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Part IV
Environmental Protection Agency
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40 CFR Parts 60 and 63
Proposed National Emission Standards for Hazardous Air Pollutants; and,
in the Alternative, Proposed Standards of Performance for New and
Existing Stationary Sources: Electric Utility Steam Generating Units;
Proposed Rule
[[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.
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SUPPLEMENTARY INFORMATION: Regulated Entities. Categories and entities
potentially regulated by this action include the following:
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NAICS Examples of potentially
Category code \1\ regulated entities
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Industry........................ 221112 Fossil fuel-fired electric
utility steam generating
units.
Federal government.............. 2 221122 Fossil fuel-fired electric
utility steam generating
units owned by the Federal
government.
State/local/tribal government... 2 221122 Fossil fuel-fired electric
utility steam generating
units owned by
municipalities.
921150 Fossil fuel-fired electric
utility steam generating
units in Indian Country.
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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.epa.gov/edocket/ to submit or view public
comments, access the index listing of the contents of the official
public docket, and access those documents in the public docket that are
available electronically. Once in the system, select ``search,'' then
key in the appropriate docket identification number.
Certain types of information will not be placed in EPA Dockets.
Information claimed as confidential business information (CBI) and
other information whose disclosure is restricted by statute, which is
not included in the official public docket, will not be available for
public viewing in EPA's electronic public docket. The EPA's policy is
that copyrighted material will not be placed in EPA's electronic public
docket but will be available only in printed paper form in the official
public docket. To the extent feasible, publicly available docket
materials will be made available in EPA's electronic public docket.
When a document is selected from the index list in EPA Dockets, the
system will identify whether the document is available for viewing in
EPA's electronic public docket. Although not all docket materials may
be available electronically, you may still access any of the publicly
available docket materials through the EPA Docket Center.
For public commenters, it is important to note that EPA's policy is
that public comments, whether submitted electronically or on paper,
will be made available for public viewing in EPA's electronic public
docket as EPA receives them and without change, unless the comment
contains copyrighted material, CBI, or other information whose
disclosure is restricted by statute. When EPA identifies a comment
containing copyrighted material, EPA will provide a reference to that
material in the version of the comment that is placed in EPA's
electronic public docket. The entire printed comment, including the
copyrighted material, will be available in the public docket.
Public comments submitted on computer disks that are mailed or
delivered to the docket will be transferred to EPA's electronic public
docket. Public comments that are mailed or delivered to the Docket will
be scanned and placed in EPA's electronic public docket. Where
practical, physical objects will be photographed, and the photograph
will be placed in EPA's electronic public docket along with a brief
description written by the docket staff.
For additional information about EPA's electronic public docket,
visit EPA Dockets online or see 67 FR 38102, May 31, 2002.
You may submit comments electronically, by mail, or through hand
delivery/courier. To ensure proper receipt by EPA, identify the
appropriate docket identification number in the subject line on the
first page of your comment. Please ensure that your comments are
submitted within the specified comment period. Comments received after
the close of the comment period will be marked ``late.'' The EPA is not
required to consider these late comments. However, late comments may be
considered if time permits.
Electronically. If you submit an electronic comment as prescribed
below, EPA recommends that you include your name, mailing address, and
an e-mail address or other contact information in the body of your
comment. Also include this contact information on the outside of any
disk or CD-ROM you submit, and in any cover letter accompanying the
disk or CD-ROM. This ensures that you can be identified as the
submitter of the comment and allows EPA to contact you in case EPA
cannot read your comment due to technical difficulties or needs further
information on the substance of your comment. The EPA's policy is that
EPA will not edit your comment, and any identifying or contact
information provided in the body of a comment will be included as part
of the comment that is placed in the official public docket and made
available in EPA's electronic public docket. If EPA cannot read your
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comment due to technical difficulties and cannot contact you for
clarification, EPA may not be able to consider your comment.
Your use of EPA's electronic public docket to submit comments to
EPA electronically is EPA's preferred method for receiving comments. Go
directly to EPA Dockets at http://www.epa.gov/edocket and follow the
online instructions for submitting comments. To access EPA's electronic
public docket from the EPA Internet home page, select ``Information
Sources,'' ``Dockets,'' and ``EPA Dockets.'' Once in the system, select
``search,'' and then key in Docket ID No. OAR-2002-0056. The system is
an anonymous access system, which means EPA will not know your
identity, e-mail address, or other contact information unless you
provide it in the body of your comment.
Comments may be sent by e-mail to 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
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Existing Sources: Electric Utility Steam Generating Units
A. Background Information
1. What is the statutory authority for the proposed section 111
rulemaking?
2. What criteria are used in the development of NSPS?
B. Proposed New Standards and Guidelines
1. What source category is affected by the proposed rulemaking?
2. What pollutants are covered by the proposed rulemaking?
3. What are the affected sources?
4. What emission limits must I meet?
5. What are the testing and initial compliance requirements?
6. What are the continuous compliance requirements?
7. What are the notification, recordkeeping, and reporting
requirements?
C. Rationale for the Proposed Subpart Da Standards
1. What is the rationale for the proposed subpart Da Hg and Ni
standards?
2. What is the performance of control technology on Hg?
3. What is the performance of control technology on Ni?
4. What is the regulatory approach?
5. What are the subpart Da Hg and Ni emission standards?
6. How did EPA select the format for the proposed standards?
7. How did EPA determine testing and monitoring requirements for
the proposed standards?
8. How did EPA determine the compliance times for the proposed
standards?
9. How did EPA determine the required records and reports for
the proposed standards?
D. Rationale for the Proposed Hg Emission Guidelines
1. What is the authority for cap-and-trade under section 111(d)?
2. What is the regulatory approach for existing and new sources?
3. What are the subpart Da Hg emission guidelines?
4. How did EPA select the format for the proposed emission
guidelines?
5. How did EPA determine the emissions monitoring and reporting
requirements for the proposed emission guidelines?
6. How did EPA determine the compliance times for the proposed
emission guidelines?
E. Rationale for the Proposed Ni Guidelines
1. What is the rationale for the proposed subpart Da Ni emission
guidelines?
2. How did EPA address dual-fired (oil/natural gas) units?
V. Impacts of the Proposed Rule
A. What are the air impacts?
B. What are the water and solid waste impacts?
C. What are the energy impacts?
D. What are the control costs?
E. Can we achieve the goals of the proposed section 112 MACT
rule in a less costly manner?
F. What are the social costs and benefits of the proposed
section 112 MACT rule?
VI. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review
B. Paperwork Reduction Act
C. Regulatory Flexibility Act
D. Unfunded Mandates Reform Act
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation and Coordination with
Indian Tribal Governments
G. Executive Order 13045: Protection of Children from
Environmental Health and Safety Risks
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
I. National Technology Transfer and Advancement Act
I. Background Information
A. What Is the Regulatory Development Background?
1. What Is the Statutory Background?
In the 1990 Amendments to the CAA, Congress substantially modified
section 112 of the CAA, which is the provision of the CAA that
expressly addresses HAP. Among other things, CAA section 112 sets forth
a list of 188 HAP, to which EPA can add, and requires EPA to list
categories and subcategories of ``major sources'' of listed pollutants.
Congress defined ``major source'' as any stationary source \1\ or group
of stationary sources at a single location and under common control
that emits or has the potential to emit 10 tons per year or more of any
HAP or 25 tons per year or more of any combination of HAP. (See CAA
section 112(a)(1).)
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\1\ A ``stationary source'' of hazardous air pollutants is any
building, structure, facility or installation that emits or may emit
any air pollutant. CAA Section 111(a)(3).
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Section 112 further requires EPA to list categories and
subcategories of area sources \2\ provided those sources meet one of
the following statutory criteria: (1) EPA determines that the category
or subcategory of area sources presents a threat of adverse effects to
human health or the environment in a manner that warrants regulation
under CAA section 112; or (2) the category or subcategory of area
sources falls within the purview of CAA section 112(k)(3)(B) (the Urban
Area Source Strategy). Once EPA has listed a source category, whether
it be a category of major sources or area sources, section 112(d) calls
for the promulgation of emission standards.
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\2\ A stationary source that is not a major source is an ``area
source.'' CAA section 112(a)(2).
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Congress, therefore, treated area sources differently from major
sources in that categories of major sources are listed under CAA
section 112 based solely on the number of tons of HAP emitted from
sources in the category on an annual basis. By contrast, area source
categories are not listed unless either the health and environmental
effects warrant regulation under section 112, or reductions from the
category are required to meet the requirements of the Urban Area Source
Strategy.
Congress also treated Utility Units differently from major and area
sources. (See CAA section 112(n)(1)(A).) Specifically, Congress
directed EPA to conduct a study that analyzed what hazards to public
health resulting from emissions of HAP from Utility Units, if any,
would reasonably be anticipated to occur following imposition of the
other requirements of the CAA. Congress further directed EPA to report
to it the results of such study. Finally, Congress directed EPA to
determine whether, based on the results of the study, regulation of
Utility Units under CAA section 112 was appropriate and necessary.
Congress did not define the terms ``appropriate'' and ``necessary,''
but required that regulation of Utility Units under section 112 occur
only if EPA found such regulation to be both appropriate and necessary.
2. What Was the Scope of, and Basis for, EPA's December 2000 Finding?
Scope of finding. On December 20, 2000, pursuant to CAA section
112(n)(1)(A), EPA determined that it was both appropriate and necessary
to regulate coal- and oil-fired Utility Units under section 112 of the
CAA. (65 FR 79826) Solely because of this finding, EPA added these
units to the list of source categories under section 112(c) of the CAA.
(Id.) In December 2000, EPA also concluded that the impacts associated
with HAP emissions from natural-gas fired Utility Units were negligible
and that regulation of such units under CAA section 112 was not
appropriate or necessary.
Basis for finding. Nature of record. The EPA premised its December
2000 ``appropriate and necessary'' finding primarily on the results of
the February 1998 ``Study of Hazardous Air Pollutant Emissions from
Electric Utility Steam Generating Units--Final Report to Congress''
(Utility RTC). The EPA prepared this study pursuant to the terms of CAA
section 112(n)(1)(A) and provided it to Congress. The EPA also based
its December 2000 finding on certain information that it obtained
following completion of the Utility RTC, which served only to confirm
the conclusions of the Utility RTC.
In the Utility RTC, EPA examined 67 of the 188 HAP listed in
section 112(b) of the CAA. These 67 HAP represent the pollutants EPA
believes could potentially be emitted from Utility Units. The EPA
assessed these HAP in terms of potential health hazards and
[[Page 4656]]
summarized its conclusions with regard to the HAP in the Utility RTC.
The Utility RTC identifies Hg as the HAP emitted from Utility Units
that is of greatest concern from a public health perspective.
(Executive Summary Utility RTC (``ES''), at 27.) The health effects of
Hg exposure are presented elsewhere in this preamble.
The Utility RTC also included information indicating that Ni was
the pollutant of concern from oil-fired Utility Units due to its high
level of emissions from those units and the potential health effects
arising from exposure to it. The health effects of Ni exposure also are
presented elsewhere in this preamble.
As for the other non-Hg and non-Ni metallic HAP examined, EPA made
the following conclusions. With regard to arsenic, a metal, EPA
concluded that there were several uncertainties associated with both
the cancer risk estimates from arsenic and the health effects data for
arsenic, and that further analyses were needed to characterize the
risks posed by arsenic emissions from Utility Units (ES at 21). As to
lead and cadmium, which are also metals, EPA found that the emission
quantities and inhalation risks of these HAP were low and did not
warrant further evaluation (ES at 24). As for the remaining, non-Hg,
non-Ni metallic HAP, EPA found that such pollutants posed no hazards to
public health.
The EPA also examined HCl and HF, which are inorganic or acid gas
HAP, and found no exceedances of the health benchmark for either
substance (ES at 24). As for dioxins, organic HAP, EPA concluded that
the quantitative exposure and risk results for such HAP ``d(id) not
conclusively demonstrate the existence of health risks of concern
associated with exposures to utility emissions either on a national
scale or from any actual individual utility.'' (Utility RTC at 11-5.)
Finally, EPA concluded that emissions from Utility Units of the
remaining HAP examined in the Study did not appear to be a concern for
public health (65 FR 79827).
As part of the Utility RTC, EPA also examined several provisions of
the CAA relating to electric utilities, including different sections of
title I and title IV (Utility RTC, Ch.1). The EPA did not focus in the
Utility RTC or the December 2000 finding, however, on whether section
111 of the CAA could be used specifically to regulate HAP from new and
existing Utility Units, or the extent to which regulation under section
111 might address any HAP-related issues for Utility Units.
Following completion of the Utility RTC, EPA obtained additional
information, which is summarized in EPA's December 20, 2000, notice.
That information addressed Hg and methylmercury and confirmed the
hazards to public health associated therewith.\4\
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\4\ Subsequent to issuance of the December 2000 Notice, EPA also
conducted additional modeling for HCl, chlorine (Cl2),
and HF. Such modeling predicted concentrations of these HAP to be
well below the relevant respiratory benchmark concentrations for the
model plants examined. Hazard indices did not exceed 0.2 for any of
these HAP. This modeling, therefore, confirmed the conclusion EPA
reached in the Utility RTC, which is that inorganic or acid gas HAP
from Utility Units, even in the absence of additional control
measures, do not pose any hazards to the public health.
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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
[[Page 4666]]
characteristic that all conventional boilers have in common is that
they inject PC and primary air through a burner where ignition of the
PC occurs, which in turn creates an individual flame. Conventional
boilers fire through many such burners mounted in the furnace walls.
In stoker-fired boilers, fuel is deposited on a moving or
stationary grate or spread mechanically or pneumatically from points
usually 10 to 20 feet above the grate. The process utilizes both the
combustion of fine coal powder in air and the combustion of larger
particles that fall and burn in the fuel bed on the grate.
Cyclone-fired boilers use several water-cooled horizontal burners
that produce high-temperature flames that circulate in a cyclonic
pattern. The burner design and placement cause the coal ash to become a
molten slag that is collected below the furnace.
Fluidized bed combustors combust coal, in a bed of inert material
(e.g., sand, silica, alumina, or ash) and/or a sorbent such as
limestone, that is suspended through the action of primary combustion
air distributed below the combustor floor. ``Fluidized'' refers to the
state of the bed of material (coal and inert material (or sorbent)) as
gas passes through the bed. As the gas flow rate is increased, the
force on the fuel particles becomes just sufficient to cause buoyancy.
The gas cushion between the solids allows the particles to move freely,
giving the bed a liquid-like (or fluidized) characteristic.
Integrated-coal gasification combined cycle units are specialized
units in which coal is first converted into synthetic coal gas. In this
conversion process, the carbon in the coal reacts with water to produce
hydrogen gas and carbon monoxide (CO). The synthetic coal gas (syngas)
is then combusted in a combustion turbine which drives an electric
generator. Hot gases from the combustion turbine then pass through a
waste heat boiler to produce steam. This steam is fed to a steam
turbine connected to a second electric generator.
After examining a number of possible subcategorization options, EPA
identified three basic ways to subcategorize coal-fired Utility Units.
No subcategorization. This approach would treat all coal ranks and
all coal combustion process types as one, with the MACT floor developed
using all of the coal-fired unit data.
Subcategorization by coal rank. Subcategorization by individual
coal rank accommodates the various design and control constraints
resulting from the various coal ranks.
Subcategorization by process type. Another option is to
subcategorize by process type (e.g., stoker-fired, cyclone-fired, FBC,
IGCC).
To determine the appropriate subcategorization approach, the EPA
evaluated fuel, process, and control technology and found that the data
did not identify any common attribute among the top units that could be
credited with the demonstrated better performance. The EPA found that
each of the best-performing units had a combination of factors that was
the basis for the better performance on that particular unit. The
factors identified included the Hg and chlorine (Cl) contents of the
coal, the speciation of the Hg in the flue gas stream, and the control
device configuration.
Based on this information, EPA then analyzed the available data to
determine which coal ranks were burned, and why, to ascertain if
changing coal rank would be a conceivable control strategy. The EPA
found that the characteristics of the coal rank to be burned was the
driving factor in how a coal-fired unit was designed. Further, the
choice of coal ranks to be burned for a given unit is based on economic
issues, including availability of the coal within the region or locale.
A number of coal-fired units, including all known lignite-fired units,
are ``mine mouth'' (or near mine-mouth) operations (i.e., the unit is
constructed on or near the coal mine itself with coal transport often
being done by conveyor directly from the mine) and many do not have the
infrastructure in place (e.g., interstate rail lines) to import other
ranks of coal in quantities sufficient to replace all lignite coal
combusted. The EPA also found that substitution of coal rank, in most
cases, would require significant modification or retooling of a unit,
which would indicate a pertinent difference in the design/operation of
the units. Because not all units are designed to combust the same rank
of coal and the Hg emissions from some ranks of coal are easier to
control than those from other ranks, a standard based on ``no
subcategorization'' likely would be unachievable for some units. For
these reasons, EPA decided that subcategorization of coal-fired units
based on coal rank (fuel type) was warranted. We note again that
certain Utility Units are, in fact, able to effectively combust coals
from different ASTM ranks because of the overlap in coal classification
properties. We do not, however, believe that this ``overlap''
compromises our ability to subcategorize by coal rank because it
remains true that coal rank is a significant factor that distinguishes
the design and operational characteristics of different boilers. We ask
for comment on this issue.
Although conventional-, stoker-, and cyclone-fired boilers use
different firing techniques, the Hg emissions characteristics of these
boilers are similar (when common ranks of coal are fired) and,
therefore, the units can be grouped together and further
subcategorization by these process types is not necessary.
Based on their unique firing designs, FBC units employ a
fundamentally different process for combusting coal from that employed
by conventional-, stoker-, or cyclone-fired boilers. Fluidized-bed
combustors are capable of combusting many coal ranks, including coal
refuse. For these reasons, FBC units can be considered a distinct type
of boiler. However, the Hg emissions test data results for FBC units
were not substantially different from those at similarly-fueled
conventionally-fired units with similar emission levels, either in mass
of emissions or in emissions characteristics. Therefore, EPA has
decided not to establish a separate subcategory for FBC units.
Integrated gasification combined cycle units combust a synthetic
coal gas. No coal is directly combusted in the unit during operation
(although a coal-derived fuel is fired), and, thus, IGCC units are a
distinct class or type of boiler for the proposed rule.
For the purposes of the proposed rule and based on the above
information, the coal-fired units at existing affected sources are
subcategorized into five subcategories, four based on coal rank and one
based on process type: bituminous (including anthracite);
subbituminous; lignite; coal refuse (which includes anthracite coal
refuse (culm), bituminous coal refuse (gob), and subbituminous coal
refuse); and IGCC (coal syngas). Because few units fire anthracite coal
and because there are significant similarities in the emissions
resulting from the combustion of anthracite and bituminous coals, EPA
chose to combine anthracite coal with bituminous coal for the purposes
of this rule. A more detailed description of the specific elements and
rationale used to determine this subcategorization scheme is located in
the docket.
Subcategorization within existing oil-fired units. The EPA analyzed
the data available on the fuel, process, emission profiles, and APCD
for oil-fired units at existing affected sources. An oil-fired electric
utility boiler combusts fuel oil exclusively, or combusts fuel oil at
certain times of the year and natural gas at other times (not
simultaneously). The choice of when to combust oil
[[Page 4667]]
exclusively or to alternate between oil and natural gas at a single
boiler is usually based on economics or fuel availability (including
seasonal availability). The ASTM classifies oils by ``grade,'' a term
which relates to the amount of refinement that the oil undergoes. The
level of refinement directly affects the Ni and carbon content of the
oil and other related parameters such as sulfur content, heating value,
and specific gravity. The most refined fuel oil used by the oil-fired
electric utility industry is known as No. 2 fuel oil (also known as
distillate oil or medium domestic fuel oil). The least refined fuel oil
used by the oil-fired electric utility industry is known as No. 6 fuel
oil (also known as residual oil or Bunker C oil). By comparison, No. 2
fuel oil is lower in Ni, sulfur, ash content, and heating value but
higher in carbon content than No. 6 fuel oil. Only a handful of boilers
(8 of 218) fire No. 2 distillate fuel oil exclusively. (2001 EIA data)
However, 28 out of 218 boilers fire No. 2 distillate fuel oil and No. 6
(residual) fuel oil in the same boiler (either simultaneously or at
separate times).
The type of oil to be burned has little impact on overall boiler
design. The goal of the plant designer is to make sure the plant can
handle the different viscosities of oil (and natural gas if applicable)
that the boiler is likely to combust.
There is only one basic type of oil combustion process used in the
oil-fired electric utility industry, known as a conventional-fired
boiler. Conventional-fired boilers have a number of firing
configurations based on their burner placement. The basic
characteristic that all conventional-fired boilers have in common is
that they inject oil and primary air through a burner where ignition of
the oil occurs, which in turn creates an individual flame.
Conventional-fired boilers fire through many such burners mounted in
the furnace walls.
The data available to EPA indicated that there is very little
variation in the process or control technologies used in the industry.
Therefore, EPA found no criteria that would warrant further
subcategorization within existing oil-fired units and is not doing so
in the proposed rule.
Subcategorization within new units. With regard to new sources, EPA
has no data that indicate that the rationale for subcategorization for
existing coal-fired units would not be applicable to new units (i.e.,
there is no reason to believe that new units will not utilize the full
range of coal ranks and combustion process types currently used by
existing units). New units constructed at the same facilities as
existing units could still be restricted, at least in concept, to the
same physical constraints (e.g., coal handling and processing, access
to interstate rail lines) as are the co-located existing units.
Further, EPA has no data indicating the availability of existing coal
ranks is likely to substantially change for a given locale. For this
reason, EPA is proposing that the subcategorization scheme for new
coal- and oil-fired units be the same as for the existing units.
The EPA solicits comment on this decision that new and existing
units should be subcategorized in the same manner.
2. How Did EPA Select the Format of the Proposed Emission Standards?
The EPA has established pollution prevention as one of the its
highest priorities. One of the opportunities for pollution prevention
lies in simply using energy efficient technologies to minimize the
generation of emissions. The EPA has previously investigated ways to
promote energy efficiency in utility plants by changing the manner in
which it regulates flue gas emissions. Therefore, in an effort to
promote energy efficiency in utility steam generating facilities, the
Administrator is proposing output-based standards for new sources for
emissions of Hg and Ni under this rule. This format has been used
successfully on other EPA rules (e.g., subpart Da NSPS NOX,
40 CFR 63.44a). Existing sources would have the option of using either
input- or output-based limits based on the potential increase in cost
resulting from the need to add instrumentation.
Traditionally, utility emissions have been controlled on the basis
of boiler input energy (lb/million British thermal units (MMBtu) heat
input). However, input-based limitations allow units with low operating
efficiency to emit more per megawatt (MWe) of electricity produced than
more efficient units. Considering two units of equal capacity, under
current regulations, the less efficient unit will emit more because it
uses more fuel to produce the same amount of electricity. One way to
regulate mass emissions and plant efficiency is to express the emission
standard in terms of output energy. Thus, an output-based emission
standard would provide a regulatory incentive to enhance unit operating
efficiency and reduce emissions. Two of the possible output-based
formats considered for the revised standards were: (1) Mass emitted per
gross boiler steam output (lb/TBtu heat output), and (2) mass emitted
per net energy output (lb/MWh). The criteria used for selecting the
format were ease in monitoring and compliance testing and ability to
promote energy efficiency.
The objective of an output-based standard is to establish an
emission limit in a format that incorporates the effects of plant
efficiency. Additionally, the limit should be in a format that is
practical to implement. Thus, the format selected must satisfy the
following: (1) Provide flexibility in promotion of plant efficiency;
(2) permit measurement of parameters related to stack emissions and
plant efficiency, on a continuous basis; and (3) be suitable for
equitable application on a variety of power plant configurations.
The option of lb/TBtu steam output accounts only for boiler
efficiency, ignores both the turbine cycle efficiency and the effects
of energy consumption internal to the plant, and provides minimal
opportunities for promoting energy efficiency at the units. The EPA has
found that the second output-based format option of lb/MWh is
preferable as it accounts for all aspects of efficiency and provides
opportunity for promoting energy efficiency for the units.
The format of lb/MWh can be measured in two ways: net and gross
energy output. The net plant energy output provides the owners/
operators with all possible opportunities for promoting energy
efficiency and can easily accommodate both electrical and thermal
(process steam) outputs. The disadvantage of a net plant energy output
is that implementation could require significant and costly additional
monitoring and reporting systems because the energy output that is used
for internal components (and not sent to the grid) cannot be accounted
for by simply installing another meter. The gross plant energy output,
on the other hand, represents the energy generated before any internal
energy consumption and losses are considered. Rules based on this
format do not have the disadvantages of the net-based format mentioned
above.
Based on this analysis, an emission limit format based on mass of
emissions per gross plant energy output is selected for the proposed
output-based standard. Because electrical output at all power plants is
typically measured directly in MWe, a format in ``lb/MWh gross'' is
determined to be the most appropriate for the proposed rule. The EPA,
however, requests comments on the selected format of ``lb/MWh gross''
because a format of ``lb/MWh net'' may be more productive in
encouraging overall energy efficiency at electric utility plants.
[[Page 4668]]
Compliance with the output-based emission limit would require
continuous measurement of plant operating parameters associated with
the mass rate of emissions and gross energy outputs. In the case of
cogeneration plants where process steam is an output product, means
would have to be provided to measure the process steam flow conditions
and to determine the useful heat energy portion of the process steam
that is interchangeable with electrical output.
Instrumentation already exists in power plants to conduct these
measurements since the instrumentation is required to support current
emission regulations and normal plant operation. Consequently,
compliance with the output-based emission limit is not expected to
require any additional instrumentation. Therefore, no additional
instrumentation is required for conventional utility applications
(particularly for new sources) to comply with the output-based emission
limit. However, additional signal input wiring and programming is
expected to be required to convert the above measurements into the
compliance format (lb/MWh gross).
To use an output-based standard for cogeneration units (i.e., units
which use steam to both generate electricity and as a process input),
the energy content of the process steam must also be considered in
determining compliance with the output-based standard. The EPA has
determined that existing plant monitoring and energy calculation curves
are available and can be easily programmed to determine the steam's
equivalent electrical energy component. This component can then be
added to the plant's actual gross electrical output to arrive at the
plant's total gross energy output.
Since all the reported data obtained throughout the development of
the revised standards are in the current format of lb/TBtu heat input,
EPA applied an efficiency factor to the current format to develop the
output-based limits. The efficiency factor approach was selected
because the alternative of converting all the reported data in the
database to an output-basis would require extensive data gathering and
analyses. Applying a baseline efficiency would essentially convert the
selected heat input-based level to an output-based emission limit.
The output-based standard must be referenced to a baseline
efficiency. Most existing electric utility steam generating plants fall
in the range of 24 to 35 percent efficiency. However, newer units
operate around 35 percent efficiency; therefore, 35 percent was
selected as the baseline efficiency for new units; 32 percent was
selected as the baseline efficiency for existing units. The EPA
requests comment on: (1) Whether 35 percent is an appropriate baseline
efficiency, (2) how often the baseline efficiency should be reviewed
and revised in order to account for future improvements in electric
generation technology, and (3) the specific methodology or
methodologies appropriate and verifiable for determining the gross
energy output.
The efficiency of Utility Units usually is expressed in terms of
heat rate, which is the ratio of heat input, based on HHV of the fuel,
to the energy (i.e., electrical) output. The heat rate of a utility
steam generating unit operating at 32 percent efficiency is 11 joules
per watt hour (J/Wh) (10,667 Btu per kilowatt hour (kWh)); at 35
percent efficiency, the values are 10 J/Wh (9,833 Btu/kWh).
Determination of the gross efficiency of a cogeneration unit
includes the gross electrical output and the useful work achieved by
the energy (i.e., steam) delivered to an industrial process. Under a
Federal Energy Regulatory Commission (FERC) regulation, the efficiency
of cogeneration units is determined from ``* * * the useful power
output plus one-half the useful thermal output * * *,'' 18 CFR part
292, section 205. Therefore, to determine the process steam energy
contribution to net plant output, a 50 percent credit of the process
steam heat was selected. This approach is consistent with the approach
taken in the most recent subpart Da revision to the NOX
standard.
The proposed section 112 MACT rule does not include a specific
methodology or methodologies for determining the unit gross output. The
EPA would specify such methods in the final rule.
The proposed format for Hg also includes the use of a 12-month
rolling average in determining compliance. The EPA considers use of an
averaging period to be appropriate because Hg is not an acute health
hazard in the context of its emission from Utility Units. Rather, it is
a persistent bioaccumulative HAP that lends itself to monitoring over a
longer-term period. Several periods could be used for this purpose,
including 12-month rolling, quarterly, and yearly. Electric Utility
Units already monitor their fuel use on a monthly basis for reporting
to the DOE. Therefore, EPA is proposing to base the Hg standard on a
12-month rolling average period.
The EPA requests comment on all aspects of the analyses and
conclusions set forth above, including (1) whether 32 and 35 percent
are appropriate baseline efficiencies; (2) how often the baseline
efficiency should be reviewed and revised in order to account for
future improvements in electric generation technology; (3) whether the
output-based standard option in the proposed rule will promote energy
efficiency improvements; (4) the specific methodology or methodologies
appropriate and verifiable for determining the gross output of a steam
generating unit; and (5) whether a fixed percentage credit of 50
percent is representative of the useful heat in varying quality of
process steam flows.
3. How Did EPA Determine the Proposed MACT Floor for Existing Units?
All standards established pursuant to the process set forth in
section 112(d) of the CAA must reflect the maximum degree of reduction
in emissions of HAP that is determined to be achievable by the industry
source category. For existing sources, MACT cannot be less stringent
than the average emission limitation achieved by the best-performing 12
percent of existing sources for categories and subcategories with 30 or
more sources (excluding certain sources as specified by the CAA). This
level of control is known as the MACT floor. Because the MACT floor
represents the level of reduction in HAP emissions that is actually
achieved by the best-performing sources in the source category, EPA may
not consider cost and other impacts in determining the MACT floor.
This section describes the process used by EPA to determine the
MACT floors for each of the subcategories included in the coal- and
oil-fired electric utility source category. The MACT floor
determination process for this source category was complicated by the
many ranks/grades of fossil fuels used in the industry and the
capability of the air pollution control technologies currently used in
the industry to reduce Hg and Ni emissions.
The initial step in developing a MACT floor or floors for a source
category is determining whether subcategorization is appropriate. A
discussion of EPA's analysis and conclusions concerning
subcategorization of coal-fired units is set forth above.
One potential approach for establishing MACT floors for the
subcategories is to require all of the sources in a category to
implement precombustion pollution prevention measures. The
precombustion techniques include fuel substitution, process changes,
and work practices. As discussed in detail below, EPA has
[[Page 4669]]
determined that none of these approaches are viable for all of the
units in the coal- and oil-fired electric utility source category.
Did EPA consider the use of precombustion measures in establishing
the MACT floor? The EPA first considered the feasibility of fuel
substitution from several perspectives: (1) Switching to other fuels
used in the same subcategory (e.g., a ``lower'' Hg content bituminous
coal); (2) switching to fuels used in another subcategory (e.g., firing
bituminous coal instead of lignite coal); or (3) switching to natural
gas. The EPA considered several aspects of fuel switching in evaluating
these alternatives. These aspects included whether switching fuels
would achieve lower Hg and Ni emissions, whether fuel switching could
be technically achieved considering the existing design characteristics
of electric Utility Units, and the availability of various types of
fuel.
For coal-fired units, the first aspect considered was fuel
switching either to a better (or lower Hg-containing) seam of coal used
within a subcategory or used in another subcategory. The question of
whether switching between coals is a viable option arises from the
variation in Hg content and other key attributes in different seams of
coal. The data indicate that, although one seam may have less Hg than
another, it may be higher in other chemical constituents of concern.
The EPA has no data on which to determine the ``best'' seam, or rank,
of coal on which to base such a requirement. Further, even if a
``better/best'' seam could be identified, changing to a specific or
different seam of coal would essentially determine the area or even
mine from which the coal could be produced. The fuel substitution issue
then becomes dependent on the regional differences in coal
characteristics and the subsequent feasibility of placing a burden on
units that are located further from the better/best seams. The EPA
feels that the intent of the CAA is to develop standards that, to the
greatest extent reasonably possible, are consistent across the industry
and avoid actions that create regional disparities. The EPA further
feels that requiring all plants to combust coal from a specific seam is
not a viable long-term solution because the supply of coal from that
seam would be rapidly depleted. Finally, EPA has determined (as stated
earlier) that the existing Utility Units were designed based on the
availability of certain coal ranks and has found that, in some
instances, the units were actually co-located with a particular coal
source.
Another perceived use of alternate ranks or seams of coal is to use
clean coal. The term ``clean coal'' generally refers to a fuel that is
lower in sulfur and/or ash content. Data gathered by EPA indicate that
within specific coal ranks, the Hg content can vary significantly and
that lower sulfur content does not necessarily mean lower Hg content.
Certain physical characteristics of coal-fired units also limit the
effectiveness of prevention measures. A unit may require extensive
changes to the coal handling and feeding system (e.g., a stoker using
bituminous coal as fuel would need to be redesigned) in order to burn a
different rank of coal. Additionally, existing burners and combustion
chamber designs are generally not capable of handling different coal
ranks, and generally cannot accommodate increases or decreases in the
coal volume and shape. For example, burners are designed partially on
the hardness of the coal; changing coal ranks could result in a harder
coal and increased wear on the burners. The size of the burner and
combustion chamber are based, in part, on the heating value of the coal
rank; lower rank coals require larger systems for the same amount of
heat input. Design changes to allow different coal use may, in some
cases, reduce the capacity and efficiency of the unit. Reduced
efficiency results in a lack of effective energy usage and may result
in less complete combustion and, thus, an increase in emissions.
Another factor supporting EPA's conclusion that precombustion
measures are not a viable emissions reductions approach for all units
in the category is the lack of available alternative types of fuel for
a given unit. Natural gas pipelines are not available in all regions of
the U.S. Even where pipelines provide access to natural gas, supplies
of natural gas may not be available in adequate quantities for
utilities. For example, it is common practice in large metropolitan
areas during winter months (or periods of peak demand) to prioritize
natural gas usage for residential areas before industrial areas (i.e.,
natural gas curtailments). Requiring an EPA-regulated utility unit to
switch to natural gas would place an even greater strain on natural gas
resources, and, in some circumstances, the change would interfere with
a unit's ability to run at full capacity. For these reasons, EPA
decided that fuel switching is not an appropriate criterion for
identifying the MACT floor level of control for existing coal-fired
units.
With regard to process changes, EPA found that Hg and Ni emissions
of concern from coal- and oil-fired units are primarily dependent upon
the composition of the fuel and, to a lesser extent, the combustion
process. Consequently, process changes (i.e., changes to unit design/
operation) would be ineffective in reducing these fuel-related Hg and
Ni emissions. The EPA did not identify any process changes or work
practices that would be appropriate criteria for identifying the MACT
floor level of control for existing coal- or oil-fired units.
In general, electric Utility Units are designed for efficient
combustion. Facilities have an economic incentive to ensure that fuel
is not wasted and that the combustion device operates properly and is
appropriately maintained. In fact, historical data show that the
average heat rate (i.e., heat energy required to produce 1 kWh of
electricity) declined by 11-fold between 1899 and the mid-1960s, mainly
because of the desire to run efficient plants. The EPA was also unable
to identify any uniform requirements or set of work practices that
would meaningfully reflect the use of GCP or that could be meaningfully
implemented across any subcategory of units. Therefore, EPA has not
found combustion practice requirements useful in determining the MACT
floor for existing coal- or oil-fired units. However, EPA's inability
to establish a combustion practice requirement as part of the MACT
floor for existing units does not reduce the incentive for owners/
operators to operate their units at top efficiency.
The EPA requests comments and emissions information regarding
whether there are any uniform GCP for controlling Hg and Ni that would
be appropriate for minimizing Hg and Ni emissions from any subcategory
of electric Utility Units.
4. How Did EPA Derive the MACT Floor for Each Subcategory?
As noted above, the EPA has determined that coal rank and resulting
system design characteristics warrant subcategorization within coal-
fired units. Once EPA determined that precombustion techniques were not
helpful in determining the MACT floor for the entire source category,
the next step was to develop a MACT floor for each subcategory based on
the control technology used by the top-performing units (i.e.,
equipment based), and the level of emissions reductions (i.e., emission
limitation based) that the top units in each subcategory demonstrated.
[[Page 4670]]
The EPA had data from an evaluation of the Hg control performance
of various emission control technologies that are either currently in
use on coal-fired units (designed for pollutants other than Hg) or that
could be applied to such units for Hg control. According to the
available data, none of the existing control systems were specifically
designed to remove Hg; however, most of the controls removed Hg to some
degree. The most prevalent control technology used in the industry was
the ESP, which was designed to control PM. Fabric filters or the
combination of spray dryer adsorbers (SDA) and fabric filters were,
however, found to be the most effective control technology for Hg
removal generally.
Unfortunately, the best Hg control technology scenarios were not
consistent with regard to the extent to which they removed Hg. For
these reasons, EPA decided to address Hg under the proposed rule using
an emission limitation-based approach as opposed to a control
equipment-based approach.
As a result of the preceding evaluations, EPA concluded that the
most appropriate approach for determining MACT floors for existing
coal- and oil-fired units was to rank the emission test results from
units within each subcategory from lowest to highest and calculate a
MACT floor emission limitation by taking the numerical average of the
test results from the best-performing 12 percent (or equivalent) of
affected sources. The MACT floor database consisted of all pollutants
described in the 132 test reports, including multiple runs if they were
available. Units were ranked based on the subcategorization scheme
described elsewhere in this preamble, and then ranked from lowest to
highest by Hg emission rates within each subcategory. For oil-fired
units, the ranking process was based on the Ni emission rates.
5. How Did EPA Account for Variability?
In establishing the MACT floor(s) for existing sources in a
particular category or subcategory of sources, section 112(d)(3) of the
CAA calls for EPA to determine the average level of emission limitation
actually being achieved by the best-performing existing sources in that
category or subcategory. For combustion sources such as Utility Units,
variability in both the Hg or Ni content of the fuel combusted and the
performance of a particular control device have a significant impact on
the determination of the level of emission limitation actually being
achieved. As a result, it is essential that EPA be able to identify and
quantify the level of variability arising from these sources. This is
borne out by the test report data EPA obtained through the ICR. That
data, which EPA is confident are representative of the industry, shows
a significant degree of variability, even within a given subcategory.
The EPA, therefore, decided it was necessary to develop a methodology
to address the multiple sources of the observed variability in order to
assure that an emission limitation value could be derived that was
representative of what was actually being achieved by the best-
performing units under all conditions expected to be encountered by
those units. The origins of variability and approaches available for
addressing the variability found in the test data are described below.
Variability is inherent whenever measurements are made or whenever
mechanical processes operate. Variability in emission test data may
arise from one or more of the following areas: (1) The emission test
method(s); (2) the analytical method(s); (3) the design of the unit and
control device(s); (4) the operation of the unit and control device(s);
(5) the amount of the constituent being tested in the fuel; and, (6)
composition of the constituents in the fuel and/or stack gases.
Test and analytical method variability can be quantified by
statistical analysis of the results of a series of tests. The results
can be analyzed to establish confidence intervals within which the true
value of a test result is presumed to lie. Confidence intervals can be
estimated for multiple-run series of tests based on the differences
found from one test run to the next, with only the upper confidence
interval having meaning (signifying the chance of the standard being
exceeded).
When testing is done at more than one unit, similar confidence
intervals can be established to account for the variability from unit-
to-unit. One can combine the test-to-test and unit-to-unit variability
into a single factor that can be applied to reported test values to
give an upper limit for the likely true value. One can also estimate
the combined factor for any desired confidence level.
Another source of variability is the time interval during which the
test is being conducted. Testing for a short time may not reveal the
range of emissions that would be found over extended time periods.
Normal changes in operating conditions or in fuel characteristics may
affect emission levels over time. For example, an increase in the Hg or
Ni content of the fuel being fired in a unit may tend to increase the
Hg or Ni emission rate from the associated stack, even where the
control efficiency of the APCD remains constant. Mercury emission rates
may also change with unit loads due to changes in the gas flow rate
through APCD downstream from the unit which may affect APCD
effectiveness.
Variability in control efficiency or emission rates may be
addressed in a number of ways, depending on the circumstances existing
within the source category. For example, different test run results can
be analyzed statistically to arrive at an upper limit that represents
the highest likely value for each test planned for use in setting
emission limits. The poorest-performing (worst-case) unit in the top 12
percent of each subcategory can be reviewed to determine the causes of
poor performance. A factor, which when applied to each of the test
runs, can more accurately reflect performance over the full range of
operating conditions can then be developed. This results in emission
values that would not likely be exceeded over long time periods.
Another approach is to look only at the performance of control devices
used by sources in the top 12 percent and then use that information to
determine likely emissions reductions for different devices operating
on different units firing different fuels. The range in emissions
reductions derived in this manner could then be used to set upper
limits of expected control performance (i.e., to identify the best
performance that can be expected under the worst conditions); then,
these limits could be used, as above, to set emission limitations for
each subcategory. A third approach is to identify correlations between
constituents of concern and other, perhaps more easily measured,
constituents that can be used to develop algorithms that incorporate
variability.
In the context of developing a MACT standard, the issue of how to
appropriately address variability arises in deriving the MACT floor
level of control. In order to determine the average emission limitation
actually being achieved by the best-performing sources in a category or
subcategory, EPA must determine how those sources will perform over the
full range of operating conditions they can reasonably be anticipated
to encounter. Addressing variability in the MACT floor calculation
requires that all of the origins of variability be assessed and
quantified into factors that can be incorporated into the emission
limitation calculations for each subcategory's floor. In this way, the
actual performance of each of the floor units over the full range of
operating conditions can be derived. The result of
[[Page 4671]]
this approach is that the measured emission rate for each unit used for
floor calculations is increased to account for the variability found
from statistical analysis, worst-case analysis, or control device
performance analysis. The performance of each unit in the top 12
percent of its subcategory would be adjusted to reflect the uncertainty
associated with the various origins of variability, and the average
emission rate for these units would be used as the floor emission
limitation.
In trying to address the apparent sources of variability in the
emissions test data, EPA tried to obtain data that reflected as many
different plant configurations as would be found in the entire industry
profile and, through the ICR, required tests to be conducted at units
believed to be representative of the various plant configurations and
operating conditions found within the source category. The tests and
measurements, typically a three-run series of manual samples taken over
1 or 2 days of testing, are limited by the emission test method's
accuracy and precision, by the short duration of the test, and by
differences from one run to the next and one unit to the next.
Together, these factors bring into question the accuracy of the results
of the tests as a measure of a particular units performance over time.
The EPA has evaluated the total population of test results to determine
a valid test method variability factor for each type of control device
as well a worst-case fuel variability factor. The EPA determined that
it was necessary to evaluate the total population of test results to
ensure that the resulting variability factors were an accurate
predictor of the impacts of variability on the performance of the floor
facilities. The variability factors were then applied in MACT floor
emission limitation calculations, as appropriate. Applying these
variability factors to the identified performance of the floor
facilities, EPA has developed proposed emission limits for Hg for coal-
fired Utility Units and for Ni for oil-fired Utility Units. Information
contained in the docket provides a detailed description of the analysis
of the variability issues, including the methods available and used to
address the variability in test data used for the proposed rule.
How did EPA derive the proposed MACT floor emission limitations for
existing sources? In order to determine the MACT floor emission limits
for existing units, EPA examined the population database of existing
sources. Available emissions test data were divided according to the
subcategorization scheme described elsewhere in this preamble; first
coal- and oil-fired, then the five subcategories of coal-fired units.
The EPA examined the existing emission test data to determine the
individual numerical average of the test results from the best-
performing 12 percent (or equivalent) of each subcategory for Hg or Ni.
The EPA then applied the potential uncertainty and variability factors
to derive the MACT floor limits. All test data were provided to EPA in
an input-based format (lb/TBtu). Therefore, EPA conducted all MACT
floor calculations using the input-based format and then converted the
input-based format into an output-based format (lb/MWh) as a compliance
option, according to the approach described elsewhere in this preamble.
The discussion below describes the development of the emission
limitation for each subcategory in the electric utility source
category.
The EPA initiated the evaluation of the units within each
subcategory by ranking them from lowest to highest based on emission
rates representing the outlet Hg or Ni concentration of the stack
tests. This initial evaluation of the test report data indicated that
no specific control technology or combination of technologies could be
credited with the better performance; however, the evaluation indicated
that fabric filter technology did provide a degree of Hg removal and
that ESP units also provided a degree of removal, although to a less
consistent and lower degree than did fabric filter units. The EPA
further investigated the apparent inconsistency of Hg removal and found
that the level of removal of Hg was dependent on the speciated form of
Hg as presented to the control device. This phenomenon was further
evaluated using the entire database of coal-fired units to determine if
the variations in the control device performances could be correlated
to the speciated form of the Hg presented to the APCD. This evaluation
encompassed an evaluation of existing coal-fired units from the ICR
data that provided Hg speciation data, Hg-in-coal data, and pre- and
post-last-control unit emissions test data. The data indicated that
where Hg was presented to the control device in particulate-bound form,
both fabric filter and ESP devices provided a degree of control, with
fabric filters generally performing better than ESP units. Where Hg was
presented to the control device in an elemental form, the performance
of the various control devices was highly variable. Part of the
variation is believed to be attributable to the form of Hg in the flue
gas, such as chlorine compounds. However, part of the variation is not
understood at this time, thus the data are inconclusive. Testing has
shown that the proportion and type of speciated Hg presented to an APCD
is not consistent; however, as stated above, the data do indicate that
PM controls are reasonably effective where particulate-bound Hg is
present. This variation of the proportions of speciated Hg within the
flue gas between units provided further explanation for the observed
removal characteristics for different units using the same control
technology. Further evaluation of Hg speciation indicated that
different coal ranks tend to speciate to a predominantly similar
proportion of speciated forms of Hg, thus further supporting the
rationale for the subcategorization of coal-fired units based on coal
rank.
The EPA found, for the reasons indicated above, that although
variable, fabric filter and ESP control technologies were reasonable
and viable technologies on which to base the MACT floor level of
control. The EPA then evaluated performance of the various fabric
filter- and ESP-equipped units to determine what criteria would most
effectively reflect the performance. The EPA considered using the
percent efficiency of the control device, the percent reduction, and
outlet concentration as viable criteria to demonstrate performance of
the technology. However, the evaluation of these performance criteria
proved problematic. The ICR Hg data were based on stack test data for
the last control device at each utility unit tested. The emissions were
measured in milligrams of Hg per volume of test solution used in the
Ontario-Hydro method. Using the duct or stack flue-gas flow volume and
the heat input to the unit being tested, the measured quantity of Hg
was converted and reported in units of lb/TBtu. In reviewing the data,
EPA found that the inlet measurement showed deficiencies due to the
flow rate and short duct runs available for testing before the control
device, and that these values were suspect as being reliable
representations of actual inlet concentrations. The EPA, therefore,
determined that evaluation of control device efficiency values based on
unreliable inlet concentration data would not be justified. The EPA
determined, however, that the outlet concentration data were reliable
based on the method used and the fact that only one measurement was
needed for the determination of the value. Another option was then to
determine Hg reduction efficiency across the system.
[[Page 4672]]
This option would also address EPA's desire to promote, and give credit
for, coal preparation practices that remove Hg before firing (i.e.,
coal washing or beneficiation). However, this option requires tracking
the Hg concentrations in coal from receipt to stack, and not just
before and after the control device(s) and could be difficult to
implement. The EPA believes that an emission rate format would allow
for the use of precombustion Hg removal processes. As a result, EPA
believes that the most credible data element available that quantified
performance would be the emission rates as provided in the stack test
reports.
The emission limitation for Hg emissions from existing coal-fired
units was determined by analyzing the available Hg emissions data in
each subcategory. The data were obtained from the ICR noted earlier and
included data for Hg emissions, and Hg-in-coal and Cl-in-coal data for
1999. The MACT floor calculations were based on the average performance
of the top 12 percent of units in the individual subcategories of
bituminous coal, subbituminous coal, lignite coal, coal refuse, and
IGCC (coal gas).
The variability of Hg emissions from coal-fired units is
significantly influenced by the variability over time in the
composition of the coal burned as fuel (i.e., differences in Hg
content, Cl content, and heat content of coal). The differing physical
and chemical properties of Hg-containing compounds in the flue gas
result in significant differences in the feasibility and effectiveness
of controls for removing the compounds from flue gas. The effectiveness
of control devices at removing Hg depends to a large extent on the
species of Hg in the flue gas. As a general matter, all of the control
devices currently installed on Utility Units are most effective at
removing Hg in the oxidized form (e.g., Hg\++\). Thus, which Hg species
are present in the flue gas impacts the amount of Hg that will be
captured by control devices and how much Hg will be released in stack
emissions. Importantly, studies have shown that the Cl content of the
coal has a significant impact on which Hg compounds are contained in
the flue gas. Generally, the higher the Cl content relative to the Hg
content, the greater the percentage of oxidized Hg (ionic or Hg\++\)
contained in the flue gas. When combined with other relevant data, such
as coal Hg content, the Cl content of coal can thus be used to predict
a particular control device's ability to effectively reduce Hg
emissions.
The data results from a multi-variable study EPA performed on the
ICR data demonstrate the significance of coal Cl content to Hg
emissions controllability. The higher the Cl:Hg ratio, the more likely
the formation of mercuric chloride (Hg\++\) that is more readily
captured by existing control devices. This Cl:Hg ratio is independent
of the coal rank as an indicator of Hg controllability.
In summary, the coal Cl content is one of the primary determinants
of which Hg-containing compounds will be present, and in what amounts,
in the flue gas of an individual utility unit. The differing physical
and chemical properties of Hg-containing compounds in the flue gas
result in significant differences in the feasibility and effectiveness
of controls for removing the compounds from flue gas.
The EPA determined that the stack tests in the ICR database alone
are insufficient to estimate the effect of fuel variability over time
on the emissions of the best-performing facilities. The ICR database
contains extensive data on variation in coal composition recorded over
the course of a year. Therefore, to link fuel composition data to Hg
emissions data, EPA developed a methodology using correlation equations
to represent the relationship between the fraction of Hg removed and Cl
concentration for each of the control configurations used by the best-
performing units. The correlation equations provide a mechanism for
predicting the performance of each of the control devices installed on
floor units when the unit is combusting any of the coals received by
that unit during 1999. The steps used to develop these correlation
equations are set forth below.
The units in each of the five subcategories were sorted in
ascending order of stack-tested Hg emission factor, measured in units
of lb/TBtu (as adjusted by a method that normalizes Hg emissions to
coal heat content (F-factor Adjustment)). Accordingly, the top
performing units of each subcategory were selected for further
analysis.
The control configuration of each of the best-performing units
(i.e., the floor units) was identified. The Hg removal fraction and
test coal Cl concentrations were obtained from the ICR database for
each of the units in the database that have one of the identified
control configurations. It was necessary to look at all units employing
the identified control configurations to ensure that the statistical
r\2\ values of the subsequently derived correlation equations were
sufficiently high to conclude that the correlation equations could
accurately predict the Hg removal efficiency of a particular control
device in operation on one of the floor units.\6\ Finally, a
correlation equation was derived for each identified control
configuration by fitting a mathematical expression to the Hg removal
fractions and corresponding Cl concentrations obtained from the ICR
stack test database. The correlation equations thus derived can be
applied to any control device for which the Hg control efficiency, when
the unit being controlled is burning a coal with an identified Cl:Hg
ratio, is known to predict the control efficiency of that device when a
coal with a different Cl:Hg ratio is burned.
---------------------------------------------------------------------------
\6\ The r\2\ measures the strength of the relationship between
any two variables in the sense that it provides the proportionate
reduction in the sum of squares of vertical deviations obtained
using a least squares approach. The largest value r\2\ can attain is
1, which occurs when the residual sum of squares is equal to zero
(i.e., all the data points lie on the curve), while the smallest
value that r\2\ may take is 0, which means there is no improvement
in predictive power using the independent variable. In our example,
the two variables of concern in effecting Hg reductions are the Hg
and Cl content of coal. Thus, the closer r\2\ comes to 1, the
stronger the relationship between these two variables, and
reductions in Hg emissions, for any given coal sample; and, on the
other hand, the closer r\2\ comes to 0, the more likely there is
little or no relationship between the two variables, and reductions
in Hg emissions, for a given coal sample.
---------------------------------------------------------------------------
In selecting the format of the correlation equation, care was taken
that the mathematical expression accurately reflected the physical and
chemical process by which Cl contributes to the controllability of
stack Hg emissions. The correlation equation is based on the assumption
that the rate of conversion of Hg to mercuric chloride (an oxidized
form) is proportional to the Cl concentration in the coal, irrespective
of coal rank. With this expression, the maximum removal fraction is
limited to 1, because the exponent term is always nonnegative,
regardless of the Cl concentration. This corresponds to the real-world
limitation that no more than 100 percent of the Hg in flue gas can be
removed (i.e., there cannot be negative Hg emissions). As the coal Cl
concentration drops to zero, the Hg removal fraction does not approach
zero because some Hg removal is achieved even without reaction with Cl.
The purpose of deriving a correlation equation for each control
configuration used by the top performing units was to provide a
numerical means of predicting the fraction of Hg removed for the best-
performing sources over the entire range of fuel variability
experienced by each of those sources over the course of a year.
Correlation equations were derived for each control configuration, but
were only used to predict Hg removal if they
[[Page 4673]]
were found to have acceptable explanatory power.
To determine whether the explanatory power of each correlation
equation warranted its use on a larger range of ICR coal composition
data, each correlation equation was validated against the ICR stack
test data. For each of the Cl concentrations in the ICR stack test
database for 1999, the Hg removal fraction was calculated by using the
correlation equation with parameters selected to give the best fit to
the data. A correlation coefficient was then calculated to evaluate the
accuracy of the fit.
For each of the best-performing units, unit-specific coal
composition data for a one-year period were extracted from the ICR
database to find the coal heat content, Hg content and Cl content. For
each set of coal composition data from the ICR database, the controlled
Hg emissions were calculated by multiplying uncontrolled Hg emissions
by (1-Hg removal fraction). For each of the best-performing sources,
this process was repeated for each set of measured coal composition
values, yielding a range of controlled Hg emission levels for that unit
over time.
The test coal composition data from the ICR database (heat and Hg
content) was used to calculate the uncontrolled Hg emission level. The
Hg removal fraction was calculated in one of the following two ways:
(1) Where the correlation equation was found to have sufficient
explanatory power, it was used to estimate the Hg removal fraction
based on coal Cl composition data from the ICR data base. This approach
accounted for variations in the Hg, Cl, and heat content of fuel.
(2) Where the correlation equation was a poor fit, the Hg removal
fraction was based on the average Hg removal fraction observed in the
ICR stack tests of that unit. This latter approach yielded a constant
removal fraction based upon the source test, and had the effect of
reducing the variability of predicted Hg emissions. Under this
approach, the measured impact of fuel variability was limited to the
effect of variations in Hg and heat content, while variations in Cl
concentration were not explicitly considered.
For each of the best-performing units, the calculated controlled Hg
emissions, calculated in accordance with the procedures outlined above,
were then sorted from smallest to largest to obtain a cumulative
frequency distribution (CFD). The 97.5th percentile value of this
distribution (i.e., an emission rate that is expected to be exceeded
only 2.5 percent of the time) was determined to represent the operation
of the unit under conditions reasonably expected to occur at the unit.
It is necessary also to account for inter-unit variability among
the top performers. The analysis of within-unit variability considered
only the top units in each subcategory. A focus on within-unit
variability alone is not expected to capture the full range of
emissions variability among the best-performing sources. The EPA
accounted for this variability by calculating a 97.5 percent upper
confidence level for the mean by use of the student t-statistic.
The EPA calculated the emission limitation for Hg for the
subcategories of bituminous-fired, subbituminous-fired, lignite-fired,
IGCC, and coal refuse-fired units as follows.
For bituminous-fired units, EPA had data from 32 units. Because
this subcategory (i.e., nationwide population) included more than 30
units, EPA determined that the top 12 percent of the units in the
subcategory would be composed of 12 percent of the number of units for
which EPA had data (i.e, 4 units). The EPA determined the top four
units from a ranking of units based on their emission rates from the
stack test reports. The emission rates from these units ranged from
0.1062 lb/TBtu to 0.1316 lb/TBtu, with an average of 0.118 lb/TBtu.
After applying variability as described above and rounding to 2
significant figures, EPA determined the inlet-based emission limitation
to be 2.0 lb/TBtu. Using the conversion described elsewhere in this
preamble (and based on 32 percent net efficiency), the inlet-based
emission limitation of 2.0 lb/TBtu was converted to 21 x
10-6 lb/MWh as the outlet-based emission limitation.
For subbituminous-fired units, EPA had data from 32 units. Because
this subcategory (i.e., nationwide population) included more than 30
units, EPA determined that the top 12 percent of the units in the
subcategory would be composed of 12 percent of the units for which EPA
had test data (i.e., 4 units). The EPA determined the top units from
the ranking of the units based on their emission rates from the stack
test reports. The emission rates from these units ranged from 0.4606
lb/TBtu to 1.207 lb/TBtu, with an average of 0.738 lb/TBtu. After
applying variability as described above and rounding to 2 significant
figures, EPA determined the inlet-based emission limitation to be 5.8
lb/TBtu. Using the conversion described elsewhere in this preamble (and
based on 32 percent net efficiency), the inlet-based emission
limitation of 5.8 lb/TBtu was converted to 61 x 10-6 lb/MWh
as the outlet-based emission limitation.
For lignite-fired units, EPA had data from 12 units. Because this
subcategory (i.e., nationwide population) consisted of fewer than 30
units, EPA determined that the top performers must include the top 5
units. The emission rates from these units ranged from 3.977 lb/TBtu to
6.902 lb/TBtu, with an average of 5.032 lb/TBtu. After applying
variability as described above and rounding to 2 significant figures,
EPA determined the inlet-based emission limitation to be 9.2 lb/TBtu.
Using the conversion described elsewhere in this preamble (and based on
32 percent net efficiency), the inlet-based emission limitation of 9.2
lb/TBtu was converted to 98 x 10-6 lb/MWh as the outlet-
based emission limitation.
For IGCC units, EPA had data on two units. Because this subcategory
(i.e., nationwide population) included less than 30 units, EPA
determined that all available units would be included and were ranked
based on their emission rates from the stack test reports. The emission
rates from these units ranged from 5.334 lb/TBtu to 5.471 lb/TBtu, with
an average of 5.403 lb/TBtu. The EPA applied the variability factors
and, with rounding to two significant figures, determined the IGCC
input-based emission limitation to be 19 lb/TBtu. Using the conversion
described elsewhere in this preamble (and based on 32 percent net
efficiency), the inlet-based emission limitation of 19 lb/TBtu was
converted to 200 x 10-6 lb/MWh as the outlet-based emission
limitation.
For coal refuse-fired units, EPA had data from two units. Because
this subcategory (i.e., nationwide population) included fewer than 30
units, EPA used all units for the calculation based on their emission
rates from the stack test reports. The emission rates from these units
ranged from 0.0816 lb/TBtu to 0.0936 lb/TBtu, with an average of 0.0876
lb/TBtu. The EPA applied the variability factors as described above and
with rounding to two significant digits, determined the input-based
emission limitation to be 0.38 lb/TBtu. Using the conversion described
elsewhere in this preamble (and based on 32 percent net efficiency),
the inlet-based emission limitation of 0.38 lb/TBtu was converted to
4.1 x 10-6 lb/MWh as the outlet-based emission limitation.
The EPA believes that the Hg emission limitations derived above,
using the test data adjusted for appropriate variability, provide a
reasonable estimate of the actual performance of the MACT floor units
under all conditions expected to be encountered over time.
Some have argued that the experience gained from regulation of
Municipal
[[Page 4674]]
Waste Combustors and Health, Medical and Infectious Waste Incinerators
in the early 1990s indicates that coal-fired power plants should be
able to achieve 90 percent Hg emission reductions (see ``Out of Control
and Close to Home: Mercury Pollution from Power Plants.'' Environmental
Defense. 2003). The EPA expects that some Utility Units can achieve
such high reduction rates, depending on factors such as the Hg and Cl
content of different coals, as outlined above. However, there are
important technical differences between Utility Units and municipal
waste combustors and health, medical and infectious waste incinerators.
Consequently, EPA believes 90 percent emission reductions cannot be
achieved across all Utility Units in the proposed section 112 time
frame. First, the percentage of emissions that is elemental Hg is much
larger in coal-fired boilers than in the waste combustors and
incinerators (e.g., 50 percent versus 2-20 percent, as stated in EPA's
Mercury Study Report to Congress). Second, Hg emissions from the waste
combustors and incinerators can be reduced effectively through waste
separation techniques, which remove Hg-containing items from the
incoming waste stream (e.g., batteries). Application of similar
measures at coal-fired Utility Units, such as effective pre-combustion
Hg removal, is not widely feasible at this time, though some innovative
techniques are under development. Third, the Hg emissions at the waste
combustors and incinerators often occur as infrequent, high-
concentration ``spikes,'' which are more easily controlled than highly
diluted Hg in the flue gas found at coal-fired Utility Units. The
technical differences between Utility Units and municipal waste
combustors and health, medical and infectious waste incinerators need
to be recognized (see ``Mercury Emissions from Coal-Fired Power Plants:
The Case for Regulatory Action,'' NESCAUM, 2003).
Are there other approaches to addressing variability? The approach
selected by EPA for addressing variability is not the only approach
that could be appropriate for evaluating emissions from the best-
performing units. The Department of Energy (DOE) has conducted a
similar analysis to that described above, but with one significant
difference. (DOE, 2003.) In calculating a MACT ``floor'' rate, DOE
considered that variability at a best-performing unit could be based on
assuming that the unit could switch to a coal not previously burned at
the unit during the one-year period covered by the ICR, but having the
same rank as the coal used at the best-performing unit. Because the
alternative coals were of the same rank and not precluded from use by
regulation or permit, DOE concluded that the combination of emission
algorithms, unit-specific stack tests, and ICR coal data from other
units constituted relevant emission estimates under worst conditions at
the best-performing units.
The essence of the DOE analysis was to average at a plant level the
Hg and Cl contents of all coals, by rank, in the ICR data base. Then,
DOE adjusted the performance test results at the lowest emitting units
in the ICR data base by assuming that they burn a coal similar to the
97.5th percent worst plant annual average coal. For bituminous coal
units, the coal Cl resulted in the greatest variability in emissions.
For subbituminous coals, the coal Hg content was more critical than Cl
content. The DOE found that most lignite-fired power plants were
directly associated with a single mine, and decided that assuming a
switch to coals from other mines was not reasonably justified.
Therefore, for lignite units, DOE would recommend using the approach
presented earlier by EPA. In addition, for bituminous coals, DOE found
that many of the lowest Cl bituminous coals are produced in the western
U.S. and are unlikely to be used in eastern power plants, where the
bulk of bituminous coal is burned. Those western coals were excluded
from the variability analysis.
Using this approach, DOE found that an appropriate MACT floor rate
for bituminous coal was 2.6 lb/TBtu heat input. The rate for
subbituminous coals was 5.4 lb/TBtu heat input. The EPA seeks comment
on alternative approaches to addressing source emission variability,
such as DOE's. In particular, we ask for comment on the relevance of
Cement Kiln Recycling Coalition to the DOE approach.
How did EPA address blended coals? The EPA recognizes that many
Utility Units burn more than one rank of coal, either at the same time
(i.e., blending) or at separate times during a year (i.e., seasonally).
Further, EPA is aware that several units burn a supplementary fuel
(e.g., petroleum coke, tire-derived fuel (TDF), etc.) in addition to a
primary coal fuel. The EPA recognizes this practice and acknowledges
the effect that coal blending (or use of supplementary fuels) will have
on Hg emissions. Because this rule does not apply to the non-regulated
supplementary fuels, the rule does not provide an emission limitation
for those fuels. The EPA believes that the most appropriate means to
address the blending scenarios is through the compliance demonstration.
The EPA has identified several blending scenarios that might occur
in the industry; blending two or more ranks of coal, blending one rank
of coal with a supplementary (non-regulated fuel), or blending multiple
ranks of coal with a supplementary (non-regulated) fuel.
There are two potential methods for addressing the blending
scenarios where two or more ranks of coal are fired. One approach to
address blended coal would be to classify a unit based on the
predominate coal it burns. For example, if 90 percent of the coal
burned for the compliance period were bituminous, the unit would be
classified as bituminous and would have to meet the Hg emission
limitation for bituminous coal. Although this approach is desirable
from a simplicity standpoint, EPA believes that this approach is not
equitable nor reflective of actual practice in the industry. Therefore,
EPA is proposing a second, potentially more equitable, approach
involving development of a weighted Hg emission limit based on the
proportion of energy output (in Btu) contributed by each coal rank
burned during the compliance period and the coal's subcategory Hg
emission limitation. The weighted emission limit would, in effect, be a
blended emission limitation based on the Hg emission limitations of the
subcategories of the coals burned.
The other scenarios discussed above involve blending a regulated
fuel (e.g., coal or coal refuse) with a supplementary, non-regulated
fuel (e.g., petroleum coke, TDF, etc.). The application of the same
methods would be appropriate for units that burn a regulated fuel with
supplementary, non-regulated fuels; however, there would be no
adjustment to the Hg emission limitation with regard to the
supplementary, non-regulated fuel.
The weighted Hg emission limitation would be developed based on the
proportions of energy output (Btu) contributed by only the regulated
fuels. For example, if the unit burned bituminous, subbituminous, and
petroleum coke during the compliance period, and where 40 percent of
the Btu output was attributable to the bituminous, 40 percent to the
subbituminous, and 20 percent to the petroleum coke, the blended Hg
emission limitation would be based on the bituminous and subbituminous
emission limitations in a 50/50 ratio. The compliance calculation would
include the energy output (Btu) of all fuels burned (including the
supplementary fuel), the emissions
[[Page 4675]]
considered would include all Hg emission measured by the CEMS, and the
unit would comply with the blended Hg emission limitation. The
compliance demonstration outlined in Sec. 63.9990(a)(6) of the proposed
rule provides the calculation of the blended Hg emission limitation
applicable under this approach.
How did EPA address Ni from oil-fired units? The proposed emission
limit for Ni from existing oil-fired units was determined by analyzing
the emissions data available. The data were obtained from the Utility
RTC which provided information indicating that Ni was the pollutant of
concern due to its high level of emissions from oil-fired units and the
potential health effects arising from exposure to it. The EPA examined
available test data and found that units equipped with ESP units (for
PM control) can effectively reduce Ni. The controls currently in use on
electric utility oil-fired units to address PM were installed as a
result of requirements to address criteria pollutants under other
regulations. The data available to EPA indicate that the Ni is present
in flue gas streams in varying concentrations, yet mostly in
particulate form. The Utility RTC emissions test data support the
conclusion that the same control techniques used to control the fly-ash
PM will also indiscriminately control Ni and that the effective removal
of PM indicates removal of Ni, for a given control device. Therefore,
EPA believes that ESP technology represents the MACT floor for Ni for
the proposed rule. The EPA has determined that the proposed emission
limitation for the oil-fired units should reflect the performance that
would be expected over time for a well designed and operated ESP.
The EPA determined the value of the Ni emission limitation by
ranking the stack test emission rates for Ni of the 17 units for which
EPA had data. The top 12 percent of the units, or 2 units, were
controlled by ESP and the range of emission rates was 29.97 to 357.16
with an average of 125.06 lb/TBtu. After applying variability as
described above and rounding to 2 significant figures, EPA determined
the inlet-based emission limitation to be 210 lb/TBtu. The output-based
Ni emission limitation was determined to be 0.002 lb/MWh after
conversion using 32 percent net efficiency. The EPA believes that these
emission limits are a reasonable estimate of the actual performance of
the MACT floor unit in reducing Ni on an ongoing basis.
The Agency is sensitive to the fact that some sources burn fuels
containing very little Ni and that compliance with the Ni emission
limitation could be burdensome in cases where the potential Ni
emissions would be very low. Therefore, EPA is considering an
alternative Ni-in-oil emission limit which would be equivalent to the
main standard. An existing source would be able to choose to comply
with the alternative Ni-in-oil emission limitation instead of the Ni
emission limitation (either input- or output-based) to meet the
proposed rule. The alternate Ni-in-oil emission limitation would be
based on a correlation between the Ni constituent concentration in the
oil burned and the expected Ni emissions in the flue gas. Data
available to EPA does not provide a consistent correlation methodology
for determination of an appropriate Ni constituent level in oil. The
EPA is soliciting comment on the usefulness of such an alternative Ni-
in-oil limit and the availability of any correlation methodology and
data for determining a Ni concentration level in oil that could be
shown to be equivalent to the proposed emission limitation.
The EPA solicits comments on these approaches and on others that
might present a better method for addressing variability in development
of the emission limitations.
How did EPA address dual-fired units? The EPA is aware that an oil-
fired unit may fire oil at certain times of the year and natural gas at
other times, as well as blends of residual oil and distillate oil. This
blending of fuels is conducted for many reasons, most of which are
economically driven with regard to the availability of fuels and the
price, and may be seasonal in nature. As stated elsewhere in this
preamble, EPA considers a unit to be an oil-fired unit if (1) it is
equipped to fire oil and/or natural gas, and (2) it fires oil in
amounts greater than or equal to 2 percent of its annual fuel
consumption. This 2 percent value is intended to represent that amount
of oil that a true natural gas-fired unit might use strictly for start-
up purposes on an annual basis.
As stated earlier for coal blending, EPA does not intend to address
the fuel blending scenarios with specific emission limitations, but
rather address the issue during the compliance demonstration.
In the proposed rule, units that burn distillate oil exclusively
would be exempt from the requirements of the rule and natural gas-fired
units would be excluded from the definition of an affected source.
Therefore, the requirements of the proposed rule would apply to units
that fire residual oil in any proportion with another oil, and to units
that fire residual oil at 98 percent or greater of its annual fuel
consumption, where the supplementary fuel is natural gas. The blending
scenarios that might occur for oil-fired units include the co-firing of
residual oil with distillate oil, and the firing of residual oil and
natural gas at different times. The EPA believes that a cutoff of 2
percent fuel oil-firing would separate those units that are
``fundamentally'' natural gas-fired but, for start-up or other
operational needs, periodically burn fuel oil.
Under the proposed rule, a unit that burns residual oil exclusively
would be required to meet the oil-fired Ni emission limitations. For
units that burn exclusively distillate oil, the unit would be exempted
from meeting the Ni emission limitation requirement. For units that
blend residual oil with distillate oil, the unit would be required to
meet the Ni emission limitations in the proposed rule, and would
include all Btus or MWh generated from the use of the distillate oil in
the compliance demonstration calculation. Likewise, a unit that burns
residual oil during certain periods and natural gas during certain
periods would include the natural gas-fired contributions (Btu or MWh)
in the compliance calculation.
Although EPA has not identified any other supplementary fuels
burned in the oil-fired industry, we are aware that such a scenario may
exist or might occur in the future. For the purposes of the proposed
rule, EPA intends that where any supplementary fuel is co-fired with
residual oil, the Btus or MWh contributed by the supplementary fuel be
accounted for in the compliance calculation, and that the unit would be
required to meet the Ni emission limitation for existing oil-fired
units.
The EPA solicits comment on whether the 2 percent breakpoint is a
reasonable basis for allowing those units that use oil only for startup
purposes to be exempted from regulation under the proposed rule.
6. How Did EPA Consider Beyond-the-Floor Options for Existing Units?
The EPA considered available regulatory options (i.e., technologies
or work practices) that were more stringent than the MACT floor level
of control for each of the different subcategories. Except for IGCC, we
have not identified technologies or work practices that provide a
viable basis for establishing standards beyond-the-floor. Described
below are the candidate technologies and work practices that we
considered in our analyses. We ask for comment on these technologies
and other control techniques that could provide
[[Page 4676]]
consistently lower levels of emissions of Hg and Ni than those
demonstrated by the MACT floor level of control. Additional information
on the beyond-the-floor analyses for existing units is available in the
document titled, ``Beyond the Floor Analysis for Existing and New Coal-
and Oil-Fired Electric Utility Steam Generating Units NESHAP'' which
can be found in the docket.
Coal-fired units. Conventional PM controls (ESP and fabric filters)
generally do not remove the vapor-phase Hg0 from coal-fired
unit emissions. This is because these controls do not capture gaseous
pollutants. Two technologies that possibly could be used to further
reduce the amount of vapor-phase Hg emitted from utilities are sorbent
injection and selective catalytic reduction (SCR).
Sorbent injection. Due to their multiple internal pores and high
specific surface area, sorbents have the potential to improve the
removal of Hg (mostly through the enhanced capture of elemental Hg;
sorbents will also remove Hg++) as well as other gaseous
pollutants that are carried with combustion fine particulates in all
coal-fired subcategories (except IGCC). The extent of the potential Hg
removal is dependent on: (1) Efficient distribution of the sorbent
(e.g., activated carbon) in the flue gas; (2) the amount of sorbent
needed to achieve a specific level of Hg removal which will vary
depending on the fuel being burned; (3) the amount of Cl present in the
fuel; and (4) the type of PM control device (e.g., at a given sorbent
feed rate, a fabric filter provides more Hg control than an ESP because
of the additional adsorption that occurs on the bags of the fabric
filter because of the increased gas contact time).
Sorbents can be introduced by two basic methods: by channeling flue
gas through a bed of sorbent or by direct sorbent injection. Sorbent
bed designs consist of fixed-sorbent filter beds, moving beds, or
fluidized sorbent filter beds. With direct sorbent injection, after
sorbent is introduced into the flue gas, it adsorbs Hg and other
contaminants and is captured downstream in an existing or sorbent-
specific PM control device. At this time, the types of sorbent that may
be viable for use in sorbent injection include two basic types of
activated carbon (AC; regular and impregnated), as well as other carbon
(mixed with other sorbents) and non-carbon sorbents.
Activated carbon is a specialized form of carbon produced by
pyrolyzing coal or various hard, vegetative materials (e.g., wood) to
remove volatile material. The resulting char then undergoes a steam or
chemical activation process to produce an AC that contains multiple
internal pores and has a very high specific surface area. With this
internal pore structure, the AC can adsorb a broad range of
contaminants. Some studies have shown good to excellent Hg removal with
the injection of AC (particularly on bituminous-fired units); however,
other studies have not shown good Hg removal (particularly on
subbituminous- and lignite-fired units). The Hg removal performance of
AC injection seems to be highly dependent on coal rank and composition
(i.e., Hg and Cl content of the coal) and specific utility plant
configuration (e.g., sequencing of APCD equipment). Further, little
long-term data is available.
Chemically-impregnated AC is AC that has been supplemented with
chemicals to improve its Hg removal. The Hg in the flue gas reacts with
the chemical that is bound to the AC, and the resulting compound is
removed by the PM control device. Typical impregnants for AC are Cl,
sulfur, and iodide. Chemically-impregnated AC have shown enhanced Hg
removal over regular AC. Chemically-impregnated AC require smaller
rates of carbon injection than does regular AC for equivalent Hg
removals. The required carbon-to-mercury mass ratio may be reduced by a
factor of from 3 to 10 with the chemically-impregnated AC. The cost per
mass unit of impregnated AC may, however, be significantly greater than
that of unmodified AC.
Other commercially available sorbent materials are
SorbalitTM (a mixture of lime with additives and 3 to 5
percent AC) and Darco FGD (an AC derived from lignite). Zeolites
comprise another category of sorbent. There are naturally occurring
mineral zeolites, in addition to commercially available synthetic
zeolites. Both types contain large surface areas and have a good
potential for Hg removal.
Although AC, chemically-impregnated AC, and other sorbents show
potential for improving Hg removal by conventional PM and
SO2 controls, this technology is not currently available on
a commercial basis and has not been installed, except on a
demonstration basis, on any electric utility unit in the U.S. to date.
Further, no long-term (e.g., longer than a few days) data are available
to indicate the performance of this technology on all representative
coal ranks or on a significant number of different power plant
configurations. Therefore, we do not believe these technologies provide
a viable basis for going beyond-the-floor.
Selective catalytic reduction. Although designed as a
NOX control technology, SCR has been shown in recent
emissions testing to have the ability to transform certain species of
Hg into other speciated forms that are easier for conventional PM and
SO2 controls to capture. The effect can be seen most
prominently when an SCR is installed between the PM control device and
a wet FGD control device on a unit that is already controlled by such
technologies. The Hg which would (in the absence of the SCR) tend to
remain as Hg0 is oxidized, and this highly soluble
Hg++ is then removed by the wet FGD. This Hg reduction
effect has been observed in limited stack testing on bituminous coal-
fired units. Results on subbituminous coal-fired units have not been
uniformly successful. To EPA's knowledge, no commercial-scale, lignite-
fired, SCR-equipped unit has been tested to date, though it is entirely
possible that greater Hg removal would result when applied to a
lignite-fired unit. Similarly, SCR has not been tested on all types of
coal sources.
The EPA requests comments on whether sorbent injection or SCR
should be considered as viable beyond-the-floor options for existing
coal-fired units. Our preliminary determination is that sorbent
injection has not been sufficiently demonstrated in practice nor have
long-term economic considerations been evaluated to allow sorbent
injection to be considered viable as a beyond-the-floor option. With
regard to the use of SCR, the EPA has inadequate information on which
to base a beyond-the-floor standard. The EPA is aware that research
continues on ways to improve Hg capture by PM controls and sorbent
injection and on the development of novel Hg capture techniques.
Therefore, EPA also requests comments on whether other control
techniques have been demonstrated to consistently achieve emission
levels lower than levels on similar sources achieving the proposed MACT
floor level of control. Comments should include information on
emissions, control efficiencies, reliability, current demonstrated
applications, and costs, including retrofit costs.
IGCC units. The EPA believes the best potential way of reducing Hg
emissions from existing IGCC units is to remove Hg from the syngas
before combustion. An existing industrial IGCC unit has demonstrated a
process, using sulfur-impregnated AC carbon beds, that has proven to
yield 90 to 95 percent Hg removal from the coal syngas. (Rutkowski,
2002) This technology could potentially be adapted to the
[[Page 4677]]
electric utility IGCC units. The EPA believes this to be a potentially
viable option for IGCC units.
We considered using sorbent bed technology as beyond-the-floor for
existing IGCC units but, because of concerns about the costs involved
and because existing IGCC units utilize older technology, have decided
not to pursue this option. The EPA is, however, proposing that the use
of a sorbent bed to remove Hg from coal gas be considered as the
beyond-the-floor option for new IGCC units. The EPA requests comments
on whether the use of this or other control techniques have been
demonstrated to consistently achieve emission levels that are lower
than levels from similar sources achieving the proposed existing MACT
floor level of control. Comments should include information on
emissions, control efficiencies, reliability, current demonstrated
applications, and costs, including retrofit costs.
Coal refuse-fired units. All of the 13 coal refuse-fired units
existing in 1999 use FBC; 10 of these 13 units inject limestone as a
sorbent for SO2 control, and 4 units are equipped with SCR
for NOX control. The only two coal refuse-fired units on
which performance tests were conducted in response to the ICR are the
MACT floor facilities for the coal refuse-fired subcategory.
The EPA knows of no technologies that could be used as beyond-the-
floor options for coal refuse units. However, the EPA requests comments
on whether existing coal refuse-fired units could use any control
techniques that have been demonstrated to consistently achieve emission
levels that are lower than levels for similar sources achieving the
proposed existing MACT floor level of control. Comments should include
information on emissions, control efficiencies, reliability, current
demonstrated applications, and costs, including retrofit costs.
Oil-fired units. The only emission control technology that EPA is
aware of to consider as a beyond-the-floor option for existing oil-
fired units is fabric filtration. Fabric filters have been shown in
pilot-scale testing to be more effective at reducing Ni emissions than
an ESP. However, the use of fabric filters on oil-fired units is also
known to be problematic due to the prevalence of the ``sticky'' PM
emitted from such units which sticks to the fabric and creates a fire
safety hazard. No existing oil-fired units are known to employ fabric
filters as their PM control. Because of this, EPA does not consider
fabric filters to be a viable beyond-the-floor option for oil-fired
units.
The EPA requests comments on whether fabric filters should be
considered as a beyond-the-floor option for existing oil-fired units.
The EPA also requests comments on whether other control techniques have
been demonstrated to consistently achieve Ni emission levels that are
lower than levels for similar sources achieving the proposed MACT floor
level of control. Comments should include information on emissions,
control efficiencies, reliability, current demonstrated applications,
and costs, including retrofit costs.
7. Should EPA Consider Different Subcategories for Coal- and Oil-Fired
Utility Units?
Although EPA has proposed subcategorizing coal-fired units into
five subcategories (bituminous coal, subbituminous coal, lignite coal,
coal refuse, and IGCC), another possible option is to subcategorize
coal-fired units into four subcategories (bituminous and subbituminous
coals, lignite coal, coal refuse, and IGCC). This second option is
claimed by some industry sources to allow greater fuel choice
flexibility. Approximately 23 percent of the coal-fired units in 1999
fired a blend of coal ranks or coals and other fuels. The majority of
blended coal-fired units in the U.S. combust a blended coal composed of
bituminous and subbituminous coal, either through direct blending or
through independently combusting each coal at some period during the
year. A standard that would subcategorize bituminous and subbituminous
together would allow easier emissions permitting and flexibility
because most units do not keep the ratio of the coals blended constant.
Although the above subcategorization scheme is not included in this
proposal, the EPA specifically requests comments on whether additional
or different subcategories should be considered. Comments should
include detailed information regarding why a new or different
subcategory is appropriate (based on the available data or adequate
data submitted with the comment), how EPA should define any additional/
different subcategories, how EPA should account for varied or changing
fuel mixtures, and how EPA should use the available data to determine
the MACT floor for any new or different categories.
8. How Did EPA Determine the Proposed MACT Floor for New Units?
For new sources, the CAA requires that the MACT floor be based on
the emission control achieved in practice by the best-controlled
similar source, as determined by EPA. The MACT standard is subsequently
based on any combination of measures or techniques that are ascertained
to have contributed to that level of control (e.g., pollution
prevention alternatives, capture and control technologies, operational
limitations, work practices) unless a more stringent level of control
is required based on the above-the-floor analysis. Because the MACT
floor represents the level of reduction in HAP emissions that is
actually demonstrated by the best-controlled similar source, EPA may
not consider cost and other impacts in determining the floor.
In order to develop a MACT floor for new coal- and oil-fired units,
EPA used the same data described above for existing sources. With
regard to Hg and Ni emissions from new units, EPA believes that the
character and levels of Hg and Ni emitted by new coal- and oil-fired
units will be similar to those emitted by existing coal- and oil-fired
units because the source of Hg and Ni is primarily related to the fuel.
The EPA has no data or information that indicate that this situation
will change in the future, particularly because EPA anticipates the use
of primarily the same fossil fuel sources for new units as are being
used for existing units.
The EPA is aware that the industry has some ability during the
designing of new units to choose coal or oil that would minimize
emissions of Hg and Ni and recognizes that the MACT standard for new
units should, to the extent possible, encourage the industry in that
direction. The type, grades, and ranks of coal and grades of oil
available for future use in new units will not likely change, and the
availability and economics of the fuel choice for these units will
likely still be a dominating factor in the design of new units. Future
technology may, however, allow for better efficiencies in the units
and, potentially, the use of a wider range of fossil fuels for a given
locale or region.
The EPA does believe that Hg from coal-fired units and Ni from oil-
fired units will remain a concern and that regulation of emissions of
Hg and Ni is warranted for new coal- and oil-fired units under the
proposed rule.
As was the case for existing units, in developing a MACT strategy
for new units, EPA considered several prevention measures as an
alternative to the application of Hg and Ni control technology. These
measures were the same precombustion techniques evaluated for existing
units, which included fuel substitution, process changes, and work
practices.
The EPA first considered the feasibility of fuel substitution from
[[Page 4678]]
several perspectives: (1) Switching to other fuels used in the same
subcategory (e.g., a ``lower'' Hg content bituminous coal); (2)
switching to fuels used in another subcategory (e.g., firing bituminous
coal instead of lignite coal); or (3) switching to natural gas. The EPA
considered several aspects of fuel switching in evaluating these
alternatives. The EPA recognizes that an owner/operator, in designing a
new unit, would be able to choose a perceived better coal rank (between
subcategories) or a perceived better coal seam within a rank (within
the subcategory) based on known issues of Hg and other pollutant
control and would be able design the new unit to that fuel's
characteristics. However, the economics of fuel availability would
still be a determining factor as to what fuel was chosen, particularly
with regard to new units co-located with existing units.
With regard to a possible EPA requirement for new sources to burn
natural gas, EPA believes that availability and economics again would
determine whether a source would chose to burn natural gas and that
such a requirement would be unduly restrictive given the owner/
operator's inability to control access to, or availability of, natural
gas. For these reasons, EPA decided that mandated fuel type is not an
appropriate criterion for identifying the MACT level of control for new
coal-fired units. In any event, we do not believe that we can or should
prescribe a given fuel type because of the implications on electricity
reliability, energy security, etc.
With regard to process design alternatives and GCP, EPA believes,
as discussed elsewhere in this preamble for existing sources, industry
has a strong economic incentive to pursue improvement in combustion and
plant efficiencies and that the trends in design and technology
development will continue in the direction of improvement in
efficiencies such that imposition of regulatory incentives based on the
existing knowledge base would be not only unnecessary but potentially
restrictive. In addition. we do not have the data necessary to
establish such a standard.
As with existing units, EPA therefore determined that precombustion
techniques were not viable for application in the MACT standard for new
coal- or oil-fired units.
Once EPA had determined that pollution prevention alternatives
would not be appropriate for the new coal- or oil-fired MACT
development, EPA then evaluated the control technology used by the top
performing unit (i.e., equipment based), and the level of emissions
reductions (i.e., emission limitation based) that the top unit in each
subcategory demonstrated.
The EPA used the same data available for existing units which
provided an evaluation of the Hg control performance of various
emission control technologies that are either currently in use on coal-
fired units (designed for pollutants other than Hg) or that could be
applied to such units for Hg control. The EPA decided to address Hg for
new units using an emission limitation-based approach.
As was discussed in MACT floor development for existing sources,
EPA is confident that the data available were obtained from units
representative of the industry; however, EPA did believe that some
adjustments to the data were justified in light of the variability in
test method and in Hg-in-fuel that was discussed previously with regard
to existing units. Although it was necessary to address the variability
issues, the use of one data set (i.e., the best unit vs. the top units)
negated the applicability of the unit-to-unit variability issue.
Otherwise, the variability issues were addressed in the same manner as
was discussed above for existing units.
The MACT floor for new units is based on the emission control
achieved in practice by the best-performing similar source. As noted
earlier, EPA believes it reasonable to subcategorize new sources in the
same manner as has been done for existing sources. In order to develop
an emission limitation for new coal- and oil-fired units, EPA ranked
the existing coal- and oil-fired units from lowest emitting to highest
within each subcategory based on Hg or Ni emission rates from the stack
test data. The EPA then took the numerical performance value from the
best-performing unit (or equivalent).
The EPA then applied the potential uncertainty and variability in
the emission test reports and worst-case Hg in fuel variability (if
applicable) to derive the Hg emission limitation values for new units.
Because test data were provided to EPA based on an input-based
format (lb/TBtu), EPA conducted the emission limitation calculations
using the input-based format and then converted the input-based format
into an output-based format (lb/MWh) according to the approach
described elsewhere in this preamble for the proposed rule. The
discussion below describes the development of the emission limitation
for each subcategory and each regulated pollutant for coal- and oil-
fired units.
Mercury from new coal-fired units. The emission limit for Hg
emissions from new coal-fired units was determined by analyzing the
available Hg emissions data in each subcategory. The data were obtained
from the ICR and included data for Hg emissions and Hg- and Cl-in-coal
data from all coal-fired units for 1999. The MACT emission limitation
calculation was based on the performance of the best similar source in
the individual subcategories of bituminous coal, subbituminous coal,
lignite coal, coal refuse, and IGCC (coal gas).
This performance value was adjusted for variability by using an
approach consisting of a combination of the statistical analysis of the
emissions test data and the application of a factor representing the
ratio of the Hg-in-coal during the stack testing to the highest Hg-in-
coal reported for the unit during 1999 (ICR test). The variability
approach used for adjusting the new unit's Hg emissions data was
modified to a simplified version of the existing unit's variability
factor that reflected the removal of the unit-to-unit variability
issue. The worst-case Hg-in-coal issue was addressed in the same manner
as the existing units, based on the Hg- and Cl-in-coal data for the
individual unit. The EPA chose the same confidence interval (97.5
percent) as was used for existing units, for the reasons discussed in
that section.
For bituminous-fired units, the best-controlled unit was controlled
with a fabric filter, and the Hg emission factor was 0.132 lb/TBtu.
This value was adjusted for variability as described above, converted
to the output-based format using the 35 percent efficiency factor, with
a resulting output-based Hg emission limitation for new bituminous-
fired units of 6.0 x 10-6 lb/MWh.
For subbituminous-fired units, the best-controlled unit was also
controlled with a fabric filter, and the Hg emission factor was 0.663
lb/TBtu. This value was adjusted for variability as described above,
converted to the output-based format using the 35 percent efficiency
factor, with a resulting output-based Hg emission limitation for new
subbituminous-fired units of 20 x 10-6 lb/MWh.
For lignite-fired units, the best controlled unit was controlled
with an ESP, and the Hg emission factor was 6.902 lb/TBtu. This value
was adjusted for variability as described above and converted to the
output-based format using the 35 percent efficiency factor, with a
resulting output-based Hg emission limitation for new lignite-fired
units of 62 x 10-6 lb/MWh.
[[Page 4679]]
For IGCC units, the best-controlled unit was uncontrolled, and the
Hg emission factor was 5.471 lb/TBtu. This value was adjusted for
variability as described above and converted to the output-based format
using the 35 percent efficiency factor, with a resulting output-based
Hg emission limitation for new IGCC units of 200 x 10-6 lb/
MWh. However, EPA believes that a 90 percent reduction in Hg emissions
is possible from new IGCC units based on the use of carbon bed
technology. Therefore, EPA is proposing an output-based Hg emission
limitation for new lignite-fired units of 20 x 10-6 lb/MWh
as a possible beyond-the-floor level of control for new IGCC units.
For coal refuse-fired units, the best-controlled unit was
controlled with a fabric filter, and the Hg emission factor was 0.094
lb/TBtu. This value was adjusted for variability as described above and
converted to the output-based format using the 35 percent efficiency
factor, with a resulting output-based Hg emission limitation for new
coal refuse-fired units of 1.1 x 10-6 lb/MWh.
The EPA believes that these Hg emission limitations, based on the
best-performing unit with associated variability applied, are a
reasonable estimate of the actual performance of the MACT floor unit on
an ongoing basis.
Blended coals. The EPA recognizes that new Utility Units may still
be designed to burn more than one rank of coal, either at the same time
(i.e., blending) or at separate times during a period of time (i.e.,
seasonally). The EPA finds no reason to address blended coals
differently for new units than has been proposed for existing units.
Therefore, the method of addressing blended coals with regard to the Hg
emission limit calculation will remain the same for new units as is
proposed for existing units. Further, EPA believes that consistency in
the compliance method would be appropriate, because many utility
owners/operators will at some point be addressing compliance for both
new and existing units at the same facility.
Nickel from new oil-fired units. The proposed emission limit for Ni
from existing oil-fired units was determined by analyzing the emissions
data available. The data were obtained from the Utility RTC which
provided information indicating that Ni was the pollutant of concern
due to its high level of emissions from oil-fired units and the
potential health effects resulting from exposure to it. The EPA
examined available test data and found that ESP-equipped units can
effectively reduce Ni. The Ni average concentration from the emission
data of the best-controlled oil-fired unit was used to determine the
emission limitation for new oil-fired units. The best oil-fired unit Ni
emission value from the stack test data was 0.0046 lb/TBtu. This
emission factor was then adjusted for uncertainty by applying
variability factors as described above for existing units, with a
resulting input-based Ni emission limit of 76 lb/TBtu. The EPA then
converted the input-based value using the 35 percent net efficiency
factor to derive the output-based value for the proposed rule. The
resulting proposed Ni emission limitation for new oil-fired units is
0.0007 lb/MWh. The EPA believes that this emission limitation is a
reasonable estimate of the actual performance of the MACT floor unit on
an ongoing basis.
The EPA is also considering development of an alternative Ni-in-oil
limit for new oil-fired units. The EPA solicits comment as to the
usefulness of such a limit and any available data or methodology to
determine a Ni constituent level in oil that would be equivalent to the
proposed Ni emission limitation.
Dual-fired units. The EPA is aware that new oil-fired units may be
designed and built to fire a combination of oil grades and/or natural
gas, as are existing units. The EPA believes that the reasons for
burning natural gas and/or any grade of oil will continue to be based
on economics or availability of fuel (i.e., seasonal considerations).
Therefore, EPA intends to address new oil-fired units that burn a
combination of oil grades and/or natural gas in the same manner as
existing units.
The method and rationale for determining the MACT floor for
existing and new units is presented in detail in the document titled
``MACT Floor Analysis for Coal- and Oil-Fired Electric Utility Steam
Generating Units NESHAP'' which can be found in the docket.
9. How Did EPA Consider Beyond-the-Floor for New Units?
Once the MACT floor determinations were done for new units in each
subcategory (by fuel type), EPA considered various regulatory options
more stringent than the MACT floor level of control (i.e., additional
technologies or work practices that could result in lower emissions)
for the different subcategories.
Due to the technical complexities of controlling metal HAP
emissions from the sources affected by this rule, however, EPA has not
been able to determine whether identified potential beyond-the-floor
options are available and demonstrated. Consequently, EPA is describing
the possible beyond-the-floor options of which the Agency is aware for
new units and requests comment on these technologies and other control
techniques that have been demonstrated to provide consistently lower
levels of emissions than those achieved by the proposed new unit MACT
floor level of control.
The following are possible beyond-the-floor control options for new
units that EPA is considering for the proposed rule.
Coal-fired units. As is explained for existing coal-fired units
elsewhere in this preamble, two technologies that possibly could be
used to further reduce the amount of vapor-phase Hg emitted from
utilities are sorbent injection and SCR. As explained elsewhere in this
preamble, however, sorbent injection is not currently available on a
commercial basis and has not been demonstrated on a utility unit
operating at full capacity over an extended period of time. As also
discussed previously, SCR has not shown the same change-in-speciation
effect on Hg emissions on all types of coal sources.
The EPA requests comments on whether sorbent injection or SCR
should be considered as a beyond-the-floor option for new coal-fired
units and whether these units could use any other control techniques
that have been demonstrated to consistently achieve emission levels
that are lower than those from similar sources achieving the proposed
MACT floor level of control. Comments should include information on
emissions, control efficiencies, reliability, current demonstrated
applications, and costs.
IGCC units. Because of their design, IGCC units have no external
APCD controls. Therefore, as is explained for existing IGCC units
elsewhere in this preamble, the best potential way of improving Hg
removal from IGCC units is to remove the Hg from the syngas before
combustion. Based on published information regarding the industrial
IGCC unit noted earlier, EPA believes that a 90 percent reduction in Hg
emissions is possible from new IGCC units based on the use of carbon
bed technology. Therefore, EPA is proposing this 90 percent Hg
reduction as a beyond-the-floor level for new IGCC units.
The EPA requests comment on whether such use of a sorbent bed to
remove Hg from coal syngas is an appropriate beyond-the-floor option.
Comments should include information on emissions, control efficiencies,
reliability, current demonstrated applications, and costs.
[[Page 4680]]
Coal refuse-fired units. Because existing units utilizing 100
percent coal refuse, all of which utilize FBC technology, have
demonstrated the best Hg control of any emission-tested electric
utility unit in the industry, EPA requests comments on whether there
are any additional control techniques that have been demonstrated and
can be applied to refuse coal-fired units to consistently achieve
emission levels that are lower than those of similar sources achieving
the proposed new MACT floor level of control. Comments should include
information on emissions, control efficiencies, reliability, current
demonstrated applications, and costs.
Oil-fired units. There has not been a new oil-fired unit
constructed in the U.S. since 1981. If a new oil-fired unit is
constructed, the only technology that might offer emissions control
better than the proposed new unit MACT limits is the use of fabric
filtration, which, as is discussed for existing sources elsewhere in
this preamble, EPA does not consider to be a viable control option for
oil-fired units.
The EPA requests comments on whether the use of fabric filters
should be considered as a beyond-the-floor option for new oil-fired
units and whether these or other control techniques could be used to
consistently achieve emission levels that are lower than those from
similar sources achieving the proposed new MACT floor level of control.
Comments should include information on emissions, emissions reductions,
reliability, current demonstrated applications, and costs.
Additional information on the beyond-the-floor analyses for new
units is available in the document titled, ``Beyond the Floor Analysis
for Existing and New Coal- and Oil-Fired Electric Utility Steam
Generating Units NESHAP'' which can be found in the docket.
10. How Did EPA Select the Proposed Testing and Monitoring
Requirements?
The CAA requires EPA to develop regulations that ensure initial and
continuous compliance. Testing and monitoring requirements allow EPA to
determine whether an affected source is operating in compliance with an
applicable emission limitation/standard. This section discusses how EPA
selected the proposed testing and monitoring requirements used to
determine compliance with the Hg emission limits for coal-fired units
and the Ni emission limits for oil-fired units that are specified in
the proposed rule.
Mercury testing and monitoring requirements. The proposed rule
would establish Hg emission limits for coal-fired units. The format
selected for these Hg emission limits is a 12-month rolling average Hg
emission level expressed in units of lb/TBtu or lb/MWh. Therefore,
appropriate testing or monitoring requirements for determining the
amount of Hg emitted from an affected unit throughout the compliance
averaging period must be included in the rule.
The most direct means of demonstrating compliance with an emission
limit is by the use of a CEMS that measures the pollutant of concern.
The EPA considers other testing or monitoring options when acceptable
CEMS are not available for the intended application or when the impacts
of including such CEMS requirements in the proposed rule are considered
by EPA to be unreasonable. In determining whether to require the use of
other testing or monitoring options in lieu of CEMS, it is often
necessary for EPA to balance more reasonable costs against the quality
or accuracy of the actual emissions data collected.
There are several approaches to Hg monitoring that EPA has
identified for possible use in this rule to determine compliance with
the proposed Hg emission limits. One option is to use a CEMS that
combines both automated sampling and analytical functions in a single
system to provide continuous, real-time Hg emission data. Mercury CEMS
are currently available from several manufacturers. These Hg CEMS are
similar to most other types of instruments used for continuous
monitoring of pollutants from combustion processes, in that the
combustion gas sample is first extracted from the stack and then
transferred to an analyzer for analysis. In general, the Hg CEMS now
available can be distinguished by the Hg measurement detection
principle used (e.g., atomic adsorption, atomic fluorescence, x-ray
fluorescence). Capital costs for a Hg CEMS are currently estimated to
range from approximately $95,000 to $135,000, depending on the
manufacturer and model selected. The annual costs to operate and
maintain a Hg CEMS are estimated to range from $45,000 to $65,000,
again depending on the manufacturer and model selected.
A second option is to use a long-term sampling method that collects
a cumulative Hg sample by continuously passing a low-flow sample stream
of the combustion process flue gas through a Hg trapping medium (e.g.,
an activated carbon tube). This sampling tube is then periodically
removed (e.g., after a day or up to 1 month) and replaced with a tube
filled with fresh trapping medium. The removed sampling tube is then
sent to a laboratory where the trapping medium is analyzed for its Hg
content. This method, like using a Hg CEMS, is capable of providing
data on the Hg emissions from a combustion process on a continuous
basis, but unlike a Hg CEMS, the data are not reported on a real-time
basis. Using the long-term sampling method, the Hg collected in the
sampling tube is integrated over a much longer sampling period (i.e., 1
to 7 days for the AC tube versus less than 15 minutes for the CEMS).
The capital cost for a gas metering system and Hg trapping medium is
estimated to be approximately $18,000. The annual costs for periodic
sampling tube replacement and for the laboratory Hg analysis range from
approximately $65,000 to $125,000 depending upon quality assurance and
quality control (QA/QC) requirements and frequency of sample tube
replacement.
Finally, a third monitoring option is to use one of the manual
stack test methods available for measuring Hg emissions from combustion
processes on an intermittent basis. The existing voluntary consensus
stack test method ASTM Method D6784-02 (commonly known as the Ontario-
Hydro method) is currently the method of choice for measuring Hg
species in the flue gas from Utility Units. Another method for
measuring total (i.e., not speciated) Hg is EPA Reference Method 29.
This method involves a technician extracting a representative flue gas
sample over a relatively short period of time (e.g., a few hours) using
a sampling train consisting of a nozzle and probe, a filter to collect
particulate matter, and a liquid solution and/or reagent to capture
gas-phase Hg. After sampling, the filter and sorption media are
prepared and analyzed for Hg in a laboratory. These test methods could
be applied to a Hg monitoring program at electric utility plants by
performing a manual stack test using ASTM Method D6784-02 or EPA
Reference Method 29 at some specified periodic interval throughout the
compliance averaging period (e.g., perform a stack test daily, weekly,
biweekly, monthly). The cost to conduct a single ASTM Method D6784-02
typically ranges from $15,000 to $17,000 depending on site conditions.
Annual costs will depend on the frequency with which the stack test is
required to be performed during the compliance averaging period. For
example, if the test is required once per week, the total annual cost
would be as much as $780,000 (52 tests in a 12-month period at $15,000
per test).
The EPA evaluated each of the above Hg monitoring options with
respect to
[[Page 4681]]
its suitability for the measurement of the Hg emission data needed for
determining compliance with the 12-month rolling average Hg emission
limit. The EPA rejected from further consideration the third option,
intermittent monitoring using manual stack test methods. Use of this
monitoring approach would place significantly higher labor requirements
and monitoring costs on facility owners/operators than the other two
options in order to perform an adequate number of source tests
throughout the compliance averaging period to demonstrate with
reasonable confidence that the applicable Hg emission limit value was
being achieved.
Both of the remaining two options would provide the necessary data
to calculate the total Hg emissions from an affected source for each
12-month compliance averaging period. While the CEMS would provide
these data on a real-time basis, EPA concluded that having real-time
data is not mandatory for determining compliance with an emission limit
based on a 12-month rolling average. Total Hg emissions from an
affected source by month are needed to compute the rolling 12-month
average Hg emission value. With regular scheduled replacement and
timely analysis of sampling tubes, total monthly Hg emissions can
readily be obtained using the long-term sampling method.
The EPA then compared the costs of applying the Hg CEMS and long-
term monitoring options to Utility Units. While the CEMS have
significantly higher capital costs, the automated analyses directly by
the instrument eliminates the need and cost for separate analyses of
the collected sampling tubes in a laboratory required by the long-term
sampling method. Overall, EPA determined that the total costs of using
either monitoring method to determine compliance would be similar for a
given site. Selection of which monitoring method should be used at the
site will depend on site-specific conditions and owner/operator
preferences. Because both monitoring methods will collect the Hg
emission data necessary to determine compliance with the proposed Hg
emission limit and the costs of either option are reasonable, EPA
decided to allow the owner/operator flexibility under the proposed rule
to choose to use either Hg CEMS or long-term sampling monitoring as
best suits their site conditions and preferences.
An owner/operator electing to use a CEMS to comply with the rule
would be allowed to use any CEMS that meets the requirements in
``Performance Specification 12A, Specifications and Test Procedures for
Total Vapor-phase Mercury Continuous Monitoring Systems in Stationary
Sources'' (PS-12A). This performance specification is proposed as part
of this rulemaking and we request comment on continuous monitoring of
Hg emissions according to the requirements in the proposed performance
specification.
Those owners/operators electing to use long-term Hg monitoring
would be required to follow the requirements in Method 324,
``Determination of Vapor Phase Flue Gas Mercury Emissions from
Stationary Sources Using Dry Sorbent Trap Sampling'' when it is
promulgated. Method 324 is proposed as part of this rulemaking to be
added to 40 CFR part 63, appendix A. We request comments on the
requirements in proposed Method 324 for Hg measurement using long-term
sampling. The owner/operator would use the procedures outlined in Sec.
63.10009 of the proposed rule to convert the concentration output from
a CEMS or Method 324 to an emission rate format in lb/TBtu or lb/MWh.
Continuous compliance requirements are required under every NESHAP
so that EPA can determine whether an affected source remains in
compliance with the applicable emission limitation/standard following
the initial compliance determination. In the case of the proposed
Utility NESHAP, the format for the Hg emission limit is a 12-month
rolling average limit. The same monitoring requirements used to
establish initial compliance of an affected electric utility unit with
the applicable Hg emission limit at the end of the first 12-month
period following the facility's compliance date serve to demonstrate
continuous compliance with the Hg emission limit with the computation
of each new 12-month rolling average value each month thereafter. Thus,
no additional continuous compliance Hg monitoring requirements beyond
those previously discussed are required for the proposed rule.
The EPA is concerned about monitoring costs for Utility Units with
low Hg emissions rates, and does not desire to adopt a monitoring
scheme where the costs are disproportionate to the costs of compliance
with the MACT emissions limitations. For these units (e.g., those
emitting under 25 pounds per year) the EPA may consider reduced
monitoring frequencies and lower cost monitoring requirements, since
the need for accuracy is reduced for such units. For example, the EPA
is concerned about the merits of requiring an expenditure of $100,000
per year to monitor releases when the costs of substantive compliance
is far less. The Agency requests comments and related data upon which
to establish an alternate reporting scheme.
Nickel testing and monitoring requirements. The proposed rule would
establish Ni emission limits for oil-fired units. The EPA selected a
different format for the Ni emission limits than is proposed for the Hg
emission limits. The Ni emission limits are maximum allowable emission
limits not to be exceeded, expressed in lb/TBtu or lb/MWh.
The EPA selected the proposed testing requirements to determine
compliance with the Ni emission limits under the NESHAP to be
consistent with existing procedures used for the electric utility
industry. Method 29 in appendix A to 40 CFR part 60 is an EPA reference
test method that has been developed and validated for the measurement
of Ni emissions from stationary sources. For sampling and analysis of
the gas stream, the following EPA reference methods would be used with
Method 29: Method 1 to select the sampling port location and the number
of traverse points; Method 2 to measure the volumetric flow rate;
Method 3 for gas analysis; and Method 4 to determine stack gas
moisture. Method 19 specifies the procedure for collecting the
necessary fuel data to be used with the Method 29 Ni measurements from
the source test to compute the Ni emission rate expressed in units of
lb/TBtu.
As an alternative under the proposed rule, an owner/operator of an
existing source could choose to comply with the applicable Ni emission
limit expressed in lb/MWh. The owner/operator would use the procedures
outlined in Sec. 63.10009 of the proposed rule to convert the
concentration output of Method 29 to the output-based emission rate
format.
To address the need for continuous compliance requirements for the
proposed Ni emission limits, EPA considered the availability and
feasibility of a number of Ni monitoring options ranging from direct
monitoring of Ni emissions, to process parameter monitoring, to control
device parameter monitoring. Monitors for continuously measuring Ni
emissions have not been demonstrated in the U.S. for the purpose of
determining compliance. Therefore, EPA did not consider further the use
of continuous monitors for Ni for the proposed rule.
Another option used in other NESHAP for demonstrating continuous
compliance is to monitor appropriate process and/or control equipment
operating parameters. These parameters are established during the
initial, and
[[Page 4682]]
any subsequent, stack test. Process parameters were not selected as
indicators for Ni emissions from Utility Units because a direct
correlation does not exist between combustion or electricity production
parameters and Ni emission rates from a given unit.
Monitoring of PM control device operating parameters is used in
other NESHAP established for combustion processes and other source
categories that include PM emission limits. The EPA decided to also use
this continuous monitoring approach to demonstrate continuous
compliance with the applicable Ni emission limits set forth in the
proposed rule. The selected operating parameters for the PM control
device used by oil-fired Utility Units (e.g., ESP) are reliable
indicators of control device performance. The EPA believes that
reasonable assurance of compliance with the emission limits proposed
for this NESHAP can be achieved through appropriate monitoring and
inspection of the operation of the APCD that have been demonstrated by
an initial performance test to achieve the applicable Ni emission
limits under the rule.
Compliance calculations. For cogeneration units, steam is also
generated for process use. The energy content of this process steam
must also be considered in determining compliance with the output-based
standard. This consideration is accomplished by taking the net
efficiency of a cogeneration unit into account. Under a Federal Energy
Regulatory Commission regulation, the efficiency of cogeneration units
is determined from the useful power output plus one-half the useful
thermal output (18 CFR 292.205). To account for the process steam
energy contribution to net plant output, a 50-percent credit of the
process steam heat is necessary. Such a credit would, EPA believes,
provide an incentive for cogeneration.
Therefore, owners/operators of cogeneration units subject to the
proposed rule would need to monitor the portion of their net plant
output that is process steam so that they can take the 50-percent
credit of the energy portion of their process steam net output. For
example, a cogeneration unit subject to the rule measures its net
electrical output over a compliance period, as 30,000 MWh. During the
same period the unit burns coal that provides 750 billion Btu input to
its furnace/boiler, and emits 0.2 lb Hg. Using equivalents found in 40
CFR 60 for electric utilities (i.e., 250 million Btu/hr input to a
boiler is equivalent to 73 MWe input to the boiler; 73 MWe input to the
boiler is equivalent to 25 MWe output from the boiler; therefore, 250
million Btu input to the boiler is equivalent to 25 MWe output from the
boiler) the 50-percent credit could be found as follows. The net output
calculation would be 750 billion Btu x (25 MWe output/250 million Btu/
hr input) = 75,000 MWh equivalent electrical output from the boiler
over the compliance period. Of this amount, 30,000 MWh was produced as
electricity sent to the grid, leaving 45,000 MWh as the energy
converted to steam for process use. Half of this amount is 22,500 MWh.
The unit's Hg CEM records a total of 0.2 lb Hg over the same compliance
period. The adjusted Hg emission rate is then: 0.2 lb Hg/(30,000 MWh +
22,500 MWh) = 3.8 x 10-\6\ lb Hg/MWh.
11. How Did EPA Determine Compliance Dates for the Proposed Rule?
Section 112(i) of the CAA specifies the dates by which affected
sources must comply with the emission standards. New or reconstructed
units must be in compliance with the proposed rule immediately upon
startup or [DATE THE FINAL RULE IS PUBLISHED IN THE Federal Register],
whichever is later, except that if the final rule is more stringent
than the proposal, a new source that commences construction before the
final rule is promulgated may comply with the proposed rule for 3 years
before complying with the final rule. Existing sources must be in
compliance with the final rule 3 years after the effective date of the
final rule. Existing sources may seek a permit granting an additional
one year to comply if such time is necessary for the installation of
controls.
We anticipate that a substantial number of sources would have to
install control technologies to meet the limits of the proposed
standard, if the CAA section 112 MACT rule is finalized. We also
believe that such construction could be constrained by the potential
impacts on electricity reliability, delays in obtaining permits, and
other factors (including potential labor and equipment shortages).
Thus, we anticipate that a substantial number of units will seek the 1-
year extension which could unduly burden State and local permitting
authorities. Therefore, EPA is soliciting comment on whether a 1-year
extension should be granted for facilities required to install controls
in order to comply with the proposed CAA section 112 MACT rule, should
it be finalized.
12. How Did EPA Select the Proposed Recordkeeping and Reporting
Requirements?
Under section 114(a) of the CAA, EPA may require owners/operators
of affected sources subject to a NESHAP to maintain records as well as
prepare and submit notifications and reports to the EPA. In addition,
section 504(a) of the CAA mandates that sources required to obtain a
title V permit submit a report setting forth the results of any
required monitoring no less often than every 6 months. The general
recordkeeping, notification, and reporting requirements for all NESHAP
are specified in 40 CFR 63.9 and 40 CFR 63.10 of the General
Provisions, if incorporated into the proposed rule. The recordkeeping,
notification, and reporting requirements for the proposed rule were
selected to include all of the applicable records, notifications, and
reports specified by the General Provisions requirements. Additional
requirements were included in the proposed rule that are necessary to
ensure that a given affected source is complying with the emission
limits from the correct subcategory.
The proposed rule would also require that the owner/operator keep
monthly records for each affected source listing the type of fuel
burned, the total fuel usage, and the fuel heating value. Additional
recordkeeping would be required for those owners/operators electing to
comply with a fuel blending emission limit. The owner/operator would be
required to maintain records of all compliance calculations and
supporting information.
13. Will EPA Allow for Facility-Wide Averaging?
The proposed rule contains provisions allowing the owner/operator
of a coal-fired affected unit to demonstrate compliance through the
averaging of Hg emissions from multiple affected units located at a
common, contiguous facility site. Consistent with EPA policy on
regulatory flexibility, this provision is intended to provide a
facility with the benefit of operational flexibility while still
meeting the proposed emission limitations and achieving the required
emissions reductions. This averaging provision effectively allows the
owner/operator to average the emissions from multiple (two or more)
coal-fired affected units and comply with one applicable facility-wide
emission limitation.
The proposed rule would require that any coal-fired affected unit
included in the facility's averaging regime be a regulated unit under
the proposed rule (i.e., coal-fired Utility Units only, and
[[Page 4683]]
not combined with sources regulated by other rules, such as IB units).
The averaging provision may be applied to meet the proposed
emission limitations for Hg from coal-fired units. An important aspect
of this provision is that the emissions measurements for the averaging
calculations are taken after the last control device. Affected units
that share a common control device are inherently averaged by the
standard compliance calculations provided in Sec. 63.10009 of the
proposed rule. It is the intention of EPA to provide additional
flexibility to average all coal-fired units at one facility into one
averaged emission limit. In accordance with that intent, the initial
and continuous compliance demonstration under this averaging provision
would be to determine the emission rate applicable to all affected
units (which may be individual or blended) according to requirements
under Sec. 63.10009 and then use those limits to calculate a limit for
the emissions averaging group according to Sec. 63.99991 of the
proposed rule.
The owner/operator would be required to limit Hg emissions from the
group of all affected units being averaged to an overall Hg emission
limit (emissions-averaged emission limit, AvEL) during each 12-month
compliance period. The owner/operator would be required to use the AvEL
determined in accordance with Sec. 63.99991 of the proposed rule
throughout the 12-month compliance period and may not switch between
compliance with individual subcategory emission limits and an AvEL. The
format of the AvEL (lb/MWh or lb/TBtu) would also be required to remain
constant throughout the 12-month compliance period. The owner/operator
would keep all records as required by sections 63.10031 and 63.10032 of
the proposed rule. The owner/operator would be required to submit
information on the affected units which comprise each AvEL group for
which the owner/operator used a calculated AvEL; the emission limits
(including format) that would be averaged (i.e., Hg); the units that
will be averaged together; and the calculation of the AvEL with which
the averaged units will comply. The owner/operator may implement
emissions averaging at any time after the effective date with
submission of the averaging plan. The owner/operator must revise the
plan to change an emissions averaging group. The owner/operator must
certify in each semiannual compliance report that the AvEL group of
affected units was in compliance with the emission limitation.
The EPA solicits comment on the emissions averaging provision,
particularly on the usefulness of the provision and its specific
applicability requirements.
III. Proposed Revision of Regulatory Finding on the Emissions of
Hazardous Air Pollutants from Electric Utility Steam Generating Units
A. What Action Is EPA Taking Today?
Today, EPA proposes revising the regulatory finding that it
published on December 20, 2000 (65 FR 79825) pursuant to section
112(n)(1)(A) of the CAA. The EPA is proposing such a revision based on
its review of the December 2000 finding, the Utility RTC underlying
that finding, and the provisions of the CAA. For the reasons discussed
below, EPA proposes to find that regulation of coal- and oil-fired
Utility Units under section 112 is not ``appropriate and necessary''
within the meaning of section 112(n)(1)(A). As a consequence, EPA also
proposes to delete such units from the CAA section 112(c) list. The EPA
does not propose revising its December 2000 conclusion with regard to
HAP emissions from natural-gas fired electric utility steam, however,
as it continues to believe that regulation of such units is not
appropriate and necessary.
What was EPA's December 2000 ``necessary'' finding? Was EPA's
December 2000 ``necessary'' finding overbroad? As noted above, in
December 2000, EPA concluded that it was
``necessary to regulate HAP emissions from coal- and oil-fired
electric utility steam generating units under section 112 of the CAA
because the implementation of other requirements under the CAA will
not adequately address the serious public health and environmental
hazards arising from such emissions.'' (65 FR 79830)
Upon further review of the record and the December 2000 notice, EPA
believes that this finding is over-broad in two respects.
First, the ``necessary'' finding might be interpreted to suggest
that all HAP emissions from coal- and oil-fired Utility Units pose
``serious public health * * * hazards.'' (65 FR 79830) Upon further
review of the record, EPA recognizes that it could not reasonably have
reached such a conclusion based on the record before it in December
2000. That record supports only a finding that emissions of Hg and Ni
warrant regulation. Nothing in the Study or the information EPA
obtained following that study even arguably supports the proposition
that EPA should address HAP emissions from Utility Units other than
emissions of Hg and Ni.
Second, the ``necessary'' finding states that emissions of HAP from
Utility Units result in ``serious * * * environmental hazards.'' (See
65 FR 79830.) (emphasis added.) After re-examining the record, EPA
recognizes that this conclusion also cannot be supported by the record.
As an initial matter, the Utility RTC, consistent with CAA section
112(n)(1)(A), focused solely on hazards to public health, not the
environment. In fact, the Study expressly states that the ecological
impacts associated with HAP from Utility Units were not examined
because such impacts were beyond the scope of the Study mandated by CAA
section 112(n)(1)(A)) (ES at 27). The only information in the record
concerning the effects of HAP on the environment was for Hg, and that
information was obtained after completion of the Utility RTC. Thus,
given the record before the Agency in December 2000, the most EPA could
have intended to state in the December 2000 ``necessary'' finding is it
is necessary to regulate Hg from coal-fired Utility Units and Ni from
oil-fired Utility Units because the implementation of other
requirements under the CAA will not adequately address the serious
public health hazards arising from such emissions or the environmental
hazards associated with Hg. Moreover, as explained below, EPA has
recently re-analyzed this ``necessary'' determination and the premise
underlying that determination.
Does other CAA authority exist to address emissions of Hg and Ni
from coal- and oil-fired Utility Units? The EPA continues to believe
that emissions of Hg from coal-fired Utility Units and emissions of Ni
from oil-fired units pose hazards to public health, that coal-fired
Utility Units are the largest domestic source of Hg emissions, and that
oil-fired units are the primary source of Ni emissions. These findings
support a determination that it is appropriate to regulate emissions of
Hg and Ni from Utility Units.
We have had an opportunity to re-assess the ``necessary'' finding
made in December 2000. Today, we propose to revise that finding
because, after examining the scope of available authorities under the
CAA, we have determined that there is, in fact, another viable
statutory mechanism that would adequately address Hg and Ni emissions
from coal- and oil-fired Utility Units. That authority is CAA section
111.
The scope of existing authorities under the CAA. The EPA interprets
the language of CAA section 112(n)(1)(A)
[[Page 4684]]
and the limited legislative history relating to that provision as
indicating Congress' intent that Utility Units be regulated under
section 112 only if the other authorities of the CAA, once implemented,
would not adequately address those HAP emissions from Utility Units
that warrant regulation. This interpretation is supported by the first
sentence of section 112(n)(1)(A), which requires EPA to conduct a study
that focuses on the hazards to public health that would exist following
implementation of the other authorities of the CAA. It is further
evidenced by the final sentence of section 112(n)(1)(A), which calls
for regulation of Utility Units under section 112 only if, based on the
results of the Study, EPA determines that it is both appropriate and
necessary to regulate such units. Finally, the remarks made by
Congressman Oxley, a member of the conference committee, concerning the
Conference Report on the CAA Amendments of 1990, confirm that Congress
sought to regulate under section 112 ``only those units [Utility Units]
that * * * (the Administrator) determines--after taking into account
compliance with all other provisions of the act * * *--have been
demonstrated to cause a significant threat of serious adverse effects
on public health.'' \7\ (136 Cong. Rec. E3670, 3671 & H12911, 12934
(daily ed. Nov. 2, 1990) (Statement of Congressman Oxley)
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\7\ Congressman Oxley further noted that regulation under CAA
section 112 should be imposed ``only if warranted by the scientific
evidence.'' 136 Cong. Rec. E3670, 3671 & H12911, 12934 (daily ed.
No. 2, 1990) (Statement of Congressman Oxley).
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Based on the foregoing, EPA believes if we make a determination
under section 112(n)(1)(A) that it is appropriate to regulate Utility
Units, we are not compelled to regulate Utility Units under section 112
if other authorities in the CAA exist to adequately address health
hazards that occur as a result of HAP emissions. The EPA believes that
this is a reasonable interpretation of the term ``necessary'' in CAA
section 112(n)(1)(A), and that it is wholly consistent with its
interpretation of the term in December 2000. (See 65 FR 79830. ``It is
necessary to regulate * * * under section 112 of the CAA because the
implementation of other requirements under the CAA will not adequately
address the serious public health and environmental hazards arising
from such emissions * * *'')
Since December 2000, EPA has had the opportunity to conduct a more
thorough review of the available authorities under the CAA. Based on
that review, EPA has identified a provision of the CAA that it believes
can be employed to adequately address the hazards to public health
resulting from Hg and Ni emissions from Utility Units. That provision
is CAA section 111, which authorizes EPA to develop standards of
performance for new and existing sources of air pollutants that cause,
or contribute significantly to, air pollution which may reasonably be
anticipated to endanger public health or welfare.
The EPA based its ``necessary'' finding in December 2000 solely on
its belief, at the time, that there were no other authorities under the
CAA that would adequately address Hg and Ni emissions from coal- and
oil-fired Utility Units. Now that we have re-examined the scope of
existing authorities under the CAA and identified a viable statutory
mechanism other than section 112, we propose to revise the December
2000 ``necessary'' finding accordingly. We specifically propose to find
that regulation of coal- and oil-fired Utility Units under section 112
is not necessary because CAA section 111, once implemented, would
adequately address the public health hazards posed by Utility Unit
emissions of Hg and Ni.\8\
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\8\ The EPA examined various provisions of the CAA, including
section 111, prior to issuing its December 2000 regulatory finding.
(Utility RTC.) At that time, we did not believe that any other
provisions of the CAA would adequately address the health hazards of
concern associated with Hg and Ni emissions. Now, after re-analyzing
the provisions of the CAA, we recognize that CAA section 111 is a
viable statutory mechanism that would adequately address Hg and Ni
emissions from coal- and oil-fired units. The premise underlying our
December 2000 ``necessary'' finding, therefore, lacks foundation.
Nothing precludes EPA from revisiting its December 2000
``necessary'' determination, particularly, where, as here, the basis
for that determination involved the scope of existing statutory
provisions and those provisions have not changed substantively since
1990.
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We further believe that CAA section 111, once implemented, would
adequately address any environmental effects associated with Hg
emissions from Utility Units, as documented in the record. We recognize
that the plain language of CAA section 112(n)(1)(A) requires an
examination solely of hazards to public health associated with HAP
emissions, not of hazards to the environment. Nevertheless, in this
case, and given that the December 2000 finding addresses both the
health and environmental effects of Hg, we believe that our section 111
proposal would adequately address both of those effects.
Regulation under CAA section 111. Overview. The two relevant
provisions of section 111 are section 111(b), which applies to new
sources, and section 111(d), which applies to existing sources. As
explained below, EPA believes that these provisions authorize the
establishment of standards of performance both for Hg emissions from
new and existing coal-fired Utility Units and for Ni emissions from new
and existing oil-fired units, and that such standards, once finalized,
would adequately address the health hazards resulting from Hg and Ni
emissions. Indeed, through this notice, EPA proposes such standards of
performance. We explain below why the proposed standards adequately
address any public health hazards resulting from Hg and Ni emissions
from Utility Units and the environmental effects associated with Hg
emissions.
Regulation under section 111(b). Pursuant to CAA section
111(b)(1)(A), EPA has established a list of stationary source
categories. The EPA is to include a source category on the section
111(b) list if it determines that such category causes, or contributes
significantly to, air pollution which may reasonably be anticipated to
endanger public health or welfare. Section 111(b) further requires EPA
to establish federal standards of performance for new sources within
each listed source category.
The EPA included Utility Units on the section 111(b) list of
stationary sources in 1979. (44 FR 33580; June 11, 1979.) The EPA has
also previously promulgated federal standards of performance for such
units for pollutants like NOX, PM, and SO2. (See
subpart Da of 40 CFR part 60.)
Nothing in section 111(b) precludes EPA from promulgating
additional standards of performance for other pollutants emitted from
new Utility Units. Indeed, where, as here, EPA has determined that
emissions of Hg and Ni from coal- and oil-fired Utility Units warrant
regulation, the establishment of Federal standards of performance under
section 111(b) is appropriate.
Moreover, nothing in CAA section 111 or section 112 indicates that
Congress sought to regulate HAP exclusively under section 112. Rather,
the language of sections 112(c)(6), 112(d)(7) and 112(n)(1)(A) supports
the conclusion that HAP emissions could be regulated under other
provisions of the CAA. There is nothing in the legislative history to
suggest that Congress sought to preclude EPA from regulating HAP under
other sections of the Act. We, therefore, believe that CAA section
111(b), as amended in 1990, constitutes a viable and appropriate
statutory authority by which to regulate Hg emissions from new coal-
fired Utility Units and Ni emissions from new oil-fired units.
[[Page 4685]]
Regulation under section 111(d). CAA section 111(d), unlike section
111(b), specifically references CAA section 112. The import of that
reference is not clear, however, because Public Law 101-549, which is
the 1990 amendments to the CAA, contains two different and conflicting
amendments to section 111(d). To understand this conflict, it is useful
to start with the language of section 111(d) as contained in the 1977
Amendments to the CAA.
In 1977, section 111(d)(1) read as follows:
The Administrator shall prescribe regulations which shall
establish a procedure similar to that provided by section 7410 of
this title under which each State shall submit to the Administrator
a plan which (A) establishes standards of performance for any
existing source for any air pollutant (i) for which air quality
criteria have not been issued or which is not included on a list
published under section 7408(a) or 7412(b)(1)(A) of this title, but
(ii) to which a standard of performance under this section would
apply if such existing source were a new source. * * *
This language provides that standards of performance should not be
established under section 111(d) with respect to any pollutants that
are listed as hazardous air pollutants under section 112(b)(1)(A) of
the 1977 CAA.
In the 1990 Amendments to the CAA, two different and conflicting
amendments to section 111(d) were enacted. Presumably, Congress did not
realize that it had passed two different amendments to the same
statutory provision. The first amendment, which is the House amendment,
is contained in section 108(g) of Public Law 101-549. That section
amends section 111(d)(1)(A)(i) of the 1977 CAA by striking the words
``or 112(b)(1)(A)'' from the 1977 CAA and inserting in its place the
following phrase: ``or emitted from a source category which is
regulated under section 112.'' The second amendment to section 111(d),
which is the Senate amendment, is labeled a ``conforming amendment''
and is set forth in section 302 of Public Law 101-549. That section
amends CAA section 111(d)(1) of the 1977 CAA by striking the reference
to ``112(b)(1)(A)'' and inserting in its place ``112(b).''
These two amendments are reflected in parentheses in the Statutes
at Large as follows:
The Administrator shall prescribe regulations which shall
establish a procedure similar to that provided by section 7410 of
this title under which each State shall submit to the Administrator
a plan which (A) establishes standards of performance for any
existing source for any air pollutant (i) for which air quality
criteria have not been issued or which is not included on a list
published under section 7408(a) (or emitted from a source category
which is regulated under section 112) (or 112(b)), but (ii) to which
a standard of performance under this section would apply if such
existing source were a new source. * * *
EPA recognizes that the United States Code does not contain the
parenthetical reference to the Senate amendment in section 302 of
Public Law 101-549; the codifier's notes to this section state that the
Senate amendment ``could not be executed'' because of the other
amendment to section 111(d) contained in the same Act. The United
States Code does not control here, however. The Statutes at Large
constitute the legal evidence of the laws, where, as here, title 42 of
the United States Code, which contains the CAA, has not been enacted
into positive law. See 1 U.S.C. 204(a); United States v. Welden, 377
U.S. 95, 98 n.4 (1964); Washington-Dulles Transportation Ltd. v.
Metropolitan Washington Airports Auth., 263 F.3d 371, 378 (4th Cir.
2001).
A literal reading of the House amendment, as contained in the
Statutes at Large, is that a standard of performance under CAA section
111(d) cannot be established for any air pollutant that is emitted from
a source category regulated under section 112. Under this reading, EPA
could not regulate, under CAA section 111(d), HAP and non-HAP emissions
that are emitted from a source category regulated under section 112. A
literal reading of the Senate amendment is that a standard of
performance under section 111(d) cannot be established for any HAP that
is listed in section 112(b)(1), regardless of what categories of
sources of that pollutant are regulated under section 112. The House
and Senate amendments conflict in that they provide different standards
as to the scope of EPA's authority to regulate under section 111(d).
Over the years, EPA has identified other conflicting provisions of
the CAA. See, e.g., Citizens to Save Spencer County v. EPA, 600 F.2d
844 (D.C. Cir. 1979). Consistent with principles of statutory
construction, the Agency has always sought to harmonize such
conflicting provisions, where possible, and to adopt a reading that
gives some effect to both provisions. The first step in this process
involves an evaluation of what Congress intended by each amendment.
This step is difficult here because of the absence of legislative
history directly addressing the amendments. For that reason, we focus
on the plain language of the amendments.
The Senate language reflects the Senate's intent to retain the pre-
1990 approach of precluding regulation under CAA section 111(d) for any
HAP that is listed under section 112(b). The Senate's intent is further
demonstrated by the fact that the amendment itself it labeled a
``conforming amendment,'' which is generally a non-substantive
amendment. By contrast, the House amendment was not a conforming
amendment. Rather, the House changed the focus of CAA section 111(d)
and sought to preclude only regulation of pollutants emitted from a
source category that is actually regulated under section 112. One
reasonable interpretation is that the House amendment reflects a desire
to change the pre-1990 approach and to expand EPA's authority as to the
scope of pollutants that could be regulated under section 111(d). One
possible reason for this change is that the House did not want to
preclude EPA from regulating under section 111(d) those pollutants
emitted from source categories which were not actually being regulated
under section 112. Such a reading of the House language would authorize
EPA to regulate under section 111(d) existing area sources which EPA
determined did not meet the statutory criterion set forth in section
112(c)(3), as well as existing Utility Units.
One way to harmonize the Senate and House amendments is to
interpret them as follows: Where a source category is being regulated
under section 112, a section 111(d) standard of performance cannot be
established to address any HAP listed under 112(b) that may be emitted
from that particular source category. Thus, if EPA is regulating source
category X under section 112, section 111(d) could not be used to
regulate HAP emissions from that particular source category.
We believe that this is a reasonable interpretation as it gives
some effect to both amendments. First, it gives effect to the Senate's
desire to focus on HAP listed under section 112(b), rather than
applying the section 111(d) exclusion to non-HAP emitted from a source
category regulated under section 112, which a literal reading of the
House amendment would do. Second, it gives effect to the House's
apparent desire to increase the scope of EPA's authority under section
111(d) and to avoid duplicative regulation of HAP for a particular
source category. We recognize that our proposed reconciliation of the
amendments does not give full effect to the House's language, because a
literal reading of the House language would mean that EPA could not
regulate both HAP and non-HAP from a source category regulated under
section 112. Such a reading would be inconsistent with the general
thrust of the 1990
[[Page 4686]]
amendments, which, on balance, reflects Congress's desire to require
EPA to regulate more substances, not to eliminate EPA's ability to
regulate large categories of pollutants like non-HAP. Furthermore, EPA
has historically regulated non-HAP under section 111(d), even where
those non-HAP were emitted from a source category actually regulated
under section 112. See, e.g., 40 CFR 62 1100 (California State Plan for
Control of Fluoride Emissions from Existing Facilities at Phosphate
Fertilizer Plants). We do not believe that Congress sought to eliminate
regulation for a large category of sources in the 1990 Amendments and
our proposed interpretation avoids this result.
Finally, we believe that the proper inquiry for assessing whether
to revise the December 2000 ``necessary'' finding is whether CAA
section 111(d) constituted a viable statutory authority by which to
address Hg and Ni emissions from existing coal- and oil-fired Utility
Units as of 1998, the date on which EPA completed the Utility RTC. The
answer, we believe, is yes. At that time, Utility Units were not listed
under section 112, which consistent with our proposed interpretation of
the conflicting amendments would allow us to regulate HAP from existing
sources of such units under CAA section 111(d). The EPA, therefore,
believes that it has the authority, and that it had the authority in
1998 when it completed the Utility RTC, to regulate Hg emissions from
existing coal-fired Utility Units and Ni emissions from existing oil-
fired units pursuant to section 111(d).
Adequacy of regulation under section 111. Adequacy of regulatory
methods. The EPA proposes to conclude that section 111 offers adequate
regulatory authority to control Hg and Ni emissions from both existing
and new coal- and oil-fired Utility Units. For existing sources,
subsection (d) of section 111 authorizes EPA to promulgate ``standards
of performance'' that States must include in SIP-like plans applicable
to those sources. The term ``standard of performance'' is defined in
section 111(a)(1) as--
a standard for emissions of air pollutants which reflects the degree
of emission limitation achievable through the application of the
best system of emission reduction which (taking into account the
cost of achieving such reduction and any non-air quality health and
environmental impact and energy requirements) the Administrator
determines has been adequately demonstrated.\9\
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\9\ The term, ``standard of performance'' is also defined in
section 302(l), although there may be uncertainty about whether that
defintion applies to the term as used under section 111. For
purposes of this discussion, the section 302(l) defintion is not
material.
The EPA believes that the gravamen of this definition is the
phrase, ``best system of emission reduction.'' While the parenthetical
following this phrase obligates EPA to consider the factors specified
in that parenthetical, the term ``best system'' is not defined, and
implicitly accords broad discretion to the Administrator, which
includes the demonstration of such systems. The term ``system'' implies
a broad set of controls, and the term ``best'' confers upon the
Administrator the authority to promulgate regulations requiring
controls that he considers superior. Moreover, except that the
parenthetical phrase in the definition mandates consideration of
certain factors, the definition provides no other explicit constraints
in determining the ``best system.'' Therefore, EPA believes that in
developing the ``best system of emission reduction,'' the Administrator
must consider cost, non-air quality health and environmental factors,
as well as energy requirements; and that he is authorized to consider,
at his discretion, human health and environmental impacts, air quality
impacts, timing and feasibility of control factors, and other factors.
This broad authority conferred on the Administrator means that
section 111 constitutes an adequate mechanism for regulating Hg
emissions from coal-fired Utility Units, and Ni from oil-fired units.
Because the Administrator may consider a broad range of factors in
developing standards of performance under section 111, the
Administrator has the authority to develop control levels to address
the emissions of Hg and Ni that warrant regulation.
Specifically, as described elsewhere in this notice, EPA is
proposing today standards of performance for regulating Hg and Ni
emissions from certain sources. In the case of Ni, EPA is proposing
emission rate requirements to address emissions from oil-fired Utility
Units. The basis for these standards of performance is discussed
elsewhere in today's notice.
In the case of Hg, EPA is proposing a ``cap-and-trade'' program for
emissions of Hg from existing Utility Units. Mercury emissions, on a
nationwide basis would, in effect, be capped at a specified level. This
cap assures permanent reductions in Hg emissions, which an emissions
rate control requirement cannot, in-and-of-itself, assure. States would
be allocated specified amounts of Hg allowances--that is authorizations
to emit a unit of Hg--which the States would then allocate to their
Utility Units. The Utility Units would be permitted to emit Hg up to
the amount of their allowances. The trading feature of this program
would allow Utility Units to purchase or sell allowances, and adjust
their emissions accordingly.
The basis for the 2010 and 2018 caps is discussed elsewhere in
today's notice. Moreover, the authorization to trade allows
implementation of the emissions cap in the most cost-effective manner.
Thus, the cap provides health protection by limiting overall emissions,
but in a cost-effective manner.
The EPA recognizes, however, that the overall cap level may not
eliminate the risk of unacceptable adverse health effects of Hg
emissions. Moreover, a cap-and-trade program raises the possibility
that any particular utility may opt to purchase allowances, instead of
implementing controls, and that this may result in continued Hg
emissions at the previous, uncontrolled levels from that Utility Unit.
These emissions may have adverse health impacts within the local area.
The EPA recognized this issue in its initial 112(n) finding, when it
stated:
There is considerable interest in an approach to mercury
regulation for power plants that would incorporate economic
incentives such as emissions trading. Such an approach can reduce
the cost of pollution controls by allowing for least-cost solutions
among a universe of facilities that face different control costs.
Trading also can allow for a greater level of control overall
because it offers the opportunity for greater efficiency in
achieving control. The EPA, however, recognizes and shares concerns
about the local impacts of mercury emissions and any regulatory
scheme for mercury that incorporates trading or other approaches
that involve economic incentives must be constructed in a way that
assures that communities near the sources of emissions are
adequately protected. Thus, in developing a standard for utilities,
the EPA should consider the legal potential for, and the economic
effects of, incorporating a trading regime under section 112 in a
manner that protects local populations.
(Regulatory Finding on the Emissions of Hazardous Air Pollutants From
Electric Utility Steam Generating Units, FR 65 at 79830 and 65 FR
79831).
To assure that the overall cap level, and the pattern of Hg
emissions resulting from the trading program, will be adequately
protective, EPA proposes today to couple this program with an
evaluation of whether Hg emissions remaining after compliance with the
cap-and-trade requirements would cause unacceptable adverse health
effects. That is, after implementation of the control requirements by
2010 and by 2018, EPA will evaluate the emission levels, attendant
health risks, and
[[Page 4687]]
available control mechanisms and determine whether the actual
reductions achieved under this program significantly differ from the
outcome predicted by our current analysis. The EPA retains the
authority to revise its conclusions as to what constitutes the ``best
system'' of emissions reductions for existing sources, and, therefore,
to revise the standard of performance, to require additional reductions
or controls to address such risks, based on information that would
justify selection of a tighter regulatory regime.
Similarly, EPA intends to evaluate whether, following
implementation of the controls on Ni emissions from existing oil-fired
units, adverse health effects might remain from Ni emissions. As
described above, EPA retains authority under section 111(d) to
promulgate additional requirements on Ni emissions to address those
health effects.
The EPA believes that these overall standards of performance for
existing Utility Unit sources of Hg and Ni coupled with authority to
evaluate remaining health risks and conduct further rulemaking,
adequately address all health effects from Hg emissions that warrant
regulation from existing coal-fired Utility Units and Ni emissions from
existing oil-fired units as well as the environmental effects of Hg.
As to new sources, section 111(b)(1)(B) authorizes EPA to
promulgate ``standards of performance'' directly regulating new
sources. The section 111(a)(1) definition of ``standard of
performance'' applies to these regulations, and thereby authorizes EPA
to consider the same range of factors described above, including, for
example, human health and environmental factors as well as
technological and feasibility factors. Upon consideration of these
factors, EPA proposes a technology-based set of controls for Hg
emissions from new coal-fired Utility Units and Ni emissions from new
oil-fired units. The basis for these controls is discussed elsewhere in
today's notice. Further, section 111(b) provides adequate authority for
EPA (i) to evaluate whether, following compliance with the new source
standards, remaining Hg and/or Ni emissions result in unacceptable
adverse health impacts; and, if so, (ii) to revise the standards of
performance to include additional restrictions for those emissions. As
a result, for new sources of both Hg and Ni emissions, as in the case
of existing sources, section 111 provides regulatory authority that
will adequately address all adverse health (and environmental) effects
of concern.
Time for implementation. Why does regulation under section 111
adequately address the hazards of concern to public health associated
with Hg and Ni emissions? This action is one part of a broader effort
to issue a coordinated set of emissions limitations for the power
sector. Today's rule would establish a mechanism by which Hg emissions
from new and existing Utility Units would be capped at specified,
nation-wide levels. A first phase cap would become effective in 2010
and a second phase cap in 2018. Facilities would demonstrate compliance
with the standard by holding one ``allowance'' for each ounce of Hg
emitted in any given year. Allowances would be readily transferrable
among all covered facilities. We believe that such a ``cap and trade''
approach to limiting Hg emissions is the most cost effective way to
achieve the reductions in Hg emissions from the power sector that are
needed to adequately protect human health and the environment.
The added benefit of this approach is that it dovetails well with
the SO2 and NOX IAQR published elsewhere in
today's Federal Register. This rule would establish a broadly-
applicable cap and trade program that would significantly limit
SO2 and NOX emissions from the power sector. The
advantage of regulating Hg at the same time and using the same
mechanism as SO2 and NOX is that significant Hg
emissions reductions can and will be achieved by the air pollution
controls designed and installed to reduce SO2 and
NOX. In other words, Hg is reduced as a ``co-benefit'' of
controlling SO2 and NOX. Thus, the coordinated
regulation of Hg, SO2, and NOX allows Hg
reductions to be achieved in a particularly efficient and cost
effective manner.
In theory, the ``co-benefit'' argument could work in both
directions: controlling Hg also controls SO2 and
NOX; controlling SO2 and NOX also
controls Hg. In deciding how regulatory deadlines influence how
investments in controls are sequenced, it makes much more sense to lead
with SO2 and NOX controls, which are well
established, than to lead with Hg controls, which are only at the
beginning stages of commercialization. Overly ambitious Hg mandates in
the near-term could actually hamper innovation toward more effective
and less costly technologies. The quantified health benefits of
NOX and SO2 are also larger and more certain.
The cap and trade approach to regulating Hg emissions offers
certain other advantages over the unit-by-unit or facility-by-facility
approach that we have traditionally employed under section 112. For
example, a cap and trade system establishes fixed emissions caps that
cannot be exceeded, even when existing plants are expanded and new
plants are constructed. Thus, the cap provides absolute certainty with
regard to national emissions. In contrast, a section 112 rule would
limit the emissions of individual units or facilities, but would not
limit overall emissions to the environment from the sector.
Another advantage of concurrently regulating Hg and SO2
is derived from the fact that companies will have the opportunity under
the SO2 cap to generate extra allowances by achieving early
reductions. For example, the first phase SO2 cap under the
transport rule becomes effective in 2010. Prior to that year, companies
have an incentive to achieve greater SO2 reductions than
needed to meet the current Acid Rain cap because the excess allowances
they generate can be ``banked'' and either later sold on the market or
used to demonstrate compliance in 2010 and beyond at the facility that
generated the excess allowances. In either case, there will be earlier
health and environmental benefits because reductions are achieved
sooner than they otherwise would be. These benefits extend to Hg
emissions because, as explained above, we expect companies to meet the
Hg cap by way of the controls they install for SO2 and
NOX. Consequently, the incentive to achieve early reductions
for SO2 effectively assures early reductions for Hg.
Several additional technical and policy considerations strongly
favor a cap-and-trade system. The objective of Hg control, as we
understand it today, is not advanced as effectively under the
prescriptive traditional MACT approach under section 112(d) for the
regulation of HAP. The MACT approach calls for two phases of
regulation: the first based on the concept of ``maximum achievable
control technology''; the second, to occur 8 years later, based on a
``residual health-risk determination.'' The second phase itself
involves a complex, two-step framework: one step to determine a
``safe'' or ``acceptable risk'' level, considering only public health
factors, and the second to set an emission standard that provides an
``ample margin of safety'' to protect public health, considering
relevant factors in addition to health, such as costs, economic
impacts, technical feasibility, uncertainties and other factors.
First, a cap-and-trade approach sets a specific limit or cap on
allowable emissions. Under a traditional section 112(d) MACT approach,
standards are
[[Page 4688]]
based on rates of emissions per unit of input or of production, for
example, pounds per million Btu. Variations in production or
differences in input mix will result in fluctuations in Hg emissions.
Thus, with shifts in coal use and with growth in the economy, Hg
emissions would likely substantially exceed the overall emission level
achieved when the MACT limits are initially met.
Second, a trading approach is better suited to stimulating
development and adoption of new technologies. A cap-and-trade system
provides a market incentive for the development and use of cost-
effective technology to reduce Hg emissions. A MACT approach provides
no such market incentive, so plants do not have an incentive to reduce
emissions below the required level. Additionally, the ability to bank
unused allowances for future use leads to early reductions of Hg
emissions. A trading approach is forward-looking in its assessment of
technology, in that it provides a continuous incentive for firms to
innovate and develop more cost-effective technologies to reduce Hg
emissions.
The traditional section 112(d) MACT approach is designed to promote
the use of proven control technologies by requiring all sources in a
category to achieve the degree of emission control already accomplished
by the average of the best 12 percent of sources in the category.
However, such a MACT approach will not stimulate innovation in Hg
control technology as well as a cap-and-trade approach because it does
not reward reductions beyond the required levels.
Indeed, a traditional 112(d) MACT approach even could inhibit
innovation. Section 112(d) does provide legal authority to go ``beyond-
the-floor'' to require control strategies more stringent than the MACT
floor, but the science, engineering and economics of Hg control have
not progressed enough to support the technical determination that would
be needed to support a section 112(d) standard that goes beyond the
MACT floor. Once MACT-level controls are installed, there is little
incentive for firms to develop even more effective technologies. In
addition, the MACT deadline is so tight (2007 with only 1 year of
possible extension) that affected firms would be unlikely to risk both
capital and non-compliance in order to use more innovative approaches
to Hg control.
Moreover, a trading approach could spur the development of cost-
effective break-through technologies to control national and local Hg
emissions. Such innovations would allow the U.S. to play a leadership
role in the reduction of global Hg emissions as well. This is a crucial
advantage of a trading approach to ultimately help remedy the problems
posed by Hg emissions.
Third, from a capital planning perspective, a trading approach
permits utilities to make a much more rational investment in emissions
control than a traditional MACT approach. We now understand that
utility investments in reducing criteria air pollutants (particulate
matter, sulfur dioxide and oxides of nitrogen) provide a ``co-benefit''
for Hg control because some forms of Hg (especially those that are
deposited nearest plants) are controlled by the same technologies used
to control criteria pollutants. The exact size of this co-benefit is
not known. In any event, given the likelihood of co-benefits, it makes
good economic sense for utilities to coordinate control of criteria air
pollutants--especially those needed to achieve the new air quality
standards for fine particulate matter and ozone--with their capital
investments aimed at reducing Hg emissions. The statutory deadlines for
a Hg MACT rule do not permit this rational sequence of investments.
Thus, the Agency has carefully considered sections 112(d), 111, and
112(n) to determine which is more appropriate for application to Hg
emissions from coal-fired Utility Units. The scientific, engineering,
economic, and environmental considerations all weigh heavily in favor
of a trading-based approach.
B. Is It Appropriate and Necessary To Regulate Coal- and Oil-Fired
Utility Units Under Section 112 Based Solely on Emissions of Non-Hg and
Non-Ni HAP?
In light of our revised interpretation of the scope of existing
authority under the CAA, we have re-examined the results of the Utility
RTC, focusing on the non-Hg and non-Ni HAP emissions from coal- and
oil-fired Utility Units. The Study indicates that there are no non-Hg
or non-Ni HAP emissions from Utility Units that warrant regulation.
We do recognize that in December 2000, we stated that arsenic and a
few other metals, such as chromium, Ni and cadmium, were of potential
concern for carcinogenic effects (65 FR 79827). We continue to believe,
as stated above, that the record supports a distinction between the
treatment of Ni emissions from oil-fired Utility Units and the
emissions of other non-Hg metallic HAP. Such a distinction is warranted
based on the relative magnitude of Ni that is emitted from oil-fired
utility units on an annual basis and the scope and number of adverse
health effects associated with such emissions. Thus, although we
recognize that uncertainties do exist with regard to the data and
information we have obtained to date for non-Hg metallic HAP, including
Ni, we believe that the nature of the uncertainties associated with the
non-Hg, non-Ni metallic HAP are so great that regulation of such
pollutants is not appropriate at this time since those pollutants do
not pose a hazard to public health that warrants regulation. The EPA
does intend, however, to continue to study these pollutants in the
future. The EPA also intends to continue to study dioxins, HCl, and HF
in the future, but, at this time, the Study and the information EPA has
obtained since the Study reveal no public health hazards reasonably
anticipated to occur as a result of these HAP emissions from Utility
Units such that they warrant regulation.\10\
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\10\ As noted above, after the December 2000 finding, EPA
conducted additional modeling that confirmed the Utility RTC's
conclusion that acid gas HAP, such as HCl, HF, and Cl, pose no
hazards to public health that warrant regulation. Furthermore, since
December 2000, EPA has not obtained any new information that would
cause it to modify its conclusion concerning the lack of health
effects that warrant regulation associated with HAP other than Hg
and Ni.
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Therefore, we believe that emissions of non-Hg and non-Ni HAP
emissions from coal- and oil-fired Utility Units do not warrant
regulation. We recognize that we based our appropriateness finding in
December 2000, in part, on the existence of available control options
that would reduce HAP emissions, including Hg, from Utility Units. See
65 FR 79830. The focus on available technologies was, however, a
subsidiary rationale and one that was included only after we had
determined that emissions of particular HAP from coal- and oil-fired
Utility Units posed significant hazards to public health and the
environment and that those hazards could only be addressed under CAA
section 112. See 65 FR 79830.
As discussed above, we believe that any health effects resulting
from Hg and Ni emissions from Utility Units can and will be addressed
adequately pursuant to CAA section 111. Thus, while control strategies
may exist to control the remaining HAP emitted from coal- and oil-fired
Utility Units (i.e., HAP other than Hg and Ni), we do not believe that
it is appropriate to regulate such HAP under section 112 where we have
not determined that emissions of such HAP from Utility Units pose
health hazards that warrant regulation. This conclusion is consistent
with CAA section 112(n)(1)(A), in which Congress called for EPA to
focus on the health effects of
[[Page 4689]]
HAP from Utility Units following imposition of the other requirements
of the CAA.
Moreover, even if in the future EPA finds that HAP emissions from
Utility Units other than Hg and Ni emissions warrant regulation, EPA
believes that CAA section 111 could be used to adequately address those
hazards. Thus, EPA proposes to find that it is not only inappropriate
to regulate coal- and oil-fired Utility Units under section 112 for HAP
emissions other than Hg and Ni, but that it is not necessary to do so.
C. What Effect Does Today's Proposal Have on the December 2000 Decision
To List Coal- and Oil-Fired Utility Units Under Section 112(c)?
In CAA section 112, Congress established a framework by which
source categories could be listed, and once listed, emission standards
developed for the listed source categories. The criteria and basis for
listing a source category under section 112 differ depending on the
sources at issue. (See generally CAA section 112(c) (discussing major
and area sources).) In particular, for Utility Units, it only would be
possible for EPA to list Utility Units under section 112(c) if it first
made the section 112(n)(1)(A) finding that it was both appropriate and
necessary to regulate such units under section 112, after EPA reviewed
the results of its section 112(n)(1)(A) study concerning health effects
and alternative control strategies.
In its December 2000 notice EPA took this additional step and after
finding it was appropriate and necessary to regulate Utility Units
under section 112, went on to list coal- and oil-fired Utility Units
under section 112(c)(65 FR 79831).
As explained above, EPA has conducted a thorough re-analysis of the
provisions of the CAA and determined that CAA section 111 is a viable
statutory mechanism that would adequately address Hg and Ni emissions
from coal- and oil-fired Utility Units. Therefore, EPA believes that
the premise underlying its December 2000 ``necessary'' finding, that no
other authority exists under the CAA to adequately address the public
health hazards associated with Hg and Ni emissions, lacks foundation.
The EPA also believes that it is not appropriate to regulate HAP other
than Hg and Ni under section 112 because the Utility RTC reveals that
there are no health hazards that warrant regulation associated with
such HAP. Moreover, even if in the future EPA finds that there are HAP
emissions (other than Hg and Ni) from Utility Units that pose hazards
to public health and warrant regulation, EPA believes that CAA section
111 would adequately address those hazards and, therefore, that
regulation of such units under section 112 would not be necessary. For
all of these reasons, EPA now believes that its initial decision to
list coal- and oil-fired Utility Units under section 112(c) in December
2000 was without proper foundation. The EPA, therefore, proposes to
modify the section 112(c) list to delete coal- and oil-fired Utility
Units as a source category. In light of EPA's interpretation and
proposed use of its existing authority under the CAA and, in
particular, CAA section 111, we propose to conclude that the statutory
listing criteria were not met in December 2000.
The EPAs proposed action here is wholly consistent with its
historical interpretation of CAA section 112(c)(9), which is that the
de-listing criteria in section 112(c)(9) apply only where the original
listing of a source category was consistent with the statutory listing
criteria. The failure to fully recognize the scope of existing
statutory authority in December 2000, is analogous to those situations
where EPA has listed a source category under section 112(c)(1), and
later determined that it lacked a factual predicate for such listing
and, therefore, delisted the source category without following the
criteria of section 112(c)(9). The EPA has done this on several
occasions. For example, in 1992, EPA listed asphalt concrete
manufacturers as a major source category \11\ under section 112(c)(1),
and then in 2002, delisted that category without following the
statutory criteria in section 112(c)(9). The EPA did so because it
determined that the initial criteria for listing had not been met since
the sources in the asphalt concrete manufacturing category did not emit
or have the potential to emit sufficient tons of hazardous air
pollutants annually to satisfy the statutory definition of ``major
source.'' See 67 FR 6521, 6522 (February 12, 2002); see also 63 FR
7155, 7157 (February 12, 1998); 61 FR 28197, 28200 (June 4, 1996).
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\11\ Under the statute, a ``major source'' is any stationary
source or group of stationary sources at a single location and under
common control that emits or has the potential to emit 10 tons per
year or more of any HAP or 25 tons per year or more of any
combination of HAP.
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IV. Proposed Standards of Performance for Mercury and Nickel From New
Stationary Sources and Emission Guidelines for Control of Mercury and
Nickel From Existing Sources: Electric Utility Steam Generating Units
A. Background Information
1. What Is the Statutory Authority for The Proposed Section 111
Rulemaking?
Section 111(b) of the CAA requires EPA to promulgate standards of
performance for emissions of air pollutants from new stationary
sources. These standards are typically referred to as NSPS. Section
111(d) requires the EPA to prescribe regulations that establish a
procedure by which each State shall submit plans which establish
standards of performance for existing sources for air pollutants for
which air quality criteria have not been set but for which NSPS have
been established.
2. What Criteria Are Used in the Development of NSPS?
Section 111(a)(1) of the CAA requires that standards of performance
reflect the
* * * degree of emission limitation achievable through application
of the best system of emission reduction which (taking into account
the cost of achieving such reduction and any non-air quality health
and environmental impact and energy requirements) the Administrator
determines has been adequately demonstrated.
The reader is referred to our interpretation of standard of
performance set forth above.
B. Proposed New Standards and Guidelines
1. What Source Category Is Affected by the Proposed Rulemaking?
The subpart Da NSPS apply to Utility Units capable of firing more
than 73 megawatts (MW) (250 million Btu/hour) heat input of fossil
fuel. The current NSPS also apply to industrial cogeneration facilities
that sell more than 25 MW of electrical output and more than one-third
of their potential output capacity to any utility power distribution
system.
2. What Pollutants Are Covered by the Proposed Rulemaking?
The proposed rule would add Hg and Ni to the list of pollutants
covered under subpart Da by establishing emission limits for new
sources and guidelines for existing sources. New sources (and existing
subpart Da facilities), however, remain subject to the applicable
existing subpart Da emission limits for NOX, SO2,
and PM. See 40 CFR part 60, subpart Da, Standards of Performance for
Electric
[[Page 4690]]
Utility Steam Generating Units for which Construction is Commenced
after September 18, 1978.
3. What Are the Affected Sources?
Only those coal- and oil-fired Utility Units for which
construction, modification, or reconstruction is commenced after
January 30, 2004 would be affected by the proposed rule. Coal- and oil-
fired Utility Units existing at the time of this proposal would be
affected facilities for purposes of the proposed section 111(d)
guidelines described in this notice.
4. What Emission Limits Must I Meet?
The following standards of performance for Hg are being proposed in
today's notice for new coal-fired subpart Da units:
Bituminous units: 0.00075 nanograms per joule (ng/J) (0.0060 lb/
gigawatt-hour (GWh));
Subbituminous units: 0.0025 ng/J (0.020 lb/GWh);
Lignite units: 0.0078 ng/J (0.062 lb/GWh);
Waste coal units: 0.00087 ng/J (0.0011 lb/GWh);
IGCC units: 0.0025 ng/J (0.020 lb/GWh).
The following standard of performance for Ni is being proposed for
new oil-fired subpart Da units:
Ni: 0.010 (ng/J) (0.0008 lb/MWh).
All of these standards are based on gross energy output.
Compliance with the proposed standard of performance for Hg would
be on a 12-month rolling average basis, as explained in section B.5
below. This compliance period is appropriate given the nature of the
health hazard presented by Hg (see section B.5 below). Compliance with
the proposed standard of performance for Ni would be on a continuous
basis.
5. What Are the Testing and Initial Compliance Requirements?
New or reconstructed units must be in compliance with the
applicable rule requirements upon initial startup or by the effective
date of the final rule, whichever is later. The effective date is the
date on which the final rule is published in the Federal Register.
Prior to the compliance date, the owner/operator would be required
to prepare a unit-specific monitoring plan and submit the plan to the
Administrator for approval. The proposed rule would require that the
plan address certain aspects with regard to the monitoring system;
installation, performance and equipment specifications; performance
evaluations; operation and maintenance procedures; quality assurance
techniques; and recordkeeping and reporting procedures. Beginning on
the compliance date, the owner/operator would be required to comply
with the plan requirements for each monitoring system.
Mercury emission limits. Compliance with the proposed standard of
performance for Hg would be determined based on a rolling 12-month
average calculation. The Hg emissions are determined by continuously
collecting Hg emission data from each affected unit by installing and
operating a CEMS or an appropriate long-term method that can collect an
uninterrupted, continuous sample of the Hg in the flue gases emitted
from the unit. The proposed rule would allow the owner/operator to use
any CEMS that meets requirements in Performance Specification 12A (PS-
12A), ``Specifications and Test Procedures for Total Vapor-phase
Mercury Continuous Monitoring Systems in Stationary Sources.'' An
owner/operator electing to use long-term Hg monitoring would be
required to comply using the new EPA Method 324, ``Determination of
Vapor Phase Flue Gas Mercury Emissions from Stationary Sources Using
Dry Sorbent Trap Sampling.'' Performance Specification 12A and Test
Method 324 are proposed as part of this rulemaking.
For new cogeneration units, steam is also generated for process
use. The energy content of this process steam must also be considered
in determining compliance with the output-based standard. Therefore,
the owner/operator of a new cogeneration unit would be required to
calculate emission rates based on electrical output to the grid plus
half the equivalent electrical output energy in the unit's process
steam. The procedure for determining these Hg emission rates is
included in section B.4 of the proposed rule.
The owner/operator of a new coal-fired unit that burns a blend of
fuels would develop a unit-specific Hg emission limitation and the unit
Hg emission rate for the portion of the compliance period that the unit
burned the blend of fuels. The procedure for determining these emission
limitations is outlined in section B.4 of the proposed rule.
Nickel emission limits. Compliance with the applicable proposed
standard of performance for Ni would be determined by performance tests
conducted according to the requirements in 40 CFR 60.8 and 40 CFR 60.11
of the NSPS General Provisions and the requirements in the proposed
rule. The proposed rule would require EPA Method 29 in appendix A to 40
CFR part 60 to be used for the measurement of Ni emissions in the flue
gas. With Method 29, Method 1 would be used to select the sampling port
location and the number of traverse points; Method 2 would be used to
measure the volumetric flow rate; Method 3 would be used for gas
analysis; and Method 4 would be used to determine stack gas moisture.
Method 19 would be used to convert the Method 29 Ni measurements to an
emission rate expressed in units of pounds per trillion British thermal
units (lb/TBtu) if complying with an input-based standard.
The proposed rule would require the owner/operator to establish
limits for control device operating parameters based on the actual
values measured during each performance test. The proposed rule
specifies the parameters to be monitored for the types of emission
control systems commonly used in the industry. The owner/operator would
be required to submit a monitoring plan identifying the operating
parameters to be monitored for any control device used that is not
specified in the proposed rule.
An initial performance test to demonstrate compliance with each
applicable Ni emission limit would be required no later than 180 days
after initial startup or 180 days after publication of the final rule,
whichever is later, for a new or reconstructed unit.
The owner/operator of a new cogeneration unit would have to account
for the process steam portion of their emissions in the same manner for
Ni emissions as they did for Hg emissions. The owner/operator of a
cogeneration unit would be required to calculate the Ni emission rate
based on electrical output to the grid plus half the equivalent
electrical output energy in the unit's process steam. The procedure for
determining these Ni emission rates are given in Sec. 60.46a of the
proposed rule.
6. What Are the Continuous Compliance Requirements?
To demonstrate continuous compliance with the applicable emission
limits under the proposed rule, the owner/operator would be required to
perform continuous Hg emission monitoring for coal-fired units and
continuous monitoring of appropriate operating parameters for the ESP
used to comply with the Ni limits for oil-fired units. In addition, an
annual performance test will be required for demonstrating compliance
with the proposed standard of performance for Ni for oil-fired units.
The annual performance test would be conducted in
[[Page 4691]]
the same manner as the initial compliance demonstration.
7. What Are the Notification, Recordkeeping, and Reporting
Requirements?
The proposed rule would require the owner/operator to keep records
and file reports consistent with the notification, recordkeeping, and
reporting requirements of the General Provisions of 40 CFR part 60,
subpart A. Records required under the proposed rule would be kept for 5
years, with the 2 most recent years being on the facility premises.
These records would include copies of all Hg emission monitoring data,
coal usage, MWh generated, and heating value data required for
compliance calculations; reports that have to be submitted to the
responsible authority; control equipment inspection records; and
monitoring data from control devices demonstrating that emission
limitations are being maintained.
Two basic types of reports would be required: initial notifications
and periodic reports. The owner/operator would be required to submit
notifications described in the General Provisions (40 CFR part 60,
subpart A), which include initial notification of applicability,
notifications of performance tests, and notification of compliance
status. For oil-fired units, if you at any time during the reporting
period comply with an applicable emissions limit by switching fuel (in
other than emergency situations), the proposed rule would also require
that you notify EPA in writing at least 30 days prior to using a fuel
other than distillate oil. In emergency situations, such notification
must be within 30 days. As required by the General Provisions, the
owner/operator would be required to submit a report of performance test
results; develop and implement a written startup, shutdown, and
malfunction plan and report semi-annually any events in which the plan
was not followed; and submit semi-annual excess emissions reports of
any deviations when any monitored parameters fell outside the range of
values established during the performance test.
C. Rationale for the Proposed Subpart Da Standards
1. What Is the Rationale for the Proposed Subpart Da Hg and Ni
Standards?
In December 2000, EPA announced a finding that regulation of Hg
emissions from coal-fired Utility Units and Ni emissions from oil-fired
Utility Units under CAA section 112 was appropriate and necessary. As
explained above, we are proposing today to revise that finding. We
continue to believe, however, that the HAP of greatest concern from
coal-fired units is Hg, with Ni being the HAP of greatest concern from
oil-fired units. In December 2000, based on the record before the
Agency, EPA estimated that coal-fired Utility Units in the U.S. emitted
approximately 48 tons of Hg into the atmosphere in 1999, and that
methylmercury, the end product of Hg deposited to water bodies, is a
significant health hazard, particularly to sensitive subpopulations.
The EPA also found that Hg emissions could in some cases be reduced
through application of control technology. Finally, the record
supporting the December 2000 action reveals that oil-fired Utility
Units emitted approximately 322 tons of Ni in 1994.
Today's action proposes standards under the regulatory authority of
section 111(b), which will regulate Hg (from coal-fired units) and Ni
(from oil-fired units) emissions from new units on which construction
is commenced after today's date, and emissions guidelines under the
authority of section 111(d), which will regulate Hg emissions from
existing coal-fired Utility Units and Ni emissions from existing oil-
fired Utility Units.
The source of Hg and Ni emissions from these units is the same at
both new and existing steam generating units; therefore, in general,
the control of these emissions would be the same as well. Throughout
this preamble, where clear distinctions arise, the rationales for the
EPA actions affecting new and existing units are discussed separately.
Otherwise, the discussion applies to the proposed standards and
emission guidelines.
2. What Is the Performance of Control Technology on Hg?
Currently, there are no commercially available control technologies
specifically designed for reducing Hg emissions. However, available
data indicate that controls installed for reducing emissions of PM,
SO2, and NOX are also effective in some cases in
reducing Hg emissions from coal-fired Utility Units. The degree of
removal, however, depends (in part) on the rank of coal being burned.
The American Society for Testing and Materials (ASTM) classifies
coals by rank, a term which relates to the carbon content of the coal
and other related parameters such as volatile-matter content, heating
value, and agglomerating properties. The coal-fired electric utility
industry combusts the following coal ranks, presented in decreasing
order: anthracite, bituminous, subbituminous, and lignite. The HHV of
coal is measured as the gross calorific value, reported in British
thermal units per pound (Btu/lb). The heating value of coal increases
with increasing coal rank. The youngest, or lowest rank, coals are
termed lignite. Lignites have the lowest heating value of the coals
typically used in power plants. Their moisture content can be as high
as 30 percent, but their volatile content is also high; consequently,
they ignite easily. Next in rank are subbituminous coals, which also
have a relatively high moisture content, typically ranging from 15 to
30 percent. Subbituminous coals also are high in volatile matter
content and ignite easily. Their heating value is generally in between
that of the lignites and the bituminous coals. Bituminous coals are
next in rank, with higher heating values and lower moisture and
volatile content than the subbituminous and lignite coals. Anthracites
are the highest rank coals. Because of the difficulty in obtaining and
igniting anthracite, only a single electric utility boiler in the U.S.
burned anthracite as its only fuel in 1999. Because bituminous coal is
the most similar coal to anthracite coal based on coal physical
characteristics (ash content, sulfur content, HHV), anthracite coal is
considered to be equivalent to bituminous coal for the purposes of the
proposed rule and, thus, the anthracite-fired unit is considered a
bituminous-fired unit for the purposes of the proposed rule.
Although there is overlap in some of the ASTM classification
properties, the ASTM method of classifying coals by rank generally is
successful in identifying some common core characteristics that have
implications for power plant design and operation.
Coal refuse (i.e., anthracite coal refuse (culm), bituminous coal
refuse (gob), and subbituminous coal refuse) is also combusted in
utility units. Coal refuse refers to the waste products of coal mining,
physical coal cleaning, and coal preparation operations (e.g. culm,
gob, etc.) containing coal, matrix material, clay, and other organic
and inorganic material. Previously considered unusable by the industry
because of the high ash content and relatively low heat content, it now
may be utilized as a supplemental fuel in limited amounts in some units
or as the primary fuel in a fluidized bed combustor (FBC). Because of
the inherent inability to utilize coal refuse as the primary fuel in
anything other than an FBC, it is considered to be a separate coal rank
for purposes of the proposed rule.
[[Page 4692]]
The rank of coal to be burned has an enormous impact on overall
plant design. The goal of the plant designer is to arrange boiler
components (furnace, superheater, reheater, boiler bank, economizer,
and air heater) to provide the rated steam flow, maximize thermal
efficiency, and minimize cost. Engineering calculations are used to
determine the optimum positioning and sizing of these components, which
cool the flue gas and generate the superheated steam. The accuracy of
the parameters specified by the owner/operators is critical to
designing and building an optimal plant. The rank of coal to be burned
greatly impacts the entire design process. The rank of coal burned also
has significant impact on the design and operation of the emission
control equipment (e.g., ash resistivity impact on ESP performance).
For the above reasons, one of the most important factors in modern
electric utility boiler design involves the differences in the ranks
and range of coals to be fired and their impact on the details and
overall arrangement of boiler components. Coal rank is so important
that plant designers and manufacturers expect to be provided with a
complete list of all coal ranks presently available or planned for
future use, along with their complete chemical and ash analyses, so
that the engineers can properly design and specify plant equipment. The
various coal characteristics (e.g., how hard the coal is to pulverize;
how high its ash content; the chemical content of the ash; how the ash
``slags'' (fused deposits or resolidified molten material that forms
primarily on furnace walls or other surfaces exposed predominantly to
radiant heat or high temperature); how big the boiler has to be to
adequately utilize the heat content; etc.), therefore, impact on boiler
design from the pulverizer through the boiler to the final steam tubes.
For a boiler to operate efficiently, it is critical to recognize the
differences in coals and make the necessary modifications in boiler
components during design to provide optimum conditions for efficient
combustion.
Coal-fired units are designed and constructed with different
process configurations partially because of the constraints, including
the properties of the fuel to be used, placed on the initial design of
the unit. Accordingly, these site-specific constraints dictate the
process equipment selected, the component order, the materials of
construction, and the operating conditions.
Approximately 23 percent of coal-fired Utility Units either (1) co-
fire two or more ranks of coal (with or without other fuels) in the
same boiler, or (2) fire two or more ranks of coal (with or without
other fuels) in the same boiler at different times (1999 EPA ICR). This
coal ``blending'' is done generally for one of three reasons: (1) To
achieve SO2 emission compliance with title IV provisions of
the CAA, (2) to prevent excessive slagging by improving the heat
content of a lower grade coal, or (3) for economic reasons (i.e., coal
rank price and availability).
These blended coals, although of different rank, do have similar
properties. That is, because of the overlap in various characteristics
in the ASTM definitions of coal rank, certain bituminous and
subbituminous coals (for example) exhibit similar handling and
combustion properties. Plant designers and operators have learned to
accommodate these blends in certain circumstances without significant
impact on plant operation or control.
The flue gases resulting from the combustion of these different
coal ranks can exhibit different Hg emissions characteristics. These Hg
emissions characteristics consist of varying percentages of the three
relevant forms (or species) of Hg (particulate-bound, oxidized (ionic),
and elemental) that makeup the total Hg in the flue gas.
Available source test data shows that combustion of bituminous coal
results in Hg emissions that are composed of relatively more Hg\++\
compared to the other coal ranks. Combustion of bituminous coal
produces the most particulate-bound Hg of any of the three major coal
ranks combusted. Combustion of subbituminous coal results in emissions
that are composed of relatively more elemental Hg (compared to
bituminous coal), with little particulate-bound Hg (less than half that
of bituminous coal emissions). Combustion of lignite coal also results
in emissions that are composed of relatively more elemental Hg
(compared to bituminous coal) with little particulate-bound Hg (also
less than half that of bituminous coal emissions). Available data
indicate that emissions from the combustion of coal refuse tends to
result almost entirely in particulate-bound Hg (greater than 99 percent
for both units tested in the 1999 EPA ICR). With few exceptions,
particulate-bound Hg can be removed with PM controls, Hg\++\ can be
removed with wet SO2 controls (FGD scrubbers), but elemental
Hg usually shows little to no removal with any existing conventional
type of APCD used on utility boilers. However, new technologies such as
activated carbon adsorption show promise in removing elemental Hg.
There are five basic types of coal combustion processes used in the
coal-fired electric utility industry. These are conventional-fired
boilers, stoker-fired boilers, cyclone-fired boilers, integrated
gasification combined cycle (IGCC) units, and fluidized bed combustors
(FBC).
Conventional boilers, also known as pulverized coal (PC) boilers,
have a number of firing configurations based on their burner placement.
The basic characteristic that all conventional boilers have in common
is that they inject PC and primary air through a burner where ignition
of the PC occurs, which in turn creates an individual flame.
Conventional boilers fire through many such burners mounted in the
furnace walls.
In stoker-fired boilers, fuel is deposited on a moving or
stationary grate or spread mechanically or pneumatically from points
usually 10 to 20 feet above the grate. The process utilizes both the
combustion of fine coal powder in air and the combustion of larger
particles that fall and burn in the fuel bed on the grate.
Cyclone-fired boilers use several water-cooled horizontal burners
that produce high-temperature flames that circulate in a cyclonic
pattern. The burner design and placement cause the coal ash to become a
molten slag that is collected below the furnace.
Fluidized bed combustors combust coal, in a bed of inert material
(e.g., sand, silica, alumina, or ash) and/or a sorbent such as
limestone, that is suspended through the action of primary combustion
air distributed below the combustor floor. ``Fluidized'' refers to the
state of the bed of material (coal and inert material (or sorbent)) as
gas passes through the bed. As the gas flow rate is increased, the
force on the fuel particles becomes just sufficient to cause buoyancy.
The gas cushion between the solids allows the particles to move freely,
giving the bed a liquid-like (or fluidized) characteristic.
Integrated-coal gasification combined cycle units are specialized
units in which coal is first converted into synthetic coal gas. In this
conversion process, the carbon in the coal reacts with water to produce
hydrogen gas and CO. The synthetic coal gas is then combusted in a
combustion turbine which drives an electric generator. Hot gases from
the combustion turbine then pass through a waste heat boiler to produce
steam. This steam is fed to a steam turbine connected to a second
electric generator.
[[Page 4693]]
Available information indicates that Hg emissions from coal-fired
Utility Units are minimized in some cases through the use of PM
controls coupled with an FGD system. For bituminous-fired units, use of
a selective catalytic reduction (SCR) or selective noncatalytic
reduction (SNCR) system may further enhance Hg removal. This does not
appear to be the case for subbituminous- and lignite-fired units. The
EPA believes the best potential way of reducing Hg emissions from IGCC
units is to remove Hg from the syngas before combustion. An existing
industrial IGCC unit has demonstrated a process, using sulfur-
impregnated AC carbon beds, that has proven to yield 90 to 95 percent
Hg removal from the coal syngas. This technology could potentially be
adapted to the electric utility IGCC units. The EPA believes this to be
a viable option for IGCC units.
3. What Is the Performance of Control Technology on Ni?
The EPA analyzed the data available on the fuel, process, emission
profiles, and APCD for oil-fired units at existing affected sources. An
oil-fired electric utility boiler combusts fuel oil exclusively, or
combusts fuel oil at certain times of the year and natural gas at other
times (not simultaneously). The choice of when to combust oil
exclusively or to alternate between oil and natural gas at a single
boiler is usually based on economics or fuel availability (including
seasonal availability). The ASTM classifies oils by ``grade,'' a term
which relates to the amount of refinement that the oil undergoes. The
level of refinement directly affects the Ni and carbon content of the
oil and other related parameters such as sulfur content, heating value,
and specific gravity. The most refined fuel oil used by the oil-fired
electric utility industry is known as No. 2 fuel oil (also known as
distillate oil or medium domestic fuel oil). The least refined fuel oil
used by the oil-fired electric utility industry is known as No. 6 fuel
oil (also known as residual oil or Bunker C oil). By comparison, No. 2
fuel oil is lower in Ni, sulfur, ash content, and heating value but
higher in carbon content than No. 6 fuel oil. Only a handful of boilers
(8 of 218) fire No. 2 distillate fuel oil exclusively. (2001 EIA data)
However, 28 out of 218 boilers fire No. 2 distillate fuel oil and No. 6
(residual) fuel oil in the same boiler (either simultaneously or at
separate times).
The proposed standard of performance for Ni from new oil-fired
units was determined by analyzing the emissions data available. The
data were obtained from the Utility RTC which provided information
indicating that Ni was the pollutant of concern due to its high level
of emissions from oil-fired units and the potential health effects
resulting from exposure to it. The EPA examined available test data and
found that ESP-equipped units can effectively reduce Ni. The proposed
standard of performance for Ni is based on the level of control
demonstrated by the top performing existing units with regard to
removal of Ni. The test data were converted to an output-based limit
using an efficiency factor.
The EPA is sensitive to the fact that some sources burn fuels
containing very little Ni. Therefore, EPA solicits comment on a Ni-in-
oil limit that would be equivalent to the proposed stack value of
0.0005 lb/MWh gross. With a limit on the amount of Ni in the oil, a new
source could choose to comply with an alternate oil-content-based Ni
emission limitation instead of the stack Ni emission limit to meet the
proposed rule. Such an alternate Ni-in-oil limit could be useful where
Ni constituent levels are low in the fuel.
Dual-Fired (Oil/Natural Gas) Units. The EPA is aware that an oil-
fired unit may fire oil at certain times of the year and natural gas at
other times. The choice of when to fire oil or natural gas is usually
based on the economics or availability of fuel (i.e., seasonal
considerations). The EPA considers a unit to be an oil-fired unit if
(1) it is equipped to fire oil and/or natural gas, and (2) it fires oil
in amounts greater than or equal to 2 percent of its annual fuel
consumption. This 2 percent value is intended to represent that amount
of oil that a true natural gas-fired unit might use strictly for start-
up purposes on an annual basis. The EPA solicits comment on whether
this two percent breakpoint is a reasonable basis for allowing those
units that use oil only for startup purposes to be exempted from
regulation under the proposed rule.
4. What Is the Regulatory Approach?
Subpart Da Hg emission standards. In selecting a regulatory
approach for formulating emission standards to limit Hg emissions from
new coal-fired steam generating units, the performance of the Hg
control technologies discussed above were considered. The technical
basis (i.e., BDT) selected for establishing Hg emission limits for new
sources is the use of effective PM controls and wet or dry FGD systems
on subbituminous-, lignite-, and waste coal-fired units and effective
PM controls, wet or dry FGD systems, and SCR or SNCR on bituminous-
fired units, and activated carbon beds for IGCC units.
Section 111(b)(2) of the CAA allows the Administrator to ``* * *
distinguish among classes, types, and sizes within categories of new
sources * * *'' in establishing standards when differences between
given types of sources within a category lead to corresponding
differences in the nature of emissions and the technical feasibility of
applying emission control techniques. After examining a number of
possible subcategorization options, EPA identified two basic ways to
subcategorize coal-fired Utility Units, by coal rank or by process
type.
Subcategorization by coal rank. Subcategorization by individual
coal rank addresses the differences in the characteristics of the Hg
emissions (i.e., speciation of Hg) and the resulting ability to control
Hg as well as accommodating the various design and control constraints
resulting from the various coal ranks.
Subcategorization by process type. Another option is to
subcategorize by process type. Different process types could create
potential emissions differences which lead to corresponding differences
in the nature of emissions and the technical feasibility of applying
emission control techniques. Although conventional-, stoker-, and
cyclone-fired boilers use different firing techniques, the Hg emissions
characteristics of these boilers are similar (given that common ranks
of coal are fired) and, therefore, the units can be grouped together.
Although these units fire a variety of coal ranks they have only
combusted coal refuse in lesser amounts as a secondary fuel source.
Based on their unique firing designs, FBC units employ a
fundamentally different process for combusting coal from that employed
by conventional-, stoker-, or cyclone-fired boilers. Fluidized-bed
combustors are capable of combusting many coal ranks including coal
refuse. For these reasons, FBC units can be considered a distinct type
of boiler. However, the Hg emissions test data results for FBC units
were not substantially different from those at similarly-fueled
conventionally-fired units with similar emission levels, either in mass
of emissions or in emissions characteristics.
Integrated gasification combined cycle units combust a synthetic
coal gas. No coal is directly combusted in the unit during operation
(although a coal-derived fuel is fired), and, thus, IGCC units are a
distinct class or type of boiler for the proposed rule.
Based on the above discussion, the EPA is proposing to use five
subcategories for establishing Hg limits based on a combination of coal
rank and
[[Page 4694]]
process type in this rule (bituminous coal, subbituminous coal, lignite
coal, coal refuse, and IGCC).
The EPA's review of the available emission data shows that Hg
emissions from new coal-fired units can be reduced to the following:
Bituminous units: 0.61 lb/TBtu heat input;
Subbituminous units: 2.0 lb/TBtu heat input;
Lignite units: 6.3 lb/TBtu heat input;
Waste coal units: 0.11 lb/TBtu heat input;
IGCC units: 2.0 lb/TBtu heat input.
Mercury emissions from new oil- and gas-fired units are not covered
by the proposed rule.
Subpart Da Ni emission standards. In selecting a regulatory
approach for formulating emission standards to limit Ni emissions from
new oil-fired steam generating units, the performance on Ni of the PM
control technologies discussed above were considered. The technical
basis (i.e., BDT) selected for establishing Ni emission limits for new
sources is the use of ESP units or oils low in Ni content.
The EPA's review of the available emission data shows that Ni
emissions from new oil-fired units can be reduced to 84 lb/TBtu heat
input.
5. What Are the Subpart Da Hg and Ni Emission Standards?
Based on available performance data analyses from the 1999 ICR for
coal-fired Utility Units, the Administrator has concluded that the
application of fabric filters or ESP units along with wet or dry FGD is
considered to be the most effective Hg control technology for units
firing subbituminous, lignite, or waste coals; and that the application
of fabric filters or ESP units, wet or dry FGD systems, and SCR is
considered to be the most effective Hg control technology for units
firing bituminous coals. For IGCC units (regardless of coal rank
fired), the Administrator has concluded that use of a carbon bed is
considered to be the most effective Hg control technology. These
controls represent the best system of emissions reductions (taking into
consideration the cost of achieving such emissions reductions, any non-
air quality health and environmental impact, and energy requirements).
Based on available performance data and cost analyses, the
Administrator has concluded that the application of ESP units or oils
containing a low Ni content is considered to be the most effective Ni
control technology for oil-fired units. These controls represent the
best system of emissions reductions (taking into consideration the cost
of achieving such emissions reductions, any non-air quality health and
environmental impact, and energy requirements).
6. How Did EPA Select the Format for the Proposed Standards?
Based on the analyses and discussion presented earlier, EPA has
selected an output-based format for the proposed new-source rule. The
Administrator is proposing today Hg emission limits for new coal-fired
Utility Units as follows:
Bituminous units: 0.0060 GWh gross;
Subbituminous units: 0.020 lb/GWh gross;
Lignite units: 0.062 lb/GWh gross;
Waste coal units: 0.0011 lb/GWh gross;
IGCC units: 0.020 lb/GWh gross.
Based on the available performance data, cost analysis, and the
above calculation, the Administrator is proposing today Ni emission
limits for new oil-fired Utility Units as follows: 0.0008 lb/MWh gross.
7. How Did EPA Determine Testing and Monitoring Requirements for the
Proposed Standards?
The CAA requires EPA to develop regulations that ensure initial and
continuous compliance. Testing and monitoring requirements allow EPA to
determine whether an affected source is operating in compliance with an
applicable emission limitation/standard. This section discusses how EPA
selected the proposed testing and monitoring requirements used to
determine compliance with the Hg and Ni emission limits that are
specified in the proposed rule.
Mercury testing and monitoring requirements. The proposed rule
would establish Hg emission limits for coal-fired units. The format
selected for these Hg emission limits is a 12-month rolling average Hg
emission level expressed in units of lb/TBtu or lb/MWh. Therefore,
appropriate testing or monitoring requirements for determining the
amount of Hg emitted from an affected unit throughout the compliance
averaging period must be included in the rule.
The most direct means of demonstrating compliance with an emission
limit is by the use of a CEMS that measures the pollutant of concern.
The EPA considers other testing or monitoring options when acceptable
CEMS are not available for the intended application or when the impacts
of including such CEMS requirements in the proposed rule are considered
by EPA to be unreasonable. In determining whether to require the use of
other testing or monitoring options in lieu of CEMS, it is often
necessary for EPA to balance more reasonable costs against the quality
or accuracy of the actual emissions data collected.
There are several approaches to Hg monitoring that EPA has
identified for possible use in this rule to determine compliance with
the proposed Hg emission limits. One option is to use a CEMS that
combines both automated sampling and analytical functions in a single
system to provide continuous, real-time Hg emission data. Mercury CEMS
are currently available from several manufacturers. These Hg CEMS are
similar to most other types of instruments used for continuous
monitoring of pollutants from combustion processes, in that the
combustion gas sample is first extracted from the stack and then
transferred to an analyzer for analysis. In general, the Hg CEMS now
available can be distinguished by the Hg measurement detection
principle used (e.g., atomic adsorption, atomic fluorescence, x-ray
fluorescence). Capital costs for a Hg CEMS are currently estimated to
range from approximately $95,000 to $135,000, depending on the
manufacturer and model selected. The annual costs to operate and
maintain a Hg CEMS are estimated to range from $45,000 to $65,000,
again depending on the manufacturer and model selected.
A second option is to use a long-term sampling method that collects
a cumulative Hg sample by continuously passing a low-flow sample stream
of the combustion process flue gas through a Hg trapping medium (e.g.,
an activated carbon tube). This sampling tube is then periodically
removed (e.g., after a day or up to 1 month) and replaced with a tube
filled with fresh trapping medium. The removed sampling tube is then
sent to a laboratory where the trapping medium is analyzed for its Hg
content. This method, like using a Hg CEMS, is capable of providing
data on the Hg emissions from a combustion process on a continuous
basis, but unlike a Hg CEMS, the data are not reported on a real-time
basis. Using the long-term sampling method, the Hg collected in the
sampling tube is integrated over a much longer sampling period (i.e., 1
to 7 days for the AC tube versus less than 15 minutes for the CEMS).
The capital cost for a gas metering system and Hg trapping medium is
estimated to be approximately $18,000. The annual costs for periodic
sampling tube replacement and for the laboratory Hg analysis range from
approximately $65,000 to $125,000 depending upon quality assurance and
quality control (QA/QC) requirements and frequency of sample tube
replacement.
[[Page 4695]]
Finally, a third monitoring option is to use one of the manual
stack test methods available for measuring Hg emissions from combustion
processes on an intermittent basis. The existing voluntary consensus
stack test method ASTM Method D6784-02 (commonly known as the Ontario-
Hydro method) is currently the method of choice for measuring Hg
species in the flue gas from Utility Units. Another method for
measuring total (i.e., not speciated) Hg is EPA Reference Method 29.
This method involves a technician extracting a representative flue gas
sample over a relatively short period of time (e.g., a few hours) using
a sampling train consisting of a nozzle and probe, a filter to collect
particulate matter, and a liquid solution and/or reagent to capture
gas-phase Hg. After sampling, the filter and sorption media are
prepared and analyzed for Hg in a laboratory. These test methods could
be applied to a Hg monitoring program at electric utility plants by
performing a manual stack test using ASTM Method D6784-02 or EPA
Reference Method 29 at some specified periodic interval throughout the
compliance averaging period (e.g., perform a stack test daily, weekly,
biweekly, monthly). The cost to conduct a single ASTM Method D6784-02
typically ranges from $15,000 to $17,000 depending on site conditions.
Annual costs will depend on the frequency with which the stack test is
required to be performed during the compliance averaging period. For
example, if the test is required once per week, the total annual cost
would be as much as $780,000 (52 tests in a 12-month period at $15,000
per test).
The EPA evaluated each of the above Hg monitoring options with
respect to its suitability for the measurement of the Hg emission data
needed for determining compliance with the 12-month rolling average Hg
emission limit. The EPA rejected from further consideration the third
option, intermittent monitoring using manual stack test methods. Use of
this monitoring approach would place significantly higher labor
requirements and monitoring costs on facility owners/operators than the
other two options in order to perform an adequate number of source
tests throughout the compliance averaging period to demonstrate with
reasonable confidence that the applicable Hg emission limit value was
being achieved.
Both of the remaining two options would provide the necessary data
to calculate the total Hg emissions from an affected source for each
12-month compliance averaging period. While the CEMS would provide
these data on a real-time basis, EPA concluded that having real-time
data is not mandatory for determining compliance with an emission limit
based on a 12-month rolling average. Total Hg emissions from an
affected source by month are needed to compute the rolling 12-month
average Hg emission value. With regular scheduled replacement and
timely analysis of sampling tubes, total monthly Hg emissions can
readily be obtained using the long-term sampling method.
The EPA then compared the costs of applying the Hg CEMS and long-
term monitoring options to Utility Units. While the CEMS have
significantly higher capital costs, the automated analyses directly by
the instrument eliminates the need and cost for separate analyses of
the collected sampling tubes in a laboratory required by the long-term
sampling method. Overall, EPA determined that the total costs of using
either monitoring method to determine compliance would be similar for a
given site. Selection of which monitoring method should be used at the
site will depend on site-specific conditions and owner/operator
preferences. Because both monitoring methods will collect the Hg
emission data necessary to determine compliance with the proposed Hg
emission limit and the costs of either option are reasonable, EPA
decided to allow the owner/operator flexibility under the proposed rule
to choose to use either Hg CEMS or long-term sampling monitoring as
best suits their site conditions and preferences.
An owner/operator electing to use a CEMS to comply with the rule
would be allowed to use any CEMS that meets the requirements in
``Performance Specification 12A, Specifications and Test Procedures for
Total Vapor-phase Mercury Continuous Monitoring Systems in Stationary
Sources'' (PS-12A). This performance specification is proposed as part
of this rulemaking and we request comment on continuous monitoring of
Hg emissions according to the requirements in the proposed performance
specification.
Those owners/operators electing to use long-term Hg monitoring
would be required to follow the requirements in Method 324,
``Determination of Vapor Phase Flue Gas Mercury Emissions from
Stationary Sources Using Dry Sorbent Trap Sampling'' when it is
promulgated. Method 324 is proposed as part of this rulemaking to be
added to 40 CFR part 60, appendix A. We request comments on the
requirements in proposed Method 324 for Hg measurement using long-term
sampling.
Continuous compliance requirements are required under every NSPS so
that EPA can determine whether an affected source remains in compliance
with the applicable emission limitation/standard following the initial
compliance determination. In the case of the proposed NSPS, the format
for the Hg emission limit is a 12-month rolling average limit. The same
monitoring requirements used to establish initial compliance of an
affected electric utility unit with the applicable Hg emission limit at
the end of the first 12-month period following the facility's
compliance date serve to demonstrate continuous compliance with the Hg
emission limit with the computation of each new 12-month rolling
average value each month thereafter. Thus, no additional continuous
compliance Hg monitoring requirements beyond those previously discussed
are required for the proposed rule.
The EPA is concerned about monitoring costs for units with low Hg
emissions rates, and does not desire to adopt a monitoring scheme where
the costs are disproportionate to the costs of compliance with the MACT
emissions limitations. For these units (e.g., those emitting under 25
pounds per year) the EPA may consider reduced monitoring frequencies
and lower cost monitoring requirements, since the need for accuracy is
reduced for such units. For example, the EPA is concerned about the
merits of requiring an expenditure of $100,000 per year to monitor
releases when the costs of substantive compliance is far less. The
Agency requests comments and related data upon which to establish an
alternate reporting scheme.
Nickel testing and monitoring requirements. The proposed rule would
establish Ni emission limits for oil-fired units. The EPA selected a
different format for the Ni emission limits than is proposed for the Hg
emission limits. The Ni emission limits are maximum allowable emission
limits not to be exceeded, expressed in lb/TBtu or lb/MWh.
The EPA selected the proposed testing requirements to determine
compliance with the Ni emission limits to be consistent with existing
procedures used for the electric utility industry. Method 29 in
appendix A to 40 CFR part 60 is an EPA reference test method that has
been developed and validated for the measurement of Ni emissions from
stationary sources. For sampling and analysis of the gas stream, the
following EPA reference methods would be used with Method 29: Method 1
to select the sampling port location and the number of traverse points;
Method
[[Page 4696]]
2 to measure the volumetric flow rate; Method 3 for gas analysis; and
Method 4 to determine stack gas moisture. Method 19 specifies the
procedure for collecting the necessary fuel data to be used with the
Method 29 Ni measurements from the source test to compute the Ni
emission rate expressed in units of lb/TBtu.
As an alternative under the proposed rule, an owner/operator of an
existing oil-fired source could choose to comply with the applicable Ni
emission limit expressed in lb/MWh.
To address the need for continuous compliance requirements for the
proposed Ni emission limits, EPA considered the availability and
feasibility of a number of Ni monitoring options ranging from direct
monitoring of Ni emissions, to process parameter monitoring, to control
device parameter monitoring. Monitors for continuously measuring Ni
emissions have not been demonstrated in the U.S. for the purpose of
determining compliance. Therefore, EPA did not consider further the use
of any continuous monitoring for Ni for the proposed rule.
Another option used in other NSPS for demonstrating continuous
compliance is to monitor appropriate process and/or control equipment
operating parameters. These parameters are established during the
initial, and any subsequent, stack test. Process parameters were not
selected as indicators for Ni emissions from Utility Units because a
direct correlation does not exist between combustion or electricity
production parameters and Ni emission rates from a given unit.
Monitoring of PM control device operating parameters is used in
other NSPS established for combustion processes and other source
categories that include PM emission limits. The EPA decided to also use
this continuous monitoring approach to demonstrate continuous
compliance with the applicable Ni emission limits set forth in the
proposed rule. The selected operating parameters for the PM control
device used by oil-fired Utility Units (e.g., ESP) are reliable
indicators of control device performance. The EPA believes that
reasonable assurance of compliance with the emission limits proposed
for this NSPS can be achieved through appropriate monitoring and
inspection of the operation of the APCD that have been demonstrated by
an initial performance test to achieve the applicable Ni emission
limits under the rule.
Compliance calculations. For cogeneration units, steam is also
generated for process use. The energy content of this process steam
must also be considered in determining compliance with the output-based
standard. This consideration is accomplished by taking the net
efficiency of a cogeneration unit into account. Under a Federal Energy
Regulatory Commission (FERC) regulation, the efficiency of cogeneration
units is determined from ``* * * the useful power output plus one half
the useful thermal output * * *,'' (18 CFR part 292, 205). To determine
the process steam energy contribution to net plant output, a 50 percent
credit of the process steam heat is necessary.
Therefore, owners/operators of cogeneration units subject to the
proposed rule would need to monitor the portion of their net plant
output that is process steam so that they can take the 50 percent
credit of the energy portion of their process steam net output. For
example, a cogeneration unit subject to the rule measures its net
electrical output over a compliance period, as 30,000 MWh. During the
same period the unit burns coal that provides 750 billion Btu input to
its furnace/boiler, and emits 0.2 lb Hg. Using equivalents found in 40
CFR part 60 for electric utilities (i.e., 250 million Btu/hr input to a
boiler is equivalent to 73 MWe input to the boiler; 73 MWe input to the
boiler is equivalent to 25 MWe output from the boiler; therefore, 250
million Btu input to the boiler is equivalent to 25 MWe output from the
boiler) the 50 percent credit could be found as follows. The net output
calculation would be 750 billion Btu x (25 MWe output/250 million Btu/
hr input) = 75,000 MWh equivalent electrical output from the boiler
over the compliance period. Of this amount, 30,000 MWh was produced as
electricity sent to the grid, leaving 45,000 MWh as the energy
converted to steam for process use. Half of this amount is 22,500 MWh.
The unit's Hg CEM records a total of 0.2 lb Hg over the same compliance
period. The adjusted Hg emission rate is then: 0.2 lb Hg/(30,000 MWh +
22,500 MWh) = 3.8 x 10-6 lb Hg/MWh. Cogeneration units would
have to account for the process steam portion of their emissions in the
same manner for PM emissions as well.
8. How Did EPA Determine the Compliance Times for the Proposed
Standards?
New sources are required to be in compliance either upon start up
or the effective date of this rule, whichever is later.
9. How Did EPA Determine the Required Records and Reports for the
Proposed Standards?
Under section 114(a) of the CAA, EPA may require owners/operators
of affected sources subject to a NSPS to maintain records as well as
prepare and submit notifications and reports to the EPA. In addition,
section 504(a) of the CAA mandates that sources required to obtain a
title V permit submit a report setting forth the results of any
required monitoring no less often than every 6 months. The general
recordkeeping, notification, and reporting requirements for all NSPS
are specified in 40 CFR 60.7 and 40 CFR 60.19 of the General
Provisions, if incorporated into the proposed rule. The recordkeeping,
notification, and reporting requirements for the proposed rule were
selected to include all of the applicable records, notifications, and
reports specified by the General Provisions requirements. Additional
requirements were included in the proposed rule that are necessary to
ensure that a given affected source is complying with the emission
limits from the correct subcategory.
The proposed rule would also require that the owner/operator keep
monthly records for each affected source listing the type of fuel
burned, the total fuel usage, and the fuel heating value. Additional
recordkeeping would be required for those owners/operators electing to
comply with a fuel blending emission limit. The owner/operator would be
required to maintain records of all compliance calculations and
supporting information.
D. Rationale for the Proposed Hg Emission Guidelines
1. What Is the Authority for Cap-and-Trade Under Section 111(d)?
Section 111(d)(1) authorizes EPA to promulgate regulations that
establish a State Implementation Plan-like (SIP-like) procedure under
which each State submits to EPA a plan that, under subparagraph (A),
``establishes standards of performance for any existing source'' for
certain air pollutants, and which, under subparagraph (B), ``provides
for the implementation and enforcement of such standards of
performance.'' Paragraph (1) continues, ``Regulations of the
Administrator under this paragraph shall permit the State in applying a
standard of performance to any particular source under a plan submitted
under this paragraph to take into consideration, among other factors,
the remaining useful life of the existing source to which such standard
applies.'' Section 111(a) defines, ``(f)or purposes
[[Page 4697]]
of * * * section (111),'' the term ``standard of performance'' to mean
a standard for emissions of air pollutants which reflects the degree
of emission limitation achievable through the application of the
best system of emission reduction which (taking into account the
cost of achieving such reduction and any non-air quality health and
environmental impact and energy requirements) the Administrator
determines has been adequately demonstrated.
Taken together, these provisions authorize EPA to promulgate a
``standard of performance'' that States must, through a SIP-like
system, apply to existing sources. A ``standard of performance'' is
defined as a rule that limits emissions to the degree achievable
through ``the best system of emission reduction'' that EPA ``determines
has been adequately demonstrated,'' considering costs and other
factors.
A cap-and-trade program reduces the overall amount of emissions by
requiring sources to hold allowances to cover their emissions on a one-
for-one basis; by limiting overall allowances so that they cannot
exceed specified levels (the ``cap''); and by reducing the cap to less
than the amount of emissions actually emitted, or allowed to be
emitted, at the start of the program. In addition, the cap may be
reduced further over time. Authorizing the allowances to be traded
maximizes the cost-effectiveness of the emissions reductions in
accordance with market forces. Sources have an incentive to endeavor to
reduce their emissions below the number of allowances they receive; if
they can do so cost-effectively, they may then sell their excess
allowances on the open market. On the other hand, sources have an
incentive to not put on controls that cost more than the allowances
they may buy on the open market.
The term ``standard of performance'' is not explicitly defined to
include or exclude an emissions cap and allowance trading program. In
today's action, EPA proposes to interpret the term ``standard of
performance,'' as applied to existing sources, to include a cap-and-
trade program. This interpretation is supported by a careful reading of
the section 111(a) definition of the term, quoted above: A requirement
for a cap-and-trade program (i) constitutes a ``standard for emissions
of air pollutants'' (i.e., a rule for air emissions), (ii) ``which
reflects the degree of emission limitation achievable'' (i.e., which
requires an amount of emissions reductions that can be achieved), (iii)
``through application of (a) * * * system of emission reduction''
(i.e., in this case, a cap-and-trade program that caps allowances at a
level lower than current emissions).\12\
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\12\ The legislative history of the term, ``standard of
performance,'' does not address an allowance/trading system, but
does indicate that Congress intended that existing sources be
accorded flexibility in meeting the standards. See ``Clean Air Act
Amendments of 1977,'' Committee on Interstate and Foreign Commerce,
H.R. Rep. No. 95-294 at 195, reprinted in 4 ``A Legislative History
of the Clean Air Act Amendments of 1977,'' Congressional Research
Service, 2662. The EPA interprets this legislative history as
generally supportive of interpreting ``standard of performance'' to
include an allowance/trading program because such a program accords
flexibility to sources.
---------------------------------------------------------------------------
Nor do any other provisions of section 111(d) indicate that the
term ``standard of performance'' may not be defined to include a cap-
and-trade program. Section 111(d)(1)(B) refers to the ``implementation
and enforcement of such standards of performance,'' and section
111(d)(1) refers to the State ``in applying a standard of performance
to any particular source,'' but all of these references readily
accommodate a cap-and-trade program.
Although section 111(a) defines ``standard of performance'' for
purposes of section 111, section 302(l) defines the same term, ``(w)hen
used in this Act,'' to mean ``a requirement of continuous emission
reduction, including any requirement relating to the operation or
maintenance of a source to assure continuous emission reduction.'' The
term ``continuous'' is not defined in the CAA.
Even if the 302(l) definition applied to the term ``standard of
performance'' as used in section 111(d)(1), EPA believes that a cap-
and-trade program meets the definition. A cap-and-trade program with an
overall cap set below current emissions is a ``requirement of * * *
emission reduction.'' Moreover, it is a requirement of ``continuous''
emissions reductions because all of a source's emissions must be
covered by allowances sufficient to cover those emissions. That is,
there is never a time when sources may emit without needing allowances
to cover those emissions.\13\
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\13\ This interpretation of the term ``continuous'' is
consistent with the legislative history of that term. See H.R. Rep.
No. 95-294 at 92, reprinted in 4 Congressional Research Service, A
Legislative History of the Clean Air Act Amendments of 1977, 2559.
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We note that EPA has on one prior occasion authorized emissions
trading under section 111(d). (The Emission Guidelines and Compliance
Times for Large Municipal Waste Combustors that are Constructed on or
Before September 20, 1994; 40 CFR part 60, subpart Cb.) This provision
allows for a NOX trading program implemented by individual
States. Section 60.33b(C)(2) states,
A State plan may establish a program to allow owners or
operators of municipal waste combustor plants to engage in trading
of nitrogen oxides emission credits. A trading program must be
approved by the Administrator before implementation.
Today's proposal is wholly consistent with this prior section
111(d) trading provision.
Having interpreted the term ``standard of performance'' to include
a cap-and-trade program, EPA must next ``determine'' that such a system
is ``the best system of emissions reductions which (taking into account
the cost of achieving such reduction and any non-air quality health and
environmental impact and energy requirements) * * * has been adequately
demonstrated.'' Section 111(a)(1). The EPA proposes to determine that a
cap-and-trade program has been adequately determined to be the best
system for reducing Hg emissions from coal-fired Utility Units.
Since the passage of the 1990 Amendments to the CAA, EPA has had
significant experience with the cap-and-trade program for utilities.
The 1990 Amendments provided, in title IV, for the acid rain program, a
national cap-and-trade program that covers SO2 emissions
from utilities. title IV requires sources to hold allowances for each
ton of emissions, on a one-for-one basis. The EPA allocates the
allowances for annual periods, in amounts initially determined by the
statute, and that decrease further at a statutorily specified time.
This program has resulted in an annual reduction in SO2
emissions from utilities from 15.9 million tons in 1990 (the year the
Amendments were enacted) to 10.2 million tons in 2002 (the most recent
year for which data is available). Emissions in 2002 were 9 percent
lower than 2000 levels and 41 percent lower than 1980, despite a
significant increase in electrical generation. As discussed elsewhere,
at full implementation after 2010, emissions will be limited to 8.95
million tons, a 50 percent reduction from 1980 levels. The Acid Rain
program allowed sources to trade allowances, thereby maximizing overall
cost-effectiveness.
In addition, in the 1998 NOX SIP Call rulemaking, EPA
promulgated a NOX reduction requirement that affects 21
States and the District of Columbia (``Finding of Significant
Contribution and Rulemaking for Certain States in the Ozone Transport
Assessment Group Region for Purposes of Reducing Regional Transport of
Ozone; Rule,'' 63 FR 57,356 (October 27, 1998)). All of the affected
jurisdictions are implementing the requirements through a cap-and-trade
program for NOX emissions
[[Page 4698]]
primarily from utilities.\14\ These programs are contained in SIP that
EPA has approved; and EPA is administering the trading programs.
However, for most States, the requirements do not need to be
implemented until May, 2004.
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\14\ Non-electricity generating units (EGU) are also included in
the States' programs.
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The success of the Acid Rain cap-and-trade program for utility
SO2 emissions, which EPA duplicated in large measure with
the NOX SIP Call cap-and-trade program for, primarily,
utility NOX emissions, leads EPA to propose to conclude that
a cap-and-trade program for Hg emissions from utilities qualifies as
the ``best system of emission reductions'' that ``has been adequately
demonstrated.'' A market system that employs a fixed tonnage limitation
(or cap) for Hg sources from the power sector provides the greatest
certainty that a specific level of emissions will be attained and
maintained since a predetermined level of reductions is ensured. The
EPA will administer a Hg trading program and will require the use of
continuous emissions monitoring systems (CEMS) or an appropriate long-
term method that will allow both EPA and sources to track progress,
ensure compliance, and provide credibility to the trading component of
the program. The advantages of the Hg trading program are discussed
further below. We ask for comments on all aspects of this approach
under section 111(d).
2. What Is the Regulatory Approach for Existing and New Sources?
What Are the National Hg Budget and Source Emission Limits?
Mercury budget overview. Our primary goal in this rulemaking is to
reduce power plant emissions of Hg by 70 percent from today's levels by
2018. We are proposing to accomplish this goal by setting a 15 ton cap
on these emissions in 2018. Under our proposal, the 2018 cap would be a
permanent cap that could not be exceeded, regardless of future growth
in the energy sector. Thus, the cap would effectively become more
stringent as more and more plants are required to keep their collective
emissions below 15 tons.
We also are proposing to set a near-term cap in 2010 at a level
that reflects the maximum reduction in Hg emissions that could be
achieved through the installation of FGD and SCR units that will be
necessary to meet the 2010 caps for SO2 and NOX
in our proposed IAQR. Although we know that FGD and SCR units reduce Hg
emissions (as well as SO2 and NOX), there is
significant uncertainty about the extent of the Hg reductions that
these controls could achieve by 2010. Thus, we are seeking technical
information that would allow us to establish an appropriate Hg cap in
2010.
The EPA believes that a carefully designed ``multi-pollutant''
approach--a program designed to control NOX, SO2,
and Hg at the same time--is the most effective way to reduce emissions
from the power sector. One key feature of this approach is the
interrelationship of the timing and cap levels for SO2,
NOX, and Hg. Today, we know that power plants can reduce
their emissions of all three pollutants by installing FGD (which
controls SO2 and Hg emissions) and SCR (which controls
NOX and Hg). With respect to the first phase of Hg
reductions, we have designed this proposal to take advantage of the
combined emission reductions that these technologies provide.
Therefore, we believe that the Phase I Hg cap should be set at a level
that reflects the Hg reductions that would be achieved from the
SO2 and NOX cap levels and corresponding control
requirements in the IAQR that we also are proposing today.
A phase-one cap based on this approach would set a standard of
performance based on the best system of emissions reduction that has
been adequately demonstrated, consistent with section 111(d) of the
Clean Air Act. Research currently indicates that Hg control
technologies other than FGD and SCR--most notably activated carbon
injection (ACI) and breakthrough technologies (e.g., chemical systems
to enhance removal efficiencies for wet scrubbers)--may one day allow
facilities to reliably reduce Hg emissions to levels significantly
below the levels achieved through application of FGD and SCR needed to
satisfy SO2 and NOX control requirements.
However, these technologies have not been adequately demonstrated on
full-scale power plants. Moreover, current information on these
technologies is not sufficient for us to conclude that they will be
adequately demonstrated by 2010. Therefore, we believe that the 2010
cap for Hg should be set at a level that can be achieved through the
installation of FGD and SCR needed to meet the 2010 SO2 and
NOX caps in the proposed IAQR. Requiring additional FGD and
SCR beyond those needed to meet the transport rule in order to further
reduce Hg emissions by 2010 is not reasonable because the incremental
cost of such a requirement for additional Hg reductions would be
extremely high and the capacity of the equipment suppliers may be
overwhelmed.\15\
---------------------------------------------------------------------------
\15\ Analysis conducted in support of the proposed IAQR predicts
that SO2 scrubbers will be installed on 48.7 GW of
existing coal-fired capacity to comply with the Phase I cap. The
analysis also predicts that SCRs will be installed on 24.1 GW of
capacity to reduce NOX emissions. In addition, we predict
that existing SCRs that are currently operated on a seasonal basis
(i.e., for the ozone season) will under the IAQR be operated for the
entire year. These technologies (FGD and SCR) have been developed to
reduce SO2 and NOX emissions. However, they do
realize collateral reductions in Hg, although these reductions are
variable (and somewhat uncertain) across types of coal and other
control technologies used for treatment. The available modeling
suggest that these NOX and SO2 controls are
predicted to reduce Hg emissions from the power sector to a level of
approximately 34 tons per year.
---------------------------------------------------------------------------
Consistent with this framework, we are seeking comment and specific
technical information concerning the 2010 cap level that should be set
for Hg in the final rule. Almost 2 years ago, the Administration
proposed Clear Skies legislation that would have established a 26 ton
Hg cap in 2010. This cap was based on several factors, including
modeling and policy analysis and technical information that was
available at that time. Our most recent analysis, based on the most
recent technical information, suggests that Hg emissions would be
reduced to approximately 34 tons as a result of the FGD and SCR that
will be installed to meet the 2010 caps for SO2 and
NOX in the proposed IAQR. Modeling done by the Energy
Information Agency (EIA) suggests that the controls required under our
proposed IAQR would not reduce Hg to the extent that EPA is projecting.
We are also aware that some stakeholders have recommended near-term Hg
reductions that are lower than our estimates.
We recognize that there is and will be for the immediate future
uncertainty about all these estimates. To a large extent, this
uncertainty exists because we have relatively little direct experience
and data about the Hg reductions that can be achieved through different
combinations of FGD and SCR on different boiler types burning different
ranks of coal, and because there is a high degree of variability in the
data that we do have. For example, based on the ICR data, it appears
that plants with very similar configurations, and that burn similar
ranks of coal, often achieve significantly different levels of Hg
control. Thus, if we receive additional technical information, we may
be able to find that plants can better optimize their FGD and SCR units
to achieve greater reductions in their Hg emissions than we currently
estimate. We therefore seek any technical information, including
information
[[Page 4699]]
about incremental costs and benefits, that provides the basis for any
of the levels mentioned above or other proposals for a near-term cap.
As noted above, EPA is proposing a 15 ton cap in 2018 from coal-
fired electric generating facilities. This proposed cap reflects a
level of Hg emissions reduction that almost certainly exceeds the level
that would be achieved through the installation of FGD and SCR needed
to meet the SO2 and NOX caps in the proposed
IAQR. We conclude that this approach is warranted because we fully
expect other Hg air pollution control technologies such as ACI and/or
one or more of the breakthrough technologies will have been adequately
demonstrated before 2018, making it possible to begin achieving much
greater reductions in Hg between 2010 and 2018. This conclusion relies
on the fact that the small number of current-day pilot scale ACI
projects at Utility Units and the innovative technologies will yield
information that will be usable in implementing similar pilot scale
projects at other facilities. Data from these pilot studies ultimately
will allow companies to design full scale applications that will
provide reasonable assurance that emissions limitations can be reliably
achieved over extended compliance periods. We do not believe that such
full scale technologies can be developed and widely implemented within
the next 6 years; however, it is reasonable to assume that this can be
accomplished over the next 14 years.
Our proposed 15 ton cap in 2018 is grounded largely in the modeling
completed in support of the President's Clear Skies initiative. This
modeling suggests that, assuming technologies such as ACI become
available, such a cap will create an incentive for certain plants to
install these newer technologies. It also suggests that such controls
should not have any significant impact on power availability,
reliability, or pricing. Nor should a 15-ton cap cause any significant
shift in the fuels currently utilized by power plants or in the source
of these fuels. Sensitivity analyses indicate that a more stringent cap
could have potentially significant impacts on fuels and/or power
availability, reliability, or pricing. Less stringent caps do not
appear warranted based on our expectations about technology development
and our modeling analysis of the potential impacts of the 15-ton cap.
The Agency continues to investigate whether the mandatory 70
percent reduction in Hg emissions will be adequate to eliminate public
health risks from local Hg deposition near plants because of scientific
and technical uncertainties. The Agency requests comment on this issue.
The EPA is also proposing a method for apportioning the nation-wide
budget to individual unit sources. The EPA maintains that the emission
budget provides an efficient method for achieving necessary reductions
in Hg emissions (as described in earlier sections of this preamble),
while providing substantial flexibility in implementing the program.
The EPA has concern about Utility Units with low Hg emissions rates
(e.g., emitting less than 25 pounds per year) because the new, Hg-
specific control technologies that we expect to be developed prior to
the Phase II cap deadline may not practicably apply to such units
period. Our data indicate that the 396 smallest emitting coal-fired
Utility Units currently account for less than 5 percent of total Hg
emissions. There is reason to believe that the 15 ton Phase II cap can
be achieved in a cost-effective manner, even if the lowest emitting 396
units are excluded from coverage under this cap. Thus, the EPA is
soliciting comment on the possibility of excluding from the Phase II
cap units with low Hg emissions rates (e.g., emitting less than 25
pounds per year).
In today's notice of proposed rulemaking, EPA is also proposing
that allowances are allocated to affected Utility Units based on the
proportionate share of their baseline heat input to total heat input of
all affected units. For purposes of allocating the allowances, each
unit's baseline heat input is adjusted to reflect the ranks of coal
combusted by the unit during the baseline period. The sum of the unit
emission allowances in a State would be considered the State's
emissions budget. If States choose not to participate in the trading
program, the State budgets and unit emission allocations will become
the required maximum emission limit. States also can require emissions
reductions beyond those required by the State budget and unit emission
limits.
As discussed elsewhere in this preamble, new sources will comply
with NSPS standards for Hg. In addition, new sources will be covered
under the Hg cap of the trading program, and will be required to hold
allowances equivalent to the product of their NSPS and baseline heat
input. The EPA proposes that these sources not receive an adjustment to
their allocated share of allowances since they are required to meet
NSPS, which may increase total emissions but will maintain required
emissions rates.
Rationale for source level limits (allowances). Unit-level
emissions limits will be proposed in a supplemental notice entitled
``Emission Guidelines and Compliance Times for Coal-fired Electric
Utility Steam Generating Units.'' If a State chooses to participate in
the trading program, these unit-level emission limits can be adopted as
unit-level allocations for the trading program. Additionally, the
trading program provides the individual States the discretion in
choosing how to allocate their respective budget allocations.
Different ranks of coal may achieve different Hg reductions
depending on the control equipment installed at the unit. In order to
distribute unit limits equitably, EPA is proposing that Hg emission
limits (allowances if State is participating in a trading program) are
distributed to existing coal units based on their share of total heat
input. This is then adjusted to reflect the concern that the
installation of PM, NOX, and SO2 control
equipment on different coal ranks results in different Hg removal.
The adjustment factors of 1 for bituminous, 1.25 for subbituminous,
and 3 for lignite coals are based on the expectation that Hg in the
coal ranks reacts differently to NOX and SO2
control equipment and that the heat input of the different coal ranks
varies. The conclusion that Hg in each of the coals reacts differently
to NOX and SO2 control equipment was based on
information collected in the ICR as well as more recent data collected
by EPA, DOE, and industry sources. This information, which was
collected from units of various coal ranks and control equipment
configuration, indicated differing levels of Hg removal. The test data
indicated that installation of PM, NOX, and SO2
controls on plants burning bituminous coals resulted in greater Hg
reduction on average than plants burning subbituminous coals or lignite
coals. Likewise, the test data indicated that installation of PM,
NOX, and SO2 controls on plants burning
subbituminous coals resulted in somewhat greater Hg removal than plants
burning lignite coals. On average, units burning lignite coal showed
the least Hg removal of the three coal ranks. See section C.4 for
further discussion on subcategorization approaches considered under
this proposal.
Under the proposed emission limit or allocation methodology,
bituminous units would be allocated a share of the allowances 1.0 times
their share of the overall heat input, subbituminous units would be
allocated a share of the allowances 1.25 times their share of the
overall heat input, and lignite units
[[Page 4700]]
would be allocated a share of the allowances 3.0 times their share of
the overall heat input. These adjustment factors are considered to be
directionally correct based on the test data currently available;
however, we realize that these factors do not in all cases accurately
predict relative rates of Hg emissions from Utility Units with
NOX and SO2 controls. Our goal, however, is not
to have the factors achieve such a result. Rather, the factors are
intended to equitably distribute allowances to the affected industry.
The EPA is taking comment on the appropriateness of these adjustment
factors. Since new sources are required to meet NSPS, EPA is proposing
new sources will not receive an adjustment to their allocated share.
Distribution of State budgets. The trading program establishes a
cap on Hg emissions for affected electric generating units of 15 tons
starting in 2018. The proposed unit level emission limits (allocations)
are the basis for establishing State budgets with the State budgets
equaling the total of the individual unit emission limits in a given
State (see Table 5 of this preamble below). States also have the
flexibility to not participate in the trading program or require more
stringent Hg emissions reductions. For States that do not participate
in the trading program, the proposed unit level allocations will become
fixed, unit level emissions limitations.
Table 5.--Distribution of State Budgets
------------------------------------------------------------------------
Phase II
State budget
(tons)
------------------------------------------------------------------------
Alabama...................................................... 0.506
Alaska....................................................... 0.002
Arizona...................................................... 0.289
Arkansas..................................................... 0.202
California................................................... 0.016
Colorado..................................................... 0.277
Connecticut.................................................. 0.023
Delaware..................................................... 0.029
District of Columbia......................................... 0.000
Florida...................................................... 0.491
Georgia...................................................... 0.483
Hawaii....................................................... 0.009
Idaho........................................................ 0.000
Illinois..................................................... 0.635
Indiana...................................................... 0.833
Iowa......................................................... 0.284
Kansas....................................................... 0.281
Kentucky..................................................... 0.605
Louisiana.................................................... 0.236
Maine........................................................ 0.001
Maryland..................................................... 0.186
Massachusetts................................................ 0.070
Michigan..................................................... 0.517
Minnesota.................................................... 0.274
Mississippi.................................................. 0.114
Missouri..................................................... 0.545
Montana...................................................... 0.148
Nebraska..................................................... 0.165
Nevada....................................................... 0.112
New Hampshire................................................ 0.025
New Jersey................................................... 0.060
New Mexico................................................... 0.240
New York..................................................... 0.157
North Carolina............................................... 0.451
North Dakota................................................. 0.614
Ohio......................................................... 0.810
Oklahoma..................................................... 0.285
Oregon....................................................... 0.030
Pennsylvania................................................. 0.710
Rhode Island................................................. 0.000
South Carolina............................................... 0.226
South Dakota................................................. 0.028
Tennessee.................................................... 0.378
Texas........................................................ 1.837
Utah......................................................... 0.224
Vermont...................................................... 0.000
Virginia..................................................... 0.234
Washington................................................... 0.077
West Virginia................................................ 0.554
Wisconsin.................................................... 0.353
Wyoming...................................................... 0.375
------------------------------------------------------------------------
Model cap-and-trade program. The EPA is outlining a national cap-
and-trade program that States may choose as a cost-effective mechanism
to achieve the emissions reductions requirements in today's rulemaking.
The trading program will meet these requirements by utilizing a cap on
total emissions in order to ensure that emissions reductions under
today's proposed rulemaking are achieved, while providing the
flexibility and cost effectiveness of a market-based system. This
section provides background information and a description of the
trading program and an explanation of how the trading program would
interface with other State and Federal programs. It is EPA's intent to
propose a model rule in a future supplemental notice.
States can voluntarily choose to participate in the trading
programs by adopting the model rule, which is a fully approvable
control strategy for achieving emissions reductions required under the
proposed section 111 rulemaking. Should the States voluntarily choose
to participate in the trading program by adopting the model rule, EPA's
authority to cooperate with and assist the States in the implementation
of the trading program resides in both State law and the CAA. With
respect to State law, any State which elects to adopt the model rule as
part of its section 111 SIP-like rule will be authorizing EPA to assist
the State in implementing the trading program with respect to the
sources in that State. With respect to the CAA, EPA believes that the
Agency's assistance to those States that choose to participate in the
trading program will facilitate the implementation of the program and
minimize administrative burden on the States.
Purpose of the trading program and model rule. In the trading
program, EPA is proposing to jointly implement with participating
States a capped market-based program for certain Utility Units to
achieve and maintain an emissions budget consistent with the proposed
section 111 rulemaking. Specifically, today's proposal is designed to
assist States in: (1) Achieving emissions reductions required under the
proposed section 111 rulemaking; (2) ensuring flexibility for regulated
sources; (3) reducing compliance costs for sources; and (4) reducing
administrative costs to States. In addition to these benefits of
electing to participate in the proposed trading program, EPA also seeks
to create as simple a regulatory regime as possible by applying a
single, comprehensive regulatory approach to all of the affected
jurisdictions.
Beyond choosing to use the proposed trading program, State adoption
of the model rule would ensure consistency in certain key operational
elements of the program among participating States, while allowing each
State flexibility in other important program elements. Uniformity of
the key operational elements across the participating states would
ensure a viable and efficient trading program with low transaction
costs and minimum administrative costs for sources, States, and EPA.
Emissions reductions required by the proposed section 111
rulemaking.
State-level emission budgets. Each of the States and the District
of Columbia covered by today's proposal has been assigned a statewide
emissions budget for Hg. The statewide budgets were developed by
totaling unit-level emissions reductions requirements for coal-fired
electricity generating devices. The statewide budget development
process is fully described elsewhere in today's preamble. States have
the flexibility to meet these State budgets by participating in a
trading program or requiring source level reductions to coal-fired
electric generating units. States have the ability to require
reductions beyond those required by the state budget.
Geographic scope of trading program. As discussed elsewhere in this
preamble, today's proposal would apply to all coal-fired Utility Units
located in all 50 states of the U.S.
[[Continued on page 4701]]
[Federal Register: January 30, 2004 (Volume 69, Number 20)]
[Proposed Rules]
[Page 4701-4750]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr30ja04-13]
[[pp. 4701-4750]] 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
[[Continued from page 4700]]
[[Page 4701]]
Each State has been assigned a statewide emissions budget for Hg.
Each of these States must submit a SIP-like plan detailing the controls
that will be implemented to meet its specified budget for reductions
from electric generating units. Therefore, should some States choose to
achieve the mandated reductions by using an approach other than the
proposed emissions trading rule, the geographic scope of the trading
program would not be nationwide.
Some stakeholders have noted that modeling results suggest that Hg
deposition from emissions from Utility Units may be higher in certain
regions of the country (e.g., the upper Ohio Valley and Mid-Atlantic
areas). In addition, the ecosystems in some regions (e.g., the lakes
regions of the Upper Midwest) may be more sensitive to Hg deposition.
As discussed more fully below, given the 70 percent emission reduction
in the proposed section 111 rule and our experience with cap-and-trade
systems, EPA does not expect any local or regional hot spots. The EPA
is interested in comments on whether it would be appropriate to adjust
the geographic scope of this program to introduce trading ratios
between regions as a way of addressing regional differences should they
occur. For example, EPA could require that eastern Utility Units in
areas of heavy deposition would need greater than 1:1 allowances from
Utility Units outside the region to cover an ounce of Hg emissions. The
EPA is interested in comments on whether such an approach is
appropriate, and if so, on the way to identify appropriate regions
where a higher trading ratio would apply and the appropriate magnitude
of the trading ratio. The EPA is also interested in comments on the
extent to which these adjustments would complicate and reduce the
efficiency of the cap-and-trade program.
Affected sources in the trading program. The model trading rule
applies to coal-fired Utility Units. The term ``electric utility steam
generating unit'' means any fossil fuel fired combustion unit that
serves a generator of more than 25 MW that produces electricity for
sale. A unit that cogenerates steam and serves a generator that
supplies more than one-third of its potential electric output capacity
and more than 25 MW electrical output to any utility power distribution
system for sale shall be considered an Utility Unit.
Benefits of participating in the trading program. Advantages of
cap-and-trade over command-and-control. When designed and implemented
properly, a market-based program offers many advantages over its
traditional command-and-control counterpart. See discussion, supra,
Section III. Six principal advantages of market-based systems have been
recognized: (1) Results in a certain, fixed cap in emissions from
affected and potentially affected sources; (2) potential for the
creation of incentives for early reductions; (3) creation of incentives
for emissions reductions beyond those required by regulations; (4)
reduced cost of compliance for individual sources and the regulated
community in general; (5) promotion of innovation and continued
evolution of production and pollution control technology; and, (6)
increased flexibility for the regulated community without resorting to
waivers, exemptions and other forms of administrative relief. These
benefits result primarily from the flexibility in compliance options
available to sources and the monetary reward associated with avoided
emissions in a market-based system. The cost of compliance in a market-
based program is reduced because sources have the freedom to pursue
various compliance strategies, such as switching fuels, installing
pollution control technologies, or buying authorizations to emit from a
source that has over-complied. Since emissions level below the level
mandated allows the freeing up of allowances that may be sold on the
market, pollution prevention becomes more cost effective, and
innovations in less-polluting alternatives and control equipment are
encouraged.
A market system that employs a fixed tonnage limitation (or cap)
for a source or group of sources provides the greatest certainty that a
specific level of emissions will be attained and maintained since a
predetermined level of reductions is ensured. With respect to transport
of pollution, an emissions cap also provides the greatest assurance to
downwind States that emissions from upwind States will be effectively
managed over time. The capping of total emissions of pollutants over a
region and through time ensures achievement of the environmental goal
while allowing economic growth through the development of new sources
or increased use of existing sources. In an uncapped system (where, for
example, sources are required only to demonstrate that they meet a
given emission rate) the addition of new sources to the regulated
sector or an increase in activity at existing sources can increase
total emissions even though the desired emission rate control is in
effect.
In addition, the reduced implementation burden for regulators and
affected sources benefits taxpayers and those who must comply with the
rules. This streamlined administrative approach allows a small number
of government employees to successfully regulate many sources by (1)
minimizing the necessity for case-by-case rules and (2) taking full
advantage of electronic communication and data transfer to track
compliance and develop detailed, critical inventories of emissions and
plant operations.
Application of the cap-and-trade approach in prior rulemakings.
Title IV. Title IV of the 1990 Amendments to the CAA established the
Acid Rain Program, a program that utilizes a market-based cap-and-trade
approach to require power plants to reduce SO2 emissions by
50 percent from 1980 levels by 2010. At full implementation after 2010,
emissions will be limited, or capped, at 8.95 million tons. It also
includes emission rate requirements to reduce NOX emissions.
The Acid Rain Program for SO2 is widely acknowledged as a
model air pollution control program because it provides significant and
measurable environmental and human health benefits with low
implementation costs.
Units are allocated their share of the total allowances, each
allowance providing an authorization to emit a ton of SO2,
based upon historical records of the heat content of the fuel that they
combusted during the period 1985 to 1987. Units that reduce their
emissions below the number of allowances they hold may trade allowances
with other units in their system, sell them to other sources on the
open market or through EPA auctions, or bank them to cover emissions in
future years. Each affected unit is required to surrender allowances to
cover its emissions each year. Should any unit fail to hold sufficient
allowances, automatic penalties apply. In addition to financial
penalties, units either will have allowances deducted immediately from
their accounts to offset their allowance deficiencies or, if such
deduction would threaten electric reliability, may submit a plan to EPA
that specifies when the allowances will be deducted in the future.
An essential feature of the Acid Rain Program is the requirement
for affected sources to install systems that continuously monitor
emissions. The use of CEMS was an important innovation that allowed
both EPA and sources to track progress, ensure compliance, and provide
credibility to the trading component of the program.
While title IV does provide for an Acid Rain Permit, the permit
simply states a non-source specific requirement that sources comply
with the standard
[[Page 4702]]
rules of the program. Acid Rain permitting has been easily incorporated
into the title V permit process and does not require the typically
resource intensive, case-by-case review associated with other permits
under command-and-control programs.
The Acid Rain Program has achieved major SO2 emissions
reductions, and associated air quality improvements, quickly and cost-
effectively. In 2002, SO2 emissions from power plants were
10.2 million tons, 41 percent lower than 1980. True to its intent, the
program has substantially reduced acid deposition, allowing lakes and
streams in the Northeast to begin recovering from decades of acid rain.
The Acid Rain Program resulted in emission reductions well below the
cap in the areas that contribute most of the sulfur in the acid rain.
Comparing emissions from the 263 power plants regulated in the first
phase of the program in 1999 with those in 1990, the North Central and
Southeast and Mid-Atlantic regions achieved 49 percent, 48 percent and
43 percent reductions in SO2, respectively. Several analyses
of trading under the acid rain program have concluded that the program
did not result in local areas with ``hot spots.''
Trading under the Acid Rain Program has created financial
incentives for electricity generators to look for new and low-cost ways
to reduce emissions, and improve the effectiveness of pollution control
equipment, at costs much lower than predicted. In fact, the Acid Rain
Program achieved reductions at two-thirds the cost of achieving the
same reductions under a command-and-control system. The cap on
emissions and significant automatic penalties for noncompliance ensure
that environmental goals are achieved and sustained, while stringent
emissions monitoring and reporting requirements make flexibility
possible. The level of compliance under the Acid Rain Program continues
to be uncommonly high, measuring over 99 percent.
NOX SIP call and OTC Trading Program. The cap-and-trade
approach has also been used to address regional ozone transport
problems in the eastern U.S. The north-eastern states (Ozone Transport
Commission) began implementing a cap-and-trade program to address
regional ozone transport in 1999. The NOX Budget Trading
Program under the NOX SIP Call began its first year of
implementation in 2003 in the Northeast. Eleven additional States will
join in 2004. Each of the States required to submit a NOX
SIP to address the regional transport of ozone chose to participate in
the interstate trading program. They each based their trading program
on the model rule; some states essentially adopted it in full, other
states modified some provisions for their unique circumstances.
Local environmental improvements achieved using cap-and-trade
model. Mercury emissions from power plants sometimes are deposited
locally near the plant. Nearby lakes may be a source of fish
consumption for recreational and/or subsistence fisherman, and thus
local Hg deposition in nearby lakes could be a source of what are
called hot spots. In this discussion, we are assuming that a power
plant may lead to a hot spot if the contribution of the plant's
emissions of Hg to local deposition is sufficient to cause blood Hg
levels of highly exposed individuals near the plant to exceed the RfD.
For the purposes of choosing a regulatory tool to address hot spots,
the relevant question is what is the contribution of these plants to
hot spots under a cap-and-trade approach, relative to their current
contribution and their projected contribution under a traditional
section 112 approach.
Concerns about hot spots have been raised despite the success and
growing use of cap-and-trade programs. The EPA believes that a trading
approach will help to address this problem. In addition to reductions
required by the cap, all States would have the ability to address local
health-based concerns separate from the Hg cap-and-trade program
requirements.
The EPA does not anticipate significant local health-based concerns
under a national Hg trading program. The Agency has considered this
possibility and believes that the cap-and-trade system, coupled with
related Federal and State programs, will effectively address local
risks. This has been EPA's experience with the title IV program
limiting SO2 emissions.
First, modeling runs suggest that large coal-fired Utility Units--
those that tend to have relatively high Hg emissions--are likely to
have larger local deposition footprints than medium-sized and smaller
coal-fired Utility Units. However, the trading of allowances is likely
to involve large Utility Units controlling their emissions more than
required and selling allowances to smaller Utility Units rather than
the reverse scenario. This prediction arises from the basic economics
of capital investment in the utility industry. Under a trading system
where the firm's access to capital is limited, where the up-front
capital costs of control equipment are significant, and where emission-
removal effectiveness (measured in percentage of removal) is unrelated
to plant size, it makes more economic sense for the utility company to
allocate pollution-prevention capital to its larger facilities than to
the smaller plants (since more allowances will be earned). Any
economies of scale of pollution control investment will favor
investment at the larger plants. Insofar as large coal-fired Utility
Units tend to be newer and/or better maintained than medium-sized and
small facilities, it can be expected that companies will favor
investments in plants with a longer expected lifetime.
Second, the types of Hg that are deposited locally--Hg\++\ and
particulate Hg (Hgp)--are controlled by the same equipment
that controls criteria air pollutants (fine particles, SO2
and NOX). These same types of Hg are more likely to be
deposited locally than Hg\0\. As utilities invest in equipment to
comply with the Agency's new fine particle and ozone control
regulations (e.g., today's proposed IAQR, and new State Implementation
Plans (SIP) for fine particles and ozone), the Agency expects a ``co-
benefit'' in Hg control as controls such as particulate controls,
scrubbers and SCR units are installed on an increasing percentage of
coal-fired Utility Units. The type of Hg that is most difficult to
control is Hg\0\, and it is this gaseous form of Hg that is most likely
to be transported long distances from the Utility Units. Effective
control of Hg\0\ may require significant investment in Hg-specific
control technologies that are only beginning to reach the
commercialization stage.
Considering the economies of Hg trading, Utility Units that have
significant emissions of Hg\0\ may become buyers of allowances from
plants that can cost-effectively control Hg\++\ and Hgp.
Consequently, the economics of the trading system are likely to favor
controls of Hg that are likely to be deposited locally, thereby
reducing any local hot spots.
The structure of the proposed rule permits States to adopt more
stringent performance standards if the State determines that such
regulations are necessary. Although more stringent State regulations
will reduce flexibility built into the cap-and-trade system, States
retain the power under the proposed section 111 rule to adopt stricter
regulations to address local hot spots or other problems. Given the 70
percent emission reduction in the proposed section 111 rule and our
experience with cap-and-trade systems, which shows that the largest
emitters are the first to install stringent emission controls, we do
not expect any local or regional hot spots. However, the Agency plans
to continue monitoring Hg emissions and the operation of the
[[Page 4703]]
trading system to make sure that localized hot spots do not
materialize.
As part of its analysis of the President's Clear Skies initiative,
EPA analyzed Hg emissions reductions under a cap-and-trade mechanism.
In the Clear Skies example, the greatest emissions reductions were
projected to occur at the electric generating sources with the highest
Hg emissions. This pattern is similar to that observed in the
SO2 emissions trading program under the Acid Rain Program.
Under Clear Skies, compared to a base case of existing programs, ionic
Hg emissions (those Hg emissions which tend to be deposited locally,
i.e., within 25 kilometers) from power plants located up to 10
kilometers from a water body were projected to decrease by over 60
percent in 2020. In addition, based on regional-scale Hg deposition
model predictions, Clear Skies could reduce Hg deposition by 5 to 15
percent beyond the existing program base case across much of the
eastern U.S. and could do so to higher levels in certain specific
locations. Based on this available information, the proposed cap-and-
trade mechanism in this regulatory proposal can be expected to reduce
Hg deposition similarly in most areas. Consequently, the EPA does not
anticipate significant local health-based concerns under a national Hg
trading program.
We explain elsewhere in this proposal our intention to take a hard
look at the Hg emissions inventory after full implementation of the
first phase cap. The main purpose of this review is to determine
whether the actual reductions achieved under this program significantly
differ from the outcome predicted by our current analysis. We retain
authority to make adjustments to the program if we find remaining areas
with heavy, localized emissions and higher health risks (i.e., if we
find ``hot spots'').
In the final days before signature and publication of this
proposal, concerns about the possibility of ``hot spots'' under our
proposed cap and trade program were widely reported. We agree that this
is an important issue and believe that our program will effectively
address potential ``hot spots.'' We ask for comment on this issue. We
are particularly interested in receiving site-specific data and
information about locations where commenters believe ``hot spots'' will
continue to exist after implementation of these rules.
State adoption of the model rule. Participation in the trading
program would enable States that have been identified in the proposed
section 111 rulemaking to achieve the required emissions reductions
from stationary combustion sources while minimizing the administrative
burden faced by both States and sources. The SIP-like rule process
required by the proposed rulemaking would be significantly streamlined
for States choosing to include the trading program as a part of the
SIP-like rule. The EPA proposes that adoption of the model rule, to be
published in a future supplemental notice of proposed rulemaking
(SNPR), will be considered a SIP-approvable control strategy for the
proposed section 111 rulemaking. States electing to participate in the
trading program may either adopt the model rule by reference or develop
State regulations that are in accordance with the model rule.
The permitting process under the trading program would be
significantly streamlined since there will be no need for enforceable
compliance plans and source-specific requirements (each permit will
have to be revised to add Hg trading program requirements). Emissions
monitoring, a central requirement of the trading program, as well as
the availability to the public of emissions data, allowance data, and
annual reconciliation information, would ensure that participating
States and the public have confidence that the required emissions
reductions are being achieved.
States that elect to participate in the trading program, thereby
allowing sources to seek the least-cost reductions, are expected to see
substantially lower compliance costs for their sources than under a
comparable rate based program.
Sources included in the trading program also benefit from increased
compliance flexibility, as compared to a rate-based approach that
requires each affected source to comply with an emission rate and
necessitates installation of control equipment for any affected source
that cannot meet the limit. Participation in the trading program
provides sources the choice of numerous compliance strategies.
Moreover, sources can choose to over-comply and free up excess
allowances that can be sold on the market or, as discussed below,
possibly banked for future use. In addition, sources may change their
control approach at any time without regulatory agency approval.
The Hg trading program. Brief description of Hg trading program.
The trading program establishes a first phase cap at a level that
reflects the Hg reductions expected with the SO2 and
NOx in the IAQR in 2010 and a Phase II cap of 15 tons on Hg
emissions for affected Utility Units starting in 2018. The new trading
program for Hg would require sources to hold allowances covering
emissions beginning January 1, 2010. The EPA is proposing that the
owner or operator must hold allowances for all the affected Utility
Units at a facility at least equal to the total Hg emissions for those
units during the year. Compliance with the requirement to hold
allowances will thus be determined on a facility-wide basis. In a
supplemental notice entitled ``Emission Guidelines and Compliance Times
for Coal-fired Electric Utility Steam Generating Units'' EPA will be
proposing unit allocations for existing units. New units will be
covered under the Hg cap of the trading program and will be required to
hold allowances. In the SNPR, EPA will recommend options for States to
address the inclusion of new sources (e.g., new source set asides and/
or updating allocations).
Applicability. The model trading rule applies to coal-fired
combustion units serving a generator of more than 25 MW that produces
electricity for sale. A unit that cogenerates steam and supplies more
than one-third of its potential electric output capacity and more than
25 MW electrical output to any utility power distribution system for
sale shall be considered an Utility Unit.
State trading budgets. This proposal establishes the total number
of tons for the Budget Trading Program within a specific State. The
proposed rule sets the State's unit level allocations and adds up those
allocations to develop a State level budget.
In a supplemental notice entitled ``Emission Guidelines and
Compliance Times for Coal-fired Electric Utility Steam Generating
Units,'' EPA will be taking comment on the proposed methodology for
establishing unit level allocations and the data used to develop these
allocations. As discussed earlier, unit allocations were determined by
adjusting a baseline heat input. That baseline heat input was
determined using the average of the three highest heat inputs of the
period 1998 to 2002. In order to adjust the heat input based on coal
type, coal usage patterns were determined from the ICR data. The EPA
requests comment on the data used to develop proposed unit-level
allocation. The EPA also requests comment on the appropriateness of
using 1999 data to determine the coal adjustment factors.
In today's proposal, EPA is proposing a safety valve provision that
sets a maximum cost for Hg emissions reductions. This provision
addresses some of the uncertainty associated with the cost of Hg
control. In fact, there is an ongoing research process sponsored by
EPA, the DOE, the Electric Power Research Institute (EPRI), and vendors
specifically aimed at furthering our
[[Page 4704]]
understanding of Hg control, with new data being made available on a
continuous basis.
Under the safety valve mechanism, the price of allowances is
capped, meaning that if the allowance price exceeds the ``safety-
valve,'' sources may borrow allowances from following years to have
access to more allowances available at that price. The EPA proposes a
price of $2,187.50 for a Hg allowance (covering one ounce). This price
will be annually adjusted for inflation. The Administrator will deduct
corresponding allowances from future facility allowance accounts.
The purpose of this provision is to minimize unanticipated market
volatility and provide more market information that industry can rely
upon for compliance decisions. The safety valve mechanism ensures the
cost of control does not exceed a certain level, but also ensures that
emissions reductions are achieved. The future year cap is reduced by
the borrowed amount, and the emissions reductions are achieved.
We note that this proposed approach may create implementation
problems associated with the need to ``reconcile'' at some point in
time the allowances borrowed from future compliance periods. We ask for
comment on the need for a safety valve and the viability of our
proposed approach, and solicit suggestions for other viable approaches.
We also ask for comment on the possibility of conducting auctions
each year, at which allowances would be offered for sale. The pool of
allowances to be auctioned would be created by specified procedures,
such as setting aside a fixed or incremented percentage of allocations
each year. The auctions would be open to any person. A person wishing
to bid for allowances in the auction would submit bids according to
auction procedures, a bidding schedule, a bidding means, and
requirements for financial guarantees specified in the regulations.
Winning bids, and required payments, for allowances would be determined
in accordance with the regulations. For any winning bid, we would
record the allowances in a tracking system only after the required
payment for such allowances is received. If we decide to provide for
auctions, we would need to determine how to collect and properly
disperse the revenues. We believe that responsibility for managing this
aspect of the program would necessarily fall to the individual states
that opt to participate in the cap and trade program. We ask for
comment on all aspects of this auctions proposal. If we decide to
proceed, details of the auction program would be spelled out in the
upcoming SNPR.
Key elements of Hg model cap-and-trade rule to be proposed in SNPR.
Allowance allocations. The EPA is proposing heat input-based
allocations for existing coal units (with different ratios for
different coal types).
The EPA believes that allocating based on heat input data is
desirable because accurate protocols exist for monitoring this data and
reporting it to EPA, and several years of certified data are available
for most of the affected sources.
New sources will be covered under the Hg cap of the trading program
and will be required to hold allowances equivalent to the product of
their NSPS standard and a baseline heat input. Therefore, state budgets
will be maintained at the levels proposed in today's rulemaking even
after the addition of new coal-fired electricity generating units in
the state. State SIP-like rules will need to address the inclusion of
these new sources in their state budget. In the SNPR, EPA will
recommend options for states to address the inclusion of new sources
(e.g., new source set asides and/or updating allocations).
Allowance management system, compliance, penalties, and banking.
Each of these elements is part of the accounting system that enables
the functioning of a trading program. An accurate, efficient accounting
system is critical to an emissions trading market. Transparency of the
system, allowing all interested parties access to the information
contained in the accounting system, increases the accountability of
regulated sources and contributes to reduced transaction costs of
trading allowances.
In order to guarantee the equitable treatment of all affected
sources across the trading region, the elements included in this
section need to be incorporated in the same manner in each state that
participates in trading.
Allowance management. The EPA intends to propose a model trading
rule that will be reasonably consistent with the existing allowance
tracking systems that are currently in use for the Acid Rain Program
under title IV and the NOX Budget Trading Program under the
NOX SIP Call. These two systems are called the Allowance
Tracking System (ATS) and the NOX Allowance Tracking System
(NATS), respectively. Under the section 111 trading rule, EPA would
maintain a separate system for Hg, Mercury Allowance Tracking System
(MATS). The MATS would be established as an automated system used to
track Hg allowances held by affected units under the Hg cap-and-trade
program, as well as those allowances held by other organizations or
individuals. Specifically, MATS would track the allocation of all Hg
allowances, holdings of Hg allowances in accounts, deduction of Hg
allowances for compliance purposes, and transfers between accounts. The
primary role of MATS, in conjunction with an emissions tracking system,
is to provide an efficient, automated means of monitoring compliance
with the trading programs. The MATS also provide the allowance market
with a record of ownership of allowances, dates of allowance transfers,
buyer and seller information, and the serial numbers of allowances
transferred.
Compliance. Compliance in the trading program consists of the
deduction of allowances from affected facilities'' accounts to offset
the quantity of emissions at the facilities. The EPA plans to propose
that compliance be assessed at the facility level, rather than the unit
level as is currently done in both the Acid Rain and NOX
Budget trading programs.
Penalties. The EPA plans to propose a system of automatic penalties
should a facility not obtain sufficient Hg allowances to offset
emissions for the compliance period. The automatic penalty provisions
will not limit the ability of the permitting authority or EPA to take
enforcement action under State law or the CAA.
Banking. Banking is the retention of unused allowances from 1 year
for use in a later calendar year. Banking allows sources to create
reductions beyond required levels and ``bank'' the unused allowances
for use later. Generally speaking, banking has several advantages: it
can encourage earlier or greater reductions than are required from
sources, stimulate the market and encourage efficiency, and provide
flexibility in achieving emissions reduction goals. On the other hand,
it may result in banked allowances being used to allow emissions in a
given year to exceed the trading program budget. The EPA plans to
propose that banking of allowances after the start of the Hg trading
program be allowed with no restrictions.
Emissions monitoring and reporting. Monitoring and reporting are an
integral part of any cap-and-trade program. Consistent and accurate
quantification of emissions ensures each allowance actually represents
one ounce of emissions and that one ounce of reported emissions from
one source is equivalent to one ounce of reported emissions from
another source. This establishes the integrity of the
[[Page 4705]]
allowance (i.e., the authorization to emit one ounce of Hg) and
instills confidence in the market mechanisms that are designed to
provide sources with flexibility in achieving compliance. Given the
variability in the type, operation and fuel mix of sources in the cap-
and-trade program, EPA believes that to ensure this accuracy and
consistency, emissions must be monitored using continuous emissions
monitoring methods. As discussed earlier, EPA plans to include in the
model trading rule a requirement for States to require year-round Part
75 monitoring and reporting for all sources.
Accountability for affected sources. Key to the success of existing
cap-and-trade programs and the integrity of the emission allowance
trading markets has been clear accountability for a source's emissions.
This takes the form of affected sources officially designating a
specific person (and alternate) that is responsible for the official
certification of all allowance transfers and emissions monitoring and
reporting as submitted to EPA in quarterly compliance reports. With
each quarterly submission, this responsible party must certify that:
(1) the monitoring equipment data were reported in compliance with the
monitoring and reporting requirements, and (2) the emission and
operation reports are true, accurate, and complete.
The trading program to be proposed in the future SNPR will include
provisions to provide for the same strict standards for source
accountability established in the Acid Rain Program and the
NOX SIP call. This will include provisions for the
establishment and management of an Authorized Account Representative.
Adoption of these provisions will be required by all States that wish
to participate in the trading program.
3. What Are the Subpart Da Hg Emission Guidelines?
This information will be provided in the Emission Guidelines, which
will be provided in an upcoming supplemental notice.
4. How Did EPA Select the Format for the Proposed Emission Guidelines?
This information will be provided in the Emission Guidelines, which
will be provided in an upcoming supplemental notice.
5. How Did EPA Determine the Emissions Monitoring and Reporting
Requirements for the Proposed Emission Guidelines?
Monitoring and reporting are an integral part of any Hg reduction
program, including a cap-and-trade program. Consistent and accurate
quantification of emissions ensures the integrity of a Hg reduction
program. The continuous emissions monitoring methods must incorporate
rigorous quality assurance testing and substitute data provisions for
times when monitors are unavailable because of planned and unplanned
outages. In addition, there must be requirements for record keeping and
electronic reporting. Provisions like these are contained in 40 CFR
part 75, and are used in both the Acid Rain and NOX SIP Call
programs, for SO2 and NOX, but not currently for
Hg.
In an effort to maintain program integrity, the EPA plans to
propose revisions to 40 CFR part 75 to establish requirements for
emission monitoring, quality assurance, substitute data, record
keeping, and reporting and to include in the SNPR a requirement for
States to require year-round Part 75 monitoring and reporting for all
sources. Monitor certification deadlines and other details will be
specified in the SNPR. The EPA believes that emissions will then be
consistently and accurately monitored and reported from unit to unit
and from State to State.
The EPA also intends to require year-round reporting of emissions
and monitoring data from each unit at each affected facility. A single
report for Hg will be required on a quarterly basis in a format
specified by the EPA. The reports will be required to be in an
electronic data reporting (EDR) format and must be submitted to EPA
electronically. The reports will be maintained in EPA's Emissions
Tracking System (ETS). This centralized reporting requirement is
necessary to ensure consistent review, checking, and posting of the
emissions and monitoring data at all affected sources, which
contributes to the integrity of the Hg reduction program.
6. How Did EPA Determine the Compliance Times for the Proposed Emission
Guidelines?
This information will be provided in the Emission Guidelines, which
will be provided in an upcoming supplemental notice.
E. Rationale for the Proposed Ni Guidelines
1. What Is the Rationale for the Proposed Subpart Da Ni Emission
Guidelines?
The proposed emission guidelines for Ni from existing oil-fired
units was determined by analyzing the emissions data available. The
data were obtained from the Utility RTC which provided information
indicating that Ni was the pollutant of concern due to its high level
of emissions from oil-fired units and the potential health effects
arising from exposure to it. The EPA examined available test data and
found that ESP-equipped units can effectively reduce Ni. Analysis of
the available emissions data indicated that existing oil-fired units
can limit Ni emissions to 210 lb/TBtu input or 0.002 lb/MWh output
gross. The EPA is proposing both an input-based and an output-based
standard in the proposed rule for existing sources (based on potential
difficulties in retrofitting the necessary data acquisition measures
for the output-based standard at an existing source).
The EPA is sensitive to the fact that some sources burn fuels
containing very little Ni. Therefore, EPA solicits comment on a Ni-in-
oil limit that would be equivalent to the proposed stack values of 210
lb/TBtu input or 0.002 lb/MWh gross. With a limit on the amount of Ni
in the oil, an existing source could choose to comply with an alternate
oil-content-based Ni emission limitation instead of the stack Ni
emission limit to meet the proposed rule. Such an alternate Ni-in-oil
limit could be useful where Ni constituent levels are low in the fuel.
Two alternatives for compliance purposes are provided in the
proposed rule for oil-fired units. The owner/operator can elect to: (1)
Meet the standard of performance for Ni, or (2) burn distillate oil
(exclusively) rather than residual oil. If an oil-fired unit is
currently burning, or switches to burning, distillate oil
(exclusively), it would be exempt from all oil-fired unit initial and
continuous compliance requirements until such time as it begins burning
any oil other than distillate oil. The proposed rule would require that
the exempted oil-fired unit begin the performance testing procedures if
it resumes burning a fuel other than distillate oil.
2. How Did EPA Address Dual-Fired (Oil/Natural Gas) Units?
The EPA is aware that an oil-fired unit may fire oil at certain
times of the year and natural gas at other times. The choice of when to
fire oil or natural gas is usually based on the economics or
availability of fuel (i.e., seasonal considerations). As stated
elsewhere in this preamble, EPA considers a unit to be an oil-fired
unit if (1) it is equipped to fire oil and/or natural gas, and (2) it
fires oil in amounts greater than or equal to two percent of its annual
fuel consumption. This two percent value is intended to represent that
amount of oil that a true natural gas-fired unit might
[[Page 4706]]
use strictly for start-up purposes on an annual basis. The EPA solicits
comment on whether this two percent breakpoint is a reasonable basis
for allowing those units that use oil only for startup purposes to be
exempted from regulation under the proposed rule.
V. Impacts of the Proposed Rule
Under the section 111 proposed approach, Hg reductions prior to
2015 are expected to be comparable to Hg reductions achieved under the
proposed section 112 MACT. In fact, given the early reductions achieved
from banking under the section 111 proposal, plus the possibility that
a section 112 MACT approach provides no incentive for power plants to
reduce below the required level, a section 111 approach will likely
lead to greater reductions in the Hg relative to the proposed section
112 MACT approach. After 2015, the Phase II cap in the proposed section
111 approach is reduced to 15 tpy, leading to still more reductions
than achieved under the proposed section 112 MACT. Therefore, the
estimated benefits of the proposed section 112 MACT can serve as a
lower bound of the benefits achieved through the proposed section 111
approach.
A. What Are the Air Impacts?
When the emissions rates developed in today's proposed section 112
MACT rule are applied to current coal use (based on the ICR), annual Hg
emissions to the atmosphere from Utility Units are projected to be 34
tons. Consistent with previous regulatory programs affecting
electricity generating units, EPA has analyzed this scenario using the
Integrated Planning Model (IPM) (see http://www.epa.gov/airmarkets/epa-ipm
). Based on this model, total Hg emissions from affected coal-fired
power plants are projected to be 30 tons in 2010 and 31 tons in 2020.
However, Hg emissions are likely to be much closer to the calculated
level of 34 tons. First, the model allows for Hg reductions using ACI
only at the 60 percent and 90 percent levels (rather than using a range
of 60 to 90 percent), which may lead the model to understate Hg
emissions from as much as 2.3 tons by bituminous-fired units. Second,
the modeling may not fully capture the range of Hg in different coal
ranks which could underestimate emissions, particularly when modeling a
facility-specific limit as is the case with this analysis. The modeling
assumes a range of Hg contents for different ranks of coal, but due to
averaging, may not fully capture all Hg contents of coal. (See IPM
documentation, Chapter 4 for further information on Hg content of
coal.)
B. What Are the Water and Solid Waste Impacts?
The EPA estimated the additional water usage that would result from
the MACT floor level of control to be 307 million gallons per year for
existing affected sources. These costs are accounted for in the control
costs estimates.
The EPA estimated the additional solid waste that would result from
the MACT floor level of control to be 282,000 tpy for existing sources.
The costs of handling the additional solid waste generated are also
accounted for in the control costs estimates.
A discussion of the methodology used to estimate impacts is
presented in the memorandum entitled ``Methodology for Estimating Cost
and Emissions Impact for Coal- and Oil-Fired Electric Utility Steam
Generating Units National Emission Standards for Hazardous Air
Pollutants'' in the docket.
C. What Are the Energy Impacts?
The EPA expects an increase of approximately 1,418 million kilowatt
hours (kWh) in national annual energy usage as a result of the proposed
rule. The increase results from the electricity required by existing
sources to operate control devices installed to meet the proposed rule.
D. What Are the Control Costs?
Table 6 of this preamble shows the estimated capital and annual
cost impacts for each subcategory. Costs include testing and monitoring
costs, but not record keeping and reporting costs.
Table 6.--Summary of Capital and Annual Costs for New and Existing Sources Under the Section 112 MACT Proposal
----------------------------------------------------------------------------------------------------------------
Estimated/
projected Annualized Capital
Source Subcategory No. of cost (106$/ costs
affected yr) (106$)
units
----------------------------------------------------------------------------------------------------------------
Coal-fired Units........................ Bituminous-fired............... 549 728 4,609
Subbituminous-fired............ 68 92 607
Lignite-fired.................. 5 9 61
Blends......................... 74 101 654
IGCC unit...................... 0 0 0
Coal refuse-fired.............. 3 16 52
--------------
Total, coal-fired units................. ............................... 719 945 5,982
Oil-fired Units......................... Oil-fired...................... 186 417 2,190
----------------------------------
Total, coal- and oil-fired units........ ............................... 905 1,362 8,172
----------------------------------------------------------------------------------------------------------------
Costs are estimated from methods based on the ``EPA Air Pollution
Control Cost Manual,'' which uses a factor method for estimating total
capital investment, then total annual and annualized costs for an
emission control system. Basic equipment costs are found either from
the Manual or from vendor contacts. Factors in the manual are applied
to the equipment cost to estimate direct and indirect costs associated
with installing the equipment. Annual operating and maintenance costs
and annualized costs for debt service are estimated to obtain annual
payments attributable to the system used for emission control. For
electric utility costing, each of the U.S. units is costed separately
using equations developed from the cost manual. A discussion of the
methodology used to estimate impacts is presented in the memorandum
entitled ``Methodology for Estimating Cost and Emissions Impact for
Coal- and Oil-Fired Electric Utility Steam Generating Units National
Emission Standards for Hazardous Air Pollutants'' in the docket.
[[Page 4707]]
As part of the costing, annual quantities of water, wastewater,
solid waste, and energy required for operating the emission control
systems are determined. These quantities represent materials or energy
used in the system or wastes that must be treated as a result of system
operation. The quantities are listed elsewhere in this preamble.
E. Can We Achieve the Goals of the Proposed Section 112 MACT Rule in a
Less Costly Manner?
The EPA has tried in developing the section 112 MACT proposal to
ensure that the cost to the regulated community is reasonable in view
of the potential benefits, and to allow maximum flexibility in
compliance options consistent with our statutory obligations. The
Agency recognizes, however, that the section 112 MACT proposal may
still require some facilities to take costly steps to further control
Hg and Ni emissions even though those emissions may not result in
exposures which could pose unacceptable risk. The EPA is, therefore,
specifically soliciting comment on whether there are further ways to
structure the section 112 MACT proposal to focus on the facilities
which may pose significant risks to public health and avoid the
imposition of high costs on facilities that pose little risk to public
health and the environment.
F. What Are the Social Costs and Benefits of the Proposed Section 112
MACT Rule?
The proposed rule sets out two major alternative actions. The first
alternative would regulate Hg emissions under the section 112 MACT
provisions CAA. The second alternative would regulate Hg emissions
through a cap-and-trade program under section 111 of the CAA.
Implementation of the section 111 cap-and-trade program would be
carried out in coordination with a cap-and-trade program for
SO2 and NOX emissions under the IAQR, which is
also being proposed in today's Federal Register. The IAQR would limit
Utility Unit SO2 and NOX emissions in
approximately 30 eastern states to address their contribution to
nonattainment of the fine particle (PM2.5) and ozone
National Ambient Air Quality Standards (NAAQS).
The control approaches adopted by Utility Units in response to the
proposed section 112 Hg MACT regulations would also achieve collateral
reductions of NOX and SO2. Based on the scenario
analyzed, the proposed action would reduce approximately 902,000 tons
of NOX emissions, and 591,000 tons of SO2
emissions in 2010. The proposed IAQR would require annual
SO2 emissions reductions of 3.6 million tons and
NOX emissions reductions of 1.4 million tons in 2010, while
achieving Hg reductions comparable to those estimated for the proposed
section 112 MACT by 2010.
Our assessment of costs and benefits of the proposed MACT rule is
detailed in the ``Benefits Analysis for the Section 112 Utility Rule,''
located in the Docket. These analyses are based on the costs and
emissions reductions associated with a particular Hg control scenario
that is consistent with the reduction in nationwide Hg emissions
expected by implementation of the proposed section 112 MACT standard.
The specific emissions control scenario is derived from application of
the Integrated Planning Model (IPM), which EPA has used to assess the
costs and emissions reductions associated with a number of regulations
of the power sector. While the Hg reduction estimates in the scenario
are consistent with the Agency's assessment of control technologies,
EPA is aware that estimates of associated reductions in other
pollutants, notably SO2 and NOX (co-benefits) may
vary significantly with alternative assumptions about the application
of particular control technologies and incentives created by the
existence of other major regulatory programs affecting the power
sector. In particular, based on past EPA analyses of multi-pollutant
strategies (e.g. Clear Skies Technical Support Document D, http://www.epa.gov/clearskies/
technical.html) the control choices made
pursuant to either a 111-or 112-based Hg program would likely be
significantly affected by the requirements of the IAQR. For these
reasons, in addition to the findings of the analyses derived from the
MACT-only scenario, we also provide some estimates of the direction of
costs and benefits under reasonably foreseeable alternative scenarios
for implementing limits on Hg emissions that take such potential
interactions into account.
The proposed section 111 and 112 actions address Hg and Ni
emissions from coal- and oil-fired Utility Units. Exposure to emissions
of Hg at low levels may cause neurological damage and learning
disorders. Nickel subsulfide and refinery dusts are classified as known
human carcinogens; Ni carbonyl is classified as a probable human
carcinogen based upon studies in animals. Due to the control
technologies selected for analysis, the actions to reduce Hg will also
achieve reductions of NOX and SO2. Although not
incorporated into the analyses, the actions to reduce Ni will also
reduce direct emissions of particulate matter. Known health and welfare
effects associated with the pollutants affected by the proposed rule
are listed in Table 7 of this preamble. As indicated in the table, we
are able to quantify and monetize only a portion of these effects.
TABLE 7.--Health and Welfare Effects of Pollutants Affected by the Proposed Utility MACT Standard
----------------------------------------------------------------------------------------------------------------
Pollutant/effect Quantified and monetized Unquantified effects
----------------------------------------------------------------------------------------------------------------
PM/Health.......................... Premature mortality--adults.......... Low birth weight.
Premature mortality--infants......... Changes in pulmonary function.
Bronchitis--chronic and acute........ Chronic respiratory diseases other
Hospital admissions--respiratory and than chronic bronchitis.
cardiovascular. Morphological changes.
Emergency room visits for asthma..... Altered host defense mechanisms.
Non-fatal heart attacks (myocardial Non-asthma respiratory emergency
infarction). room visits.
Lower and upper respiratory illness.. Changes in cardiac function (e.g.,
Asthma exacerbations................. heart rate variability).
Minor restricted activity days....... Allergic responses (to diesel
Work loss days....................... exhaust).
PM/Welfare......................... ..................................... Visibility in Class I areas.
Visibility in residential and non-
Class I areas.
Household soiling.
Ozone/Health....................... ..................................... Increased airway responsiveness to
stimuli.
Inflammation in the lung.
Chronic respiratory damage.
Premature aging of the lungs.
[[Page 4708]]
Acute inflammation and respiratory
cell damage.
Increased susceptibility to
respiratory infection.
Non-asthma respiratory emergency
room visits.
Hospital admissions--respiratory.
Emergency room visits for asthma.
Minor restricted activity days.
School loss days.
Asthma attacks.
Cardiovascular emergency room
visits.
Premature mortality B acute
exposures.
Acute respiratory symptoms.
Ozone/Welfare...................... ..................................... Decreased commercial forest
productivity.
Decreased yields for fruits and
vegetables.
Decreased yields for commercial and
non-commercial crops.
Damage to urban ornamental plants.
Impacts on recreational demand from
damaged forest aesthetics.
Damage to ecosystem functions.
Decreased outdoor worker
productivity.
Nitrogen and Sulfate Deposition/ ..................................... Costs of nitrogen controls to reduce
Welfare. eutrophication in selected eastern
estuaries.
Impacts of acidic sulfate and
nitrate deposition on commercial
forests.
Impacts of acidic deposition on
commercial freshwater fishing.
Impacts of acidic deposition on
recreation in terrestrial
ecosystems.
Impacts of nitrogen deposition on
commercial fishing, agriculture,
and forests.
Impacts of nitrogen deposition on
recreation in estuarine ecosystems.
Reduced existence values for
currently healthy ecosystems.
SO2/Health......................... ..................................... Hospital admissions for respiratory
and cardiac diseases.
Respiratory symptoms in asthmatics.
NOX/Health......................... ..................................... Lung irritation.
Lowered resistance to respiratory
infection.
Hospital Admissions for respiratory
and cardiac diseases.
Hg Health.......................... ..................................... Neurological disorders.
Learning disabilities.
Developmental delays.
Cardiovascular effects*.
Altered blood pressure regulation*.
Increased heart rate variability*.
Myocardial infarctions*.
Reproductive effects in adults*.
Hg Deposition Welfare.............. ..................................... Impacts on birds and mammals (e.g.
reproductive effects).
Impacts to commercial, subsistence,
and recreational fishing.
Reduced existence values for
currently healthy ecosystems.
Ni Health.......................... ..................................... Dermatitis.
Respiratory effects.
Increased Risk of Lung and Nasal
cancer.
----------------------------------------------------------------------------------------------------------------
* These are potential effects as the literature is either contradictory or incomplete.
It is estimated that the section 112 MACT proposal will reduce
national Hg emissions to approximately 34 tons and national Ni
emissions to approximately 103 tons at electric utility facilities that
generate steam using fossil fuels (i.e., coal or oil fuels). The health
effects associated with these pollutants are discussed earlier in this
preamble, however, a summary of the potential benefits is provided
below. While it is beneficial to society to reduce Hg and Ni, we are
unable to quantify and provide a monetized estimate of the benefits at
this time due to gaps in available information on the fate of emissions
for these two pollutants, human exposure, and health impact models.
The Hg and Ni emissions reductions associated with implementing of
the proposed action would produce a
[[Page 4709]]
variety of benefits. Mercury emitted from utilities and other natural
and man-made sources is carried by winds through the air and eventually
is deposited to water and land. In water, Hg is transformed to
methylmercury through biological processes. Methylmercury, a highly
toxic form of Hg, is the form of Hg of greatest concern for the purpose
of this rulemaking. Once Hg has been transformed into methylmercury, it
can be ingested by the lower trophic level organisms where it can
bioaccumulate in fish tissue (i.e., concentrations in predatory fish
build up over the fish's entire lifetime, accumulating in the fish
tissue as predatory fish consume other species in the food chain).
Thus, fish and wildlife at the top of the food chain can have Hg
concentrations that are higher than the lower species, and they can
have concentrations of Hg that are higher than the concentration found
in the water body itself. Therefore, the most common form of exposure
to Hg for humans and wildlife is through the consumption of
contaminated predatory fish, such as: Commercially consumed tuna,
shark, or other saltwater fish species and recreationally caught bass,
perch, walleye or other freshwater fish species. When humans consume
fish contaminated with methylmercury, the ingested methylmercury is
almost completely absorbed into the blood and distributed to all
tissues (including the brain); it also readily passes through the
placenta to the fetus and fetal brain.
Based on the findings of the National Research Council, EPA has
concluded that benefits of Hg reductions would be most apparent at the
human consumption stage, as consumption of fish is the major source of
exposure to methylmercury. At lower levels, documented Hg exposure
effects may include more subtle, yet potentially important,
neurodevelopmental effects.
Some subpopulations in the U.S., such as: Native Americans,
Southeast Asian Americans, and lower income subsistence fishers, may
rely on fish as a primary source of nutrition and/or for cultural
practices. Therefore, they consume larger amounts of fish than the
general population and may be at a greater risk to the adverse health
effects from Hg due to increased exposure. In pregnant women,
methylmercury can be passed on to the developing fetus, and at
sufficient exposure may lead to a number of neurological disorders in
children. Thus, children who are exposed to low concentrations of
methylmercury prenatally may be at increased risk of poor performance
on neurobehavioral tests, such as those measuring attention, fine motor
function, language skills, visual-spatial abilities (like drawing), and
verbal memory. The effects from prenatal exposure can occur even at
doses that do not result in effects in the mother. Mercury may also
affect young children who consume fish contaminated with Hg.
Consumption by children may lead to neurological disorders and
developmental problems, which may lead to later economic consequences.
In response to potential risks of consuming fish containing
elevated concentrations of Hg, EPA and FDA have issued fish consumption
advisories which provide recommended limits on consumption of certain
fish species for different populations. The EPA and FDA are currently
developing a joint advisory that has been released in draft form. This
newest draft FDA-EPA fish advisory recommends that women and young
children reduce the risks of Hg consumption in their diet by moderating
their fish consumption, diversifying the types of fish they consume,
and by checking any local advisories that may exist for local rivers
and streams. This collaborative FDA-EPA effort will greatly assist in
educating the most susceptible populations. Additionally, the
reductions of Hg from this regulation may potentially lead to fewer
fish consumption advisories, which will benefit the fishing community.
Reducing emissions of Ni can also contribute to several benefits.
We are concerned with the inhalation risks of Ni as the primary route
of human exposure in this rulemaking. Nickel is found in ambient air at
very low levels as a result of releases from oil combustion. The
differing forms of Ni have varying levels of toxicity. There is great
uncertainty about the type of Ni emitted. Respiratory effects have also
been reported in humans who have been occupationally exposed to high
levels of Ni. Human and animal studies have reported an increased risk
of lung and nasal cancers from exposure to Ni refinery dusts and Ni
subsulfide. Animal studies of soluble Ni compounds (i.e., Ni carbonyl)
have reported lung tumors. The EPA has classified Ni refinery
subsulfide as a Group A carcinogen due to lung and nasal cancers in
humans occupationally exposed to Ni refinery dust. Ni carbonyl is
classified as a Group B2, probable human carcinogen based upon studies
conducted in animals.
The proposed actions would also reduce NOX and
SO2 emissions that contribute to the formation of fine
particles (PM2.5). In general, exposure to high
concentrations of PM2.5 may aggravate existing respiratory
and cardiovascular disease including asthma, bronchitis and emphysema,
especially in children and the elderly. Nitrogen oxides and
SO2 are also contributors to acid deposition, or acid rain,
which causes acidification of lakes and streams and can damage trees,
crops, historic buildings and statues. Exposure to PM2.5 can
lead to decreased lung function, and alterations in lung tissue and
structure and in respiratory tract defense mechanisms which may then
lead to, increased respiratory symptoms and disease, or in more severe
cases, premature death or increased hospital admissions and emergency
room visits. Children, the elderly, and people with cardiopulmonary
disease, such as asthma, are most at risk from these health effects.
Fine PM can also form a haze that reduces the visibility of scenic
areas, can cause acidification of water bodies, and have other impacts
on soil, plants, and materials.
As previously stated, the control technologies selected for
analysis of the Hg portion of this action would also achieve reductions
of NOX and SO2. Based on the scenario analyzed,
the proposed section 112 MACT action would reduce approximately 902,000
tons of NOX emissions, and 591,000 tons of SO2
emissions. These projected reductions are due to the reliance on some
SO2 and NOX controls and coal-switching to
achieve Hg reductions. When compared to the base case, there is a
projected shift towards lower sulfur bituminous coals (about 6 percent)
that are also lower in Hg, which results in SO2 emissions
reductions. In addition, some units are projected to use SO2
controls (scrubbers) to comply with the proposed section 112 MACT
(about 1 GW), as well as generation shifts (about 1 percent) from
uncontrolled units to units with scrubbers which would result in
additional SO2 reductions from the base case. Projected
NOX emissions reductions from the base case are a result of
seasonal NOX controls being operated annually in the MACT
case to achieve additional Hg control (about 90 GW of SCR operate
annually). Because NOX and SO2 contribute to the
formation of PM2.5, and because direct PM controls would be
applied to meet the Ni requirements, these standards should lead to
substantial benefits from reductions of ambient PM. Therefore,
reduction of SO2 and NOX emissions from utilities
will contribute to reduced human health and welfare impacts.
Due to both technical and resource limits in available modeling, we
have only been able to quantify and monetize the benefits for a few of
the endpoints associated with reducing Hg, Ni, directly emitted PM, and
gaseous NOX
[[Page 4710]]
and SO2. However, based on relevant available modeling of
several alternative control strategies to reduce Utility Unit
SO2 and NOX emissions (including Clear Skies), we
can approximate the benefits of reduced exposure to ambient PM
resulting from reductions in precursor emissions of NOX and
SO2. These benefit categories--including reductions in
premature mortality--are believed to represent a dominant fraction of
the total benefits associated with these proposed actions.
To quantify benefits, we evaluated PM-related health effects
(including SO2 and NOX contributions to ambient
concentrations of PM2.5). Our approach requires the
estimation of changes in air quality expected from the rule and the
resulting effects on health. In order to characterize the benefits of
today's proposed section 112 action, given the constraints on time and
resources available for the analysis, we adopted a benefits transfer
technique that relies on air quality and benefits modeling conducted
for the recently proposed Clear Skies Act of 2003. Results from the
Clear Skies analysis in 2010 are then scaled and transferred to the
emission reductions expected from the proposed section 112 MACT rule.
This benefits assessment is conducted in two phases. First, using
modeling runs developed in support of the Clear Skies legislation, we
estimated the number of reduced incidences of illnesses,
hospitalizations, and premature fatalities associated with a unit
change in ambient concentrations of PM2.5. The Clear Skies
program covers a similar universe of affected sources and yields larger
reductions in NOX and SO2 emissions. The
distribution of emission reductions across states differs between the
two analyses, especially in the Western U.S. Given the very small
reductions in NOX and SO2 expected to occur in
the Western U.S. as a result of the rule and the potential for errors
in transferring benefits, we limit the benefits analysis to the Eastern
U.S., and derive the benefits transfer factors from the Eastern U.S.
Clear Skies benefits results only. Recognizing the differences in
emission reduction patterns in the Eastern U.S. between the Clear Skies
analysis and the current proposed MACT standards, we believe that the
benefits per ton of SO2 and NOX estimated for the
Clear Skies analysis represents a reasonable approximation of the
benefits per ton that might be realized from the reductions in
NOX and SO2 expected under the current proposed
section 112 rule. The analysis of the proposed section 112 MACT
includes only health benefits related to PM2.5 reductions
associated with the NOX and SO2 reductions, and
does not include health benefits related to ozone reductions,
visibility benefits, and other benefits including reduced nitrogen
deposition and acidification. For the most part, quantifiable ozone
benefits do not contribute significantly to the monetized benefits:
thus, their omission does not materially affect the magnitude of
estimated benefits. Visibility benefits may be more significant;
although, visibility has generally contributed only a few percent of
total monetized benefits.
Second, we used the Clear Skies analysis to develop a relationship
between changes in ambient PM2.5 concentrations and the
underlying NOX and SO2 emission reductions to
reflect differences in emissions reductions between the modeled Clear
Skies scenario and the proposed standard. The sum of the scaled
benefits for the SO2 and NOX emission reductions
provide us with the total benefits of the rule.
The benefit estimates derived from the Clear Skies air quality
modeling in the first phase of our analysis uses an analytical
structure and sequence similar to that used in the benefits analyses
for the proposed Nonroad Diesel rule and proposed IAQR and in the
``section 812 studies'' analysis of the total benefits and costs of the
Clean Air Act. We used many of the same models and assumptions used in
the Nonroad Diesel and IAQR analyses as well as other Regulatory Impact
Analyses (RIAs) prepared by the Office of Air and Radiation. By
adopting the major design elements, models, and assumptions developed
for the section 812 studies and other RIAs, we have largely relied on
methods which have already received extensive review by the independent
Science Advisory Board (SAB), the National Academies of Sciences, by
the public, and by other federal agencies. Interested parties will be
able to obtain further information from the section 812 study on the
kinds of methods we are likely to use for estimating benefits and costs
in the final rule.
The benefits transfer method used in the second phase of the
analysis is similar to that used to estimate benefits in the recent
analysis of the proposed Nonroad Diesel rule and Nonroad Large Spark-
Ignition Engines and Recreational Engines standards (67 FR 68241,
November 8, 2002). A similar method has also been used in recent
benefits analyses for the proposed Industrial Boilers and Process
Heaters NESHAP and the Reciprocating Internal Combustion Engines
NESHAP.
The economic and energy impact analysis memo (for the proposed
section 112 MACT) details the control scenario as consisting of a
combination of direct Hg controls and additional SO2 and
NOX controls. Under this scenario, the extent of
SO2 and NOX controls in Eastern U.S. would be
limited to approximately 902,000 tons of NOX and 591,000
tons of SO2. As outlined above, these reductions drive the
monetized benefits of the proposed rule, which would be approximately
$15 billion (1999$). This economic benefit is associated with
approximately 2,200 avoided premature mortalities, 1,200 avoided cases
of chronic bronchitis, 2,900 avoided non-fatal heart attacks, thousands
of avoided hospital and emergency room visits for respiratory and
cardiovascular diseases, tens of thousands of avoided days with
respiratory symptoms, and millions of avoided work loss and restricted
activity days. The EPA recognizes that at the present time, these
direct controls have not been adequately demonstrated, so this scenario
reflects uncertain but possible advances in the availability of such
controls. Under a more restrictive assumption about the availability of
direct Hg controls (e.g., ACI) than used in this analysis, Utility Unit
control strategies may rely to an even greater extent on
SO2, NOX, and direct PM control approaches to
reduce Hg. In such an alternative MACT-only scenario, projected costs
and benefits would be correspondingly much greater than those indicated
in Table 8 of this preamble.
As noted above, however, consideration of the proposed section 112
MACT or proposed section 111 only scenarios does not capture the full
dimension of the most likely air regulatory situation facing the power
industry over the next decade. As noted above, EPA is also proposing
significant additional SO2 and NOX reduction
requirements to limit interstate transport of these pollutants. These
requirements are likely to require Utility Units to install
SO2 and NOX controls on significant fractions of
their coal-fired capacity. For these reasons, there are strong public
policy reasons to consider the combined influence of the Hg and IAQR
requirements.
Table 8 of this preamble summarizes the results of the benefit-cost
analysis of the proposed section 112 MACT scenario and compares them
with estimates of the range of potential costs and benefits associated
with an alternative scenario that addresses combined implementation of
section 111 Hg requirements in coordination with proposed
SO2 and NOX
[[Page 4711]]
requirements in the proposed IAQR. The potential influence of such a
combined scenario is illustrated in the second column of Table 8 of
this preamble, which assumes the proposed section 111 requirements are
implemented in combination with the IAQR. The IAQR analysis projects
that the Hg reductions associated with implementing the SO2/
NOX requirements in the Eastern U.S. in 2010 would be
approximately 10.6 tons per year, which is almost identical to those
estimated from the proposed section 112 MACT-only scenario.
If the goal for the proposed section 111 program in 2010 is limited
to these co-control reductions, there might be no additional costs or
benefits to the program, over those achieved by the IAQR--this is
indicated in the lower portion of the ranges in Table 8 of this
preamble. By contrast, if the proposed section 111 regulation adopts a
2010 goal similar to the Phase I Clear Skies Hg cap, additional Hg
reductions would be required over those forecast for the IAQR. Based on
a multipollutant analyses conducted for Clear Skies (p D-9, Technical
appendix D, at http://www.epa.gov/airmarkets/epa-ipm), power generators
would likely opt for some additional SO2 and NOX
controls beyond those needed for the IAQR, as well as considering
additional direct Hg controls. Although the actual results are
uncertain, the Clear Skies results suggest that the costs and benefits
associated with a section 112 MACT-only approach may reflect a
reasonable lower bound for the additional costs and benefits. These
potential additional costs and benefits related to additional Hg
controls are reflected in the upper end of the ranges in Table 8 of
this preamble. In the decade beyond 2010, the proposed section 111
program would establish a 15 ton cap for Hg in 2018, similar to Clear
Skies. Based on Clear Skies analyses, this would result in further Hg
controls, which would likely include at least some additional
SO2/NOX controls as well as direct Hg controls.
The IAQR program alone produces only small additional reductions in Hg
emissions in 2020. The Hg reductions estimated for the proposed section
112 MACT and the proposed section 111 and proposed IAQR programs are
summarized in Table 9. These forecasts are based on IPM analyses of the
proposed section 112 MACT scenario outlined above, the proposed IAQR
analysis, and estimates derived from earlier analyses of the Clear
Skies program.
Every benefit-cost analysis examining the potential effects of a
change in environmental protection requirements is limited, to some
extent, by data gaps, limitations in model capabilities (such as
geographic coverage), and uncertainties in the underlying scientific
and economic studies used to configure the benefit and cost models.
Deficiencies in the scientific literature often result in the inability
to estimate changes in health and environmental effects. Deficiencies
in the economics literature often result in the inability to assign
economic values even to those health and environmental outcomes that
can be quantified. While these general uncertainties in the underlying
scientific and economics literatures are discussed in detail in the RIA
and its supporting documents and references, the key uncertainties
which have a bearing on the results of the benefit-cost analysis of
today's action are the following:
1. The exclusion of potentially significant benefit categories
(e.g., health and ecological benefits of reduction in hazardous air
pollutants emissions);
2. Errors in measurement and projection for variables such as
population growth;
3. Uncertainties in the estimation of future year emissions
inventories and air quality;
4. Uncertainties associated with the extrapolation of air quality
monitoring data to some unmonitored areas required to better capture
the effects of the standards on the affected population;
5. Variability in the estimated relationships of health and welfare
effects to changes in pollutant concentrations; and
6. Uncertainties associated with the benefit transfer approach.
Despite these uncertainties, we believe the benefit-cost analysis
provides a reasonable indication of the expected economic benefits of
the proposed actions under a given set of assumptions.
Based on estimated compliance costs (control + administrative costs
associated with Paperwork Reduction Act requirements associated with
the proposed rule and predicted changes in the price and output of
electricity), the estimated social costs of the proposed section 112
MACT-only scenario are $1.6 billion (1999$). Social costs are different
from compliance costs in that social costs take into account the
interactions between affected producers and the consumers of affected
products in response to the imposition of the compliance costs. In this
action, coal-fired utilities are the affected producers and users of
electricity are the consumers of the affected product.
As explained above, we estimate $15 billion in benefits from the
proposed section 112 MACT, compared to less than $2 billion in costs.
It is important to put the results of this analysis in the proper
context. The large benefit estimate is not attributable to reducing
human and environmental exposure to Hg. It arises from ancillary
reductions in SO2 and NOX that result from
controls aimed at complying with the proposed MACT. Although
consideration of ancillary benefits is reasonable, we note that these
benefits are not uniquely attributable to Hg regulation. Under the
IAQR, coal-fired units would achieve much larger reductions in
SO2 and NOX emissions than they would under the
proposed section 112 MACT. In the years ahead, as the Agency and the
States develop rules, guidance and policies to implement the new air
quality standards for ozone and PM, coal-fired power plants will be
required to implement additional controls to reduce SO2 and
NOX (e.g., scrubbers, SCR units, year-round NOX
controls in place of summertime only controls, conversion to low-sulfur
coals, and so forth). Thus, most or all of the ancillary benefits of Hg
control would be achieved anyway, regardless of whether a section 112
MACT is promulgated. Based on analysis of the Clear Skies legislation,
EPA believes that the proposed 2018 Hg cap in the proposed section 111
rule would result in additional SO2 and NOX
reductions beyond those that would be required under the proposed IAQR.
Thus, the section 111 approach, unlike the section 112 approach, may
achieve SO2 and NOX reduction benefits beyond
those that would be achieved under the IAQR. We believe, however, that
even if no Hg controls were imposed, most major coal-fired units would
still have to reduce their SO2 and NOX emissions
as part of the efforts to bring the nation into attainment with the new
air quality standards. In light of these considerations, the Agency
believes that the key rationale for controlling Hg is to reduce public
and environmental exposure to Hg, thereby reducing risk to public
health and wildlife. Although the available science does not support
quantification of these benefits at this time, the Agency believes the
qualitative benefits are large enough to justify substantial investment
in Hg emission reductions.
It should be recognized, however, that this analysis does not
account for many of the potential benefits that may result from these
actions. The net benefits would be greater if all the benefits of the
Hg, Ni, and other pollutant reductions
[[Page 4712]]
could be quantified. Notable omissions to the net benefits include all
benefits of HAP reductions, including reduced cancer incidences, toxic
morbidity effects, and cardiovascular and CNS effects, and all health
and welfare effects from reduction of ambient NOX and
SO2.
Table 8.--Summary of Monetized Benefits, Costs, and Net Benefits of the Proposed Section 112 MACT Standard, \1\
With a Range for Potential Alternative Scenario Estimates for MACT and Section III Proposal in 2010 ($billions/
yr)
----------------------------------------------------------------------------------------------------------------
MACT-only
Scenario Sec. 111 plus IAQR Combined\4\
----------------------------------------------------------------------------------------------------------------
Social Costs\2\....................................... $1.6 $2.9 to 4.5+
Social Benefits\3\: ............... .......................................
PM-related Health benefits........................ $15+B $58 to 73+B
Net Benefits (Benefits-Costs)\3\...................... $13+B $55 to $68+B
----------------------------------------------------------------------------------------------------------------
\1\All costs and benefits are rounded to two significant digits.
\2\Note that costs are the total costs of reducing all pollutants, including Hg and other metallic air toxics,
as well as NOX and SO2 reductions. Benefits in this table are associated only with NOX and SO2.
\3\Not all possible benefits or disbenefits are quantified and monetized in this analysis. In particular, ozone
health and welfare and PM welfare benefits are omitted. Other potential benefit categories that have not been
quantified and monetized are listed in Table 5. B is the sum of all unquantified benefits and disbenefits.
\4\Estimated combined benefits of S. 111 plus IAQR costs and benefits in 2010. Ranges do not reflect actual
analyses of combined programs. Rough estimates based on consideration of available IAQR, MACT, and Clear Skies
analyses. See text.
Table 9.--Forecast Mercury Emissions Under the Proposed Section 112
MACT, and the Proposed Section 111 Rule and the Proposed IAQR\1\
------------------------------------------------------------------------
Program/Year 2010 2020
------------------------------------------------------------------------
MACT only............................................. 34 31
IAQR only............................................. 34 30
IAQR and section 111 caps............................. \(2)\ 18-22
------------------------------------------------------------------------
\1\ Annual reductions from base case forecast under current programs to
reduce Utility Unit emissions. MACT only value for 2015 based on
interpolation of 2010 and 2015. Lower bound of IAQR and section 111
caps in 2010 assumes Hg cap is set at co-control level achieved by
IAQR. Upper bound in 2010 and ranges thereafter estimates derived from
Clear Skies analyses.
\2\ Mercury emissions will reflect the level of emissions resulting from
the co-benefits of controlling SO2 and NOX. See section IV.B.1 for a
detailed discussion.
VI. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review
Under Executive Order 12866 (58 FR 51735, October 4, 1993), EPA
must determine whether a regulatory action is ``significant'' and,
therefore, subject to review by the Office of Management and Budget
(OMB) and subject to the requirements of the Executive Order. The
Executive Order defines ``significant regulatory action'' as one that
is likely to result in a rule that may:
(1) Have an annual effect on the economy of $100 million or more or
adversely affect in a material way the economy, a sector of the
economy, productivity, competition, jobs, the environment, public
health or safety, or State, local, or tribal governments or
communities;
(2) Create a serious inconsistency or otherwise interfere with an
action taken or planned by another agency;
(3) Materially alter the budgetary impact of entitlements, grants,
user fees, or loan programs, or the rights and obligation of recipients
thereof; or
(4) Raise novel legal or policy issues arising out of legal
mandates, the President's priorities, or the principles set forth in
the Executive Order.
Pursuant to the terms of Executive Order 12866, it has been
determined that the proposed rule is an economically ``significant
regulatory action'' because the annual cost may exceed $100 million
dollars. As such, this action was submitted to OMB for review. Changes
made in response to OMB suggestions or recommendations will be
documented in the public record.
B. Paperwork Reduction Act
The information collection requirements in the proposed NESHAP have
been submitted for approval to OMB under the Paperwork Reduction Act,
44 U.S.C. 3501 et seq. The ICR document prepared by EPA has been
assigned EPA ICR No.----.
The information requirements are based on notification,
recordkeeping, and reporting requirements in the NESHAP General
Provisions (40 CFR part 63, subpart A), which are mandatory for all
operators subject to national emission standards. These recordkeeping
and reporting requirements are specifically authorized by section 114
of the Act (42 U.S.C. 7414). All information submitted to EPA pursuant
to the recordkeeping and reporting requirements for which a claim of
confidentiality is made is safeguarded according to Agency policies set
forth in 40 CFR part 2, subpart B.
The proposed rule would require a monitoring plan submitted to the
Administrator but would not require any reports beyond those required
by the General Provisions. The recordkeeping requirements require only
the specific information needed to determine compliance. The proposed
rule would require notification in advance of complying with the rule
by changing fuel.
The annual average monitoring, reporting, and recordkeeping burden
for this collection (averaged over the first 3 years of this ICR) is
estimated to total 243,000 labor hours per year. This includes 2
responses per year from 568 respondents for an average of 214 hours per
response. The total annualized cost burden is estimated at $48.4
million, including labor, capital, and operation and maintenance. The
capital costs of monitoring equipment are estimated at $66.8 million;
the estimated annual cost for operation and maintenance of monitoring
equipment is $15.4 million.
Burden means the total time, effort, or financial resources
expended by persons to generate, maintain, retain, or disclose or
provide information to or for a Federal agency. This includes the time
needed to review instructions; develop, acquire, install, and utilize
technology and systems for the purposes of collecting, validating, and
verifying information, processing and maintaining information, and
disclosing and providing information; adjust the existing ways to
comply with any previously applicable instructions and requirements;
train personnel to be able to respond to a collection of information;
search data sources; complete and review the collection of
[[Page 4713]]
information; and transmit or otherwise disclose the information.
An agency may not conduct or sponsor, and a person is not required
to respond to, a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for EPA's
regulations in 40 CFR part 63 are listed in 40 CFR part 9.
To comment on the Agency's need for this information, the accuracy
of the provided burden estimates, and any suggested methods for
minimizing respondent burden, including the use of automated collection
techniques, EPA has established a public docket for this proposed rule,
which includes this ICR, under Docket ID number OAR-2003-0056. Submit
any comments related to the ICR for this proposed rule to EPA and OMB.
See the ADDRESSES section at the beginning of this notice for where to
submit comments to EPA. Send comments to OMB at the Office of
Information and Regulatory Affairs, Office of Management and Budget,
725 17th Street, NW, Washington, DC 20503, Attention: Desk Office for
EPA. Because OMB is required to make a decision concerning the ICR
between 30 and 60 days after January 30, 2004, a comment to OMB is best
assured of having its full effect if OMB receives it by March 1, 2004.
The final rule will respond to any OMB or public comments on the
information collection requirements contained in this proposal.
C. Regulatory Flexibility Act
The EPA has determined that it is not necessary to prepare a
regulatory flexibility analysis in connection with the proposed rule.
We have also determined that the proposed rule will not have a
significant impact on a substantial number of small entities.
For purposes of assessing the impacts of the final rule on small
entities, small entity is defined as:
(1) A small business according to Small Business Administration
size standards by the North American Industry Classification System
(NAICS) category of the owning entity. For electric utilities, the size
standard is 4 billion kilowatt-hours of production or less,
respectively;
(2) a small governmental jurisdiction that is a government of a
city, county, town, school district or special district with a
population of less than 50,000; and
(3) a small organization that is any not-for-profit enterprise that
is independently owned and operated and is not dominant in its field.
After considering the economic impact of the proposed rule on small
entities, we have determined that the proposed rule will not have a
significant impact on a substantial number of small entities. Companies
owning affected facilities as small businesses are projected to incur
about 1.2 percent of the total compliance costs. Comparing these costs
for small entities to their generation revenues, they represent about
1.3 percent of generation revenues.
An economic impact analysis was performed to estimate the changes
in product price and production quantities for this action. As
mentioned in the summary of economic impacts earlier in this preamble,
the estimated changes in prices and output for affected firms is less
than 1 percent.
This analysis, therefore, allows us to certify that there will not
be a significant impact on a substantial number of small entities from
the implementation of the proposed rule. For more information, consult
the docket for the proposed rule.
We specifically solicit comment on the option to lower small entity
costs through excluding units that release small amounts of Hg (e.g.,
less than 25 pounds annually) from the phase II cap, while maintaining
this cap for the largest sources of Hg.
We continue to be interested in the potential impacts of the
proposed rule on small entities and welcome comments on issues related
to such impacts.
D. Unfunded Mandates Reform Act
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public
Law 104-4, establishes requirements for Federal agencies to assess the
effects of their regulatory actions on State, local, and tribal
governments and the private sector. Under section 202 of the UMRA, we
generally must prepare a written statement, including a cost-benefit
analysis, for proposed and final rules with ``Federal mandates'' that
may result in expenditures to State, local, and tribal governments, in
the aggregate, or to the private sector, of $100 million or more in any
1 year. Before promulgating a rule for which a written statement is
needed, section 205 of the UMRA generally requires us to identify and
consider a reasonable number of regulatory alternatives and adopt the
least costly, most cost-effective or least burdensome alternative that
achieves the objectives of the rule. The provisions of section 205 do
not apply when they are inconsistent with applicable law. Moreover,
section 205 allows us to adopt an alternative other than the least
costly, most cost-effective or least burdensome alternative if the
Administrator publishes with the final rule an explanation why that
alternative was not adopted. Before we establish any regulatory
requirements that may significantly or uniquely affect small
governments, including tribal governments, we must develop a small
government agency plan under section 203 of the UMRA. The plan must
provide for notifying potentially affected small governments, enabling
officials of affected small governments to have meaningful and timely
input in the development of regulatory proposals with significant
Federal intergovernmental mandates, and informing, educating, and
advising small governments on compliance with the regulatory
requirements.
We have determined that the proposed rule contains a Federal
mandate that may result in expenditures of $100 million or more for
State, local, and tribal governments, in the aggregate, or the private
sector in any 1 year. Accordingly, we have prepared a written statement
(titled ``Unfunded Mandates Reform Act Analysis for the Proposed
Industrial Boilers and Process Heaters NESHAP)'' under section 202 of
the UMRA which is summarized below.
1. Statutory Authority
As discussed in section I of this preamble, the statutory authority
for the proposed rulemaking is sections 111 and 112 of the CAA. Title
III of the CAA Amendments was enacted to reduce nationwide air toxic
emissions. Section 112(b) of the CAA lists the 188 chemicals,
compounds, or groups of chemicals deemed by Congress to be HAP. These
toxic air pollutants are to be regulated by NESHAP.
Section 112(d) of the CAA directs us to develop NESHAP which
require existing and new major sources to control emissions of HAP
using MACT based standards. This NESHAP applies to all fossil fuel-
fired utility boilers located at major sources of HAP emissions as
mentioned earlier in this preamble.
In compliance with section 205(a) of the UMRA, we identified and
considered a reasonable number of regulatory alternatives. Additional
information on the costs and environmental impacts of these regulatory
alternatives is presented in the docket.
The regulatory alternative upon which the proposed rule is based
represents the MACT floor for fossil fuel-fired utility boilers and, as
a result, it is the least costly and least burdensome alternative.
[[Page 4714]]
2. Social Costs and Benefits
The benefits and cost analyses prepared for the proposed rule are
detailed in the ``Benefit Analysis of the CAA Section 111 Proposal To
Reduce Mercury Emissions From Fossil-Fuel Fired Utilities'' and the
``Economic and Energy Impact Analysis of the Section 112 Utility
MACT,'' respectively. Both of these reports are in the docket. Based on
estimated compliance costs associated with the proposed rule and the
predicted change in prices and production in the affected industry, the
estimated social costs of the proposed rule are $1.6 billion (1999
dollars).
It is estimated that by 2010, Hg emissions will be reduced by the
section 112 MACT rule to approximately 34 tons and Ni emissions reduced
to approximately 103 tons. Studies have determined a relationship
between exposure to these HAP and the onset of cancer and a number of
other health effects. The Agency is unable to provide a monetized
estimate of the benefits of the Hg and Ni emissions reduced by the
proposed rule at this time. However, there are significant reductions
in NOX and SO2 that occur. Reductions of
NOX amount to 902,000 tons and 591,000 tons of
SO2 are expected to occur. These reductions occur from
existing sources in operation in 2010 and are expected to continue
throughout the life of the affected sources. The major health effect
that results from these NOX and SO2 emissions
reductions is a reduction in premature mortality. Other health effects
that occur are reductions in chronic bronchitis, asthma attacks, and
work-lost days (i.e., days when employees are unable to work).
While we are unable to monetize the benefits associated with the Hg
and Ni HAP emissions reductions, we are able to monetize the benefits
associated with the PM and SO2 emissions reductions. For
NOX and SO2, we estimated the benefits associated
with reductions of health effects but were unable to quantify all
categories of benefits (particularly those associated with ecosystem
and environmental effects). Estimates of the benefits and costs of the
SO2 and NOX emission reductions associated with
the proposed actions are presented in Table 8 above. Unquantified
benefits are noted with ``B'' in the estimates presented below.
3. Future and Disproportionate Costs
The Unfunded Mandates Act requires that we estimate, where accurate
estimation is reasonably feasible, future compliance costs imposed by
the proposed rule and any disproportionate budgetary effects. Our
estimates of the future compliance costs of the proposed rule are
discussed in section--of this preamble.
We do not believe that there will be any disproportionate budgetary
effects of the proposed rule on any particular areas of the country,
State or local governments, types of communities (e.g., urban, rural),
or particular industry segments. This is true for the 28 facilities
owned by about 80 different government bodies, and this is borne out by
the results of the ``Economic and Energy Impact Analysis of the Utility
MACT,'' the results of which are discussed in a previous section of
this preamble.
4. Effects on the National Economy
The Unfunded Mandates Act requires that we estimate the effect of
the proposed rule on the national economy. To the extent feasible, we
must estimate the effect on productivity, economic growth, full
employment, creation of productive jobs, and international
competitiveness of the U.S. goods and services, if we determine that
accurate estimates are reasonably feasible and that such effect is
relevant and material.
The nationwide economic impact of the proposed rule is presented in
the ``Economic and Energy Impact Analysis for the Utility MACT'' in the
docket. This analysis provides estimates of the effect of the proposed
rule on some of the categories mentioned above. The results of the
economic impact analysis are summarized in a previous section of this
preamble.
5. Consultation With Government Officials
The Unfunded Mandates Act requires that we describe the extent of
the Agency's prior consultation with affected State, local, and tribal
officials, summarize the officials' comments or concerns, and summarize
our response to those comments or concerns. In addition, section 203 of
the UMRA requires that we develop a plan for informing and advising
small governments that may be significantly or uniquely impacted by a
proposal. Although the proposed rule does not affect any State, local,
or tribal governments, we have consulted with State and local air
pollution control officials. We also have held meetings on the proposed
rule with many of the stakeholders from numerous individual companies,
environmental groups, consultants and vendors, labor unions, and other
interested parties. We have added materials to the Air docket to
document these meetings.
In addition, we have determined that the proposed rule contains no
regulatory requirements that might significantly or uniquely affect
small governments. While some small governments may have some sources
affected by the proposed rule, the impacts are not expected to be
significant. Therefore, today's proposed rule is not subject to the
requirements of section 203 of the UMRA.
E. Executive Order 13132: Federalism
Executive Order 13132 (64 FR 43255, August 10, 1999), requires EPA
to develop an accountable process to ensure ``meaningful and timely
input by State and local officials in the development of regulatory
policies that have federalism implications.'' ``Policies that have
federalism implications'' is defined in the Executive Order to include
regulations that have ``substantial direct effects on the States, on
the relationship between the national government and the States, or on
the distribution of power and responsibilities among the various levels
of government.''
The proposed rule does not have federalism implications. It will
not have substantial direct effects on the States, on the relationship
between the national government and the States, or on the distribution
of power and responsibilities among the various levels of government,
as specified in Executive Order 13132.
Although section 6 of Executive Order 13132 does not apply to the
proposed rule, we consulted with representatives of State and local
governments to enable them to provide meaningful and timely input into
the development of the proposed rule. This consultation took place
during the FACA committee meetings where members representing State and
local governments participated in developing recommendations for this
rulemaking. The concerns raised by representatives of State and local
governments were considered during the development of the proposed
rule.
In the spirit of Executive Order 13132, and consistent with EPA
policy to promote communications between EPA and State and local
governments, EPA specifically solicits comment on the proposed rule
from State and local officials.
F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
Executive Order 13175 (65 FR 67249, November 6, 2000) requires the
EPA to develop an accountable process to ensure ``meaningful and timely
input by tribal officials in the development of regulatory policies
that have Tribal
[[Page 4715]]
implications.'' ``Policies that have tribal implications'' is defined
in the Executive Order to include regulations that have ``substantial
direct effects on one or more Indian tribes, on the relationship
between the Federal government and the Indian tribes, or on the
distribution of power and responsibilities between the Federal
government and Indian tribes.''
Under section 5(b) of Executive Order 13175, EPA may not issue a
regulation that has tribal implications, that imposes substantial
direct compliance costs, and that is not required by statute, unless
the Federal government provides the funds necessary to pay the direct
compliance costs incurred by Tribal governments, or EPA consults with
Tribal officials early in the process of developing the proposed
regulation. Under section 5(c) of Executive Order 13175, EPA may not
issue a regulation that has Tribal implications and that preempts
tribal law, unless the Agency consults with Tribal officials early in
the process of developing the proposed regulation.
The EPA has concluded that the proposed rule may have Tribal
implications because two coal-fired Utility Units are located in Indian
Country. Based on a review of information available to EPA at this time
about the operations at these two plants, the Agency concluded that
compliance of the plants with the requirements of the proposed rule
would not impose substantial direct compliance costs on the affected
Tribal governments. The EPA specifically solicits additional comment
from Tribal officials on the proposed rule's potential impacts on
Utility Units located in Indian Country.
G. Executive Order 13045: Protection of Children From Environmental
Health and Safety Risks
Executive Order 13045, ``Protection of Children From Environmental
Health Risks and Safety Risks'' (62 FR 19885, April 23, 1997) applies
to any rule that (1) is determined to be ``economically significant''
as defined under Executive Order 12866, and (2) concerns an
environmental health or safety risk that EPA has reason to believe may
have a disproportionate effect on children. If the regulatory action
meets both criteria, Section 5-501 of the Order directs the Agency to
evaluate the environmental health or safety effects of the planned rule
on children, and explain why the planned regulation is preferable to
other potentially effective and reasonably feasible alternatives.
In accordance with the Order, the Agency evaluated the
environmental and health and safety effects of the proposed rule, and
for the reasons explained above, the Agency believes that the proposed
strategies are preferable to other potentially effective and reasonably
feasible alternatives. The strategies proposed in this rulemaking will
further improve air quality and will further improve children's health.
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
Executive Order 13211 (66 FR 28355, May 22, 2001) provides that
agencies shall prepare and submit to the Administrator of the Office of
Information and Regulatory Affairs, Office of Management and Budget, a
Statement of Energy Effects for certain actions identified as
``significant energy actions.'' Section 4(b) of Executive Order 13211
defines ``significant energy actions'' as ``any action by an agency
(normally published in the Federal Register) that promulgates or is
expected to lead to the promulgation of a final rule or regulation,
including notices of inquiry, advance notices of final rulemaking, and
notices of final rulemaking: (1) (i) That is a significant regulatory
action under Executive Order 12866 or any successor order, and (ii) is
likely to have a significant adverse effect on the supply,
distribution, or use of energy; or (2) that is designated by the
Administrator of the Office of Information and Regulatory Affairs as a
``significant energy action.'' The proposed rule is a ``significant
energy action'' because it is likely to have a significant adverse
effect on the supply, distribution, or use of energy. The basis for the
determination is as follows.
Compared to 2010 projections of existing statutory and regulatory
requirements, coal-fired and gas-fired electricity generation are
projected to remain relatively unchanged by this action. When compared
to 2010 projections of existing statutory and regulatory requirements,
about 900 MW of coal-fired capacity is projected to be uneconomic to
maintain. Coal production for the electric power sector is expected to
increase from 2000 levels, about 147 million tons or 16 percent. When
compared to 2010 projections of existing statutory and regulatory
requirements, the nationwide price of fuel for the electric power
sector, both coal and natural gas remain relatively unchanged by this
action, with coal prices projected to remain unchanged and gas prices
projected to increase less than 1 percent. Nationwide retail
electricity prices are projected to gradually decline from 2000 levels
but then rise over time. Prices are projected to drop initially due to
excess generation capacity; in 2010 prices are projected to increase
due to new capacity requirements, which lead to higher capital costs
and greater natural gas use, and higher retail prices passed on to
consumers. In 2020, retail electricity prices are projected to still be
below 2000 prices. When compared to 2010 projections of existing
statutory and regulatory requirements, electricity prices are projected
to increase less than 1 percent. We also expect that there will be no
discernible impact on the import of foreign energy supplies, and no
other adverse outcomes are expected to occur with regards to energy
supplies. For more information on the estimated energy effects, please
refer to the economic and energy impact analysis memo for the proposed
rule. The analysis is available in the public docket. Total annual
costs of this action are projected to be up to $1.6 billion in 2010,
depending on other actions that EPA or States might take to control
SO2 and NOX emissions. These costs represent
about a 1.9 percent increase in annual electricity production costs.
Because this proposed regulation has greater than a 1 percent
impact on the cost of electricity production and because it results in
the retirement of greater than 500 MW of coal-fired generation (the
retirement estimate is 900 MW), this regulation is significant. It
should be noted that EPA has proposed a trading program to achieve Hg
reduction as an alternative to the MACT standard, which is a command
and control regulation. The relative flexibility offered by a trading
program may ease the impact on energy production.
I. National Technology Transfer and Advancement Act
Section 12(d) of the National Technology Transfer and Advancement
Act (NTTAA) of 1995 (Pub. L. No. 104-113; 15 U.S.C. 272 note) directs
EPA to use voluntary consensus standards in its regulatory and
procurement activities unless to do so would be inconsistent with
applicable law or otherwise impractical. Voluntary consensus standards
are technical standards (e.g., materials specifications, test methods,
sampling procedures, business practices) developed or adopted by one or
more voluntary consensus bodies. The NTTAA directs EPA to provide
Congress, through annual reports to the OMB, with explanations when EPA
does not use available and applicable voluntary consensus standards.
This rulemaking involves technical standards.
[[Page 4716]]
List of Subjects
40 CFR Part 60
Environmental protection, Administrative practice and procedure,
Air pollution control, Coal, Electric power plants, Intergovernmental
relations, Metals, Natural gas, Nitrogen dioxide, Particulate matter,
Reporting and recordkeeping requirements, Sulfur oxides.
40 CFR Part 63
Environmental protection, Air pollution control, Hazardous
substances, Reporting and recordkeeping requirements.
Dated: December 15, 2003.
Michael O. Leavitt,
Administrator.
For the reasons stated in the preamble, title 40, chapter I, parts
60 and 63 of the Code of the Federal Regulations are proposed to be
amended as follows:
Note: There are two options proposed for comment. Based on the
comments we receive on this proposal, we will promulgate either
Option 1 or Option 2.
Option 1--Proposed Amendments to Parts 60 and 63
PART 60--[AMENDED]
1. The authority citation for part 60 continues to read as follows:
Authority: 42 U.S.C 7401, et seq.
2. Section 60.17 is amended by adding paragraph (a)(65) to read as
follows:
Sec. 60.17 Incorporations by Reference.
* * * * *
(a) * * *
(65) ASTM D6784-02, Standard Test Method for Elemental, Oxidized,
Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired
Stationary Sources (Ontario Hydro Method), for appendix B to part 60,
Performance Specification 12A.
* * * * *
APPENDIX B PART 60
3. Appendix B to part 60 is amended by adding in numerical order
new Performance Specification 12A to read as follows:
Performance Specification 12a--Specifications and Test Procedures
for Total Vapor Phase Mercury Continuous Emission Monitoring
Systems in Stationary Sources
1.0 Scope and Application.
1.1 Analyte.
------------------------------------------------------------------------
Analyte CAS No.
------------------------------------------------------------------------
Mercury (Hg)............................................... 7439-97-6
------------------------------------------------------------------------
1.2 Applicability.
1.2.1 This specification is for evaluating the acceptability of
total vapor phase Hg continuous emission monitoring systems (CEMS)
installed on the exit gases from fossil fuel fired boilers at the
time of or soon after installation and whenever specified in the
regulations. The Hg CEMS must be capable of measuring the total
concentration in [mu]g/m3 (regardless of speciation) of
vapor phase Hg, and recording that concentration on a dry basis,
corrected to 20 degrees C and 7 percent CO2. Particle
bound Hg is not included. The CEMS must include (a) a diluent
(CO2) monitor, which must meet Performance Specification
3 in 40 CFR part 60, appendix B, and (b) an automatic sampling
system. Existing diluent and flow monitoring equipment can be used.
This specification is not designed to evaluate an installed
CEMS's performance over an extended period of time nor does it
identify specific calibration techniques and auxiliary procedures to
assess the CEMS's performance. The source owner or operator,
however, is responsible to calibrate, maintain, and operate the CEMS
properly. The Administrator may require, under CAA section 114, the
operator to conduct CEMS performance evaluations at other times
besides the initial test to evaluate the CEMS performance. See 40
CFR 60.13(c).
2.0 Summary of Performance Specification
Procedures for measuring CEMS relative accuracy, measurement
error and drift are outlined. CEMS installation and measurement
location specifications, and data reduction procedures are included.
Conformance of the CEMS with the Performance Specification is
determined.
3.0 Definitions
3.1 Continuous Emission Monitoring System (CEMS) means the total
equipment required for the determination of a pollutant
concentration. The system consists of the following major
subsystems:
3.2 Sample Interface means that portion of the CEMS used for one
or more of the following: sample acquisition, sample transport,
sample conditioning, and protection of the monitor from the effects
of the stack effluent.
3.3 Hg Analyzer means that portion of the CEMS that measures the
total vapor phase Hg mass concentration and generates a proportional
output.
3.4 Diluent Analyzer (if applicable) means that portion of the
CEMS that senses the diluent gas (CO2) and generates an
output proportional to the gas concentration.
3.5 Data Recorder means that portion of the CEMS that provides a
permanent electronic record of the analyzer output. The data
recorder can provide automatic data reduction and CEMS control
capabilities.
3.6 Span Value means the upper limit of the intended Hg
concentration measurement range. The span value is a value equal to
two times the emission standard.
3.7 Measurement Error (ME) means the difference between the
concentration indicated by the CEMS and the known concentration
generated by a reference gas when the entire CEMS, including the
sampling interface, is challenged. An ME test procedure is performed
to document the accuracy and linearity of the CEMS at several points
over the measurement range.
3.8 Upscale Drift (UD) means the difference in the CEMS output
responses to a Hg reference gas when the entire CEMS, including the
sampling interface, is challenged after a stated period of operation
during which no unscheduled maintenance, repair, or adjustment took
place.
3.9 Zero Drift (ZD) means the difference in the CEMS output
responses to a zero gas when the entire CEMS, including the sampling
interface, is challenged after a stated period of operation during
which no unscheduled maintenance, repair, or adjustment took place.
3.10 Relative Accuracy (RA) means the absolute mean difference
between the pollutant concentration(s) determined by the CEMS and
the value determined by the reference method (RM) plus the 2.5
percent error confidence coefficient of a series of tests divided by
the mean of the RM tests or the applicable emission limit.
4.0 Interferences [Reserved]
5.0 Safety
The procedures required under this performance specification may
involve hazardous materials, operations, and equipment. This
performance specification may not address all of the safety problems
associated with these procedures. It is the responsibility of the
user to establish appropriate safety and health practices and
determine the applicable regulatory limitations prior to performing
these procedures. The CEMS user's manual and materials recommended
by the reference method should be consulted for specific precautions
to be taken.
6.0 Equipment and Supplies
6.1 CEMS Equipment Specifications.
6.1.1 Data Recorder Scale. The CEMS data recorder output range
must include zero and a high level value. The high level value must
be approximately 2 times the Hg concentration corresponding to the
emission standard level for the stack gas under the circumstances
existing as the stack gas is sampled. If a lower high level value is
used, the CEMS must have the capability of providing multiple high
level values (one of which is equal to the span value) or be capable
of automatically changing the high level value as required (up to
specified high level value) such that the measured value does not
exceed 95 percent of the high level value.
6.1.2 The CEMS design should also provide for the determination
of response drift at both the zero and mid-level value. If this is
not possible or practical, the design must allow these
determinations to be conducted at a low-level value (zero to 20
percent of the high-level value) and at a value between 50 and 100
percent of the high-level value.
6.2 Reference Gas Delivery System. The reference gas delivery
system must be designed so that the flowrate of reference gas
introduced to the CEMS is the same at all three challenge levels
specified in Section 7.1 and at all times exceeds the flow
requirements of the CEMS.
[[Page 4717]]
6.3 Other equipment and supplies, as needed by the applicable
reference method used. See Section 8.6.2.
7.0 Reagents and Standards
7.1 Reference Gases.
7.1.1 Zero--N2 or Air. Less than 0.1 [mu]g Hg/
m3.
7.1.2 Mid-level Hg0 and HgCl2. 40 to 60
percent of span.
7.1.3 High-level Hg0 and HgCl2. 80 to 100
percent of span.
7.2 Reagents and Standards. May be required for the reference
methods. See Section 8.6.2.
8.0 Performance Specification Test Procedure
8.1 Installation and Measurement Location Specifications.
8.1.1 CEMS Installation. Install the CEMS at an accessible
location downstream of all pollution control equipment. Since the Hg
CEMS sample system normally extracts gas from a single point in the
stack, use a location that has been shown to be free of
stratification for SO2 and NOX through
concentration measurement traverses for those gases. If the cause of
failure to meet the RA test requirement is determined to be the
measurement location and a satisfactory correction technique cannot
be established, the Administrator may require the CEMS to be
relocated.
Measurement locations and points or paths that are most likely
to provide data that will meet the RA requirements are listed below.
8.1.2 Measurement Location. The measurement location should be
(1) at least eight equivalent diameters downstream of the nearest
control device, point of pollutant generation, bend, or other point
at which a change of pollutant concentration or flow disturbance may
occur, and (2) at least two equivalent diameters upstream from the
effluent exhaust. The equivalent duct diameter is calculated as per
40 CFR part 60, appendix A, Method 1.
8.1.3 Hg CEMS Sample extraction Point. Use a sample extraction
point (1) no less than 1.0 meter from the stack or duct wall, or (2)
within the centroidal velocity traverse area of the stack or duct
cross section.
8.2 Reference Method (RM) Measurement Location and Traverse
Points. The RM measurement location should be at a point or points
in the same stack cross sectional area as the CEMS is located,
according to the criteria above. The RM and CEMS locations need not
be immediately adjacent. They should be as close as possible without
causing interference with one another.
8.3 Measurement Error (ME) Test Procedure. The Hg CEMS must be
constructed to permit the introduction of known (NIST traceable)
concentrations of elemental mercury (Hg0) and mercuric
chloride (HgCl2) separately into the sampling system of
the CEMS immediately preceding the sample extraction filtration
system such that the entire CEMS can be challenged. Inject
sequentially each of the three reference gases (zero, mid-level, and
high level) for each Hg species. CEMS measurements of each reference
gas shall not differ from their respective reference values by more
than 5 percent of the span value. If this specification is not met,
identify and correct the problem before proceeding.
8.4 Upscale Drift (UD) Test Procedure.
8.4.1 UD Test Period. While the affected facility is operating
at more than 50 percent of normal load, or as specified in an
applicable subpart, determine the magnitude of the UD once each day
(at 24-hour intervals) for 7 consecutive days according to the
procedure given in Sections 8.4.2 through 8.4.3.
8.4.2 The purpose of the UD measurement is to verify the ability
of the CEMS to conform to the established CEMS response used for
determining emission concentrations or emission rates. Therefore, if
periodic automatic or manual adjustments are made to the CEMS zero
and response settings, conduct the UD test immediately before these
adjustments, or conduct it in such a way that the UD can be
determined.
8.4.3 Conduct the UD test at the mid-level point specified in
Section 7.1. Evaluate upscale drift for elemental Hg
(Hg0) only. Introduce the reference gas to the CEMS.
Record the CEMS response and subtract the reference value from the
CEM value (see example data sheet in Figure 12A-1).
8.5 Zero Drift (ZD) Test Procedure.
8.5.1 ZD Test Period. While the affected facility is operating
at more than 50 percent of normal load, or as specified in an
applicable subpart, determine the magnitude of the ZD once each day
(at 24-hour intervals) for 7 consecutive days according to the
procedure given in Sections 8.5.2 through 8.5.3.
8.5.2 The purpose of the ZD measurement is to verify the ability
of the CEMS to conform to the established CEMS response used for
determining emission concentrations or emission rates. Therefore, if
periodic automatic or manual adjustments are made to the CEMS zero
and response settings, conduct the ZD test immediately before these
adjustments, or conduct it in such a way that the ZD can be
determined.
8.5.3 Conduct the ZD test at the zero level specified in Section
7.1. Introduce the zero gas to the CEMS. Record the CEMS response
and subtract the zero value from the CEM value (see example data
sheet in Figure 12A-1).
8.6 Relative Accuracy (RA) Test Procedure.
8.6.1 RA Test Period. Conduct the RA test according to the
procedure given in Sections 8.6.2 through 8.6.6 while the affected
facility is operating at normal full load, or as specified in an
applicable subpart. The RA test can be conducted during the UD test
period.
8.6.2 Reference Method (RM). Unless otherwise specified in an
applicable subpart of the regulations, use either Method 29 in
appendix A to 40 CFR part 60, or ASTM Method D 6784-02 (incorporated
by reference in Sec. 60.17) as the RM for Hg. Do not include the
filterable portion of the sample when making comparisons to the CEMS
results. Conduct all RM tests with paired or duplicate sampling
systems.
8.6.3 Sampling Strategy for RM Tests. Conduct the RM tests in
such a way that they will yield results representative of the
emissions from the source and can be compared to the CEMS data. It
is preferable to conduct the diluent (if applicable), moisture (if
needed), and Hg measurements simultaneously. However, diluent and
moisture measurements that are taken within an hour of the Hg
measurements can be used to adjust the results to a consistent
basis. In order to correlate the CEMS and RM data properly, note the
beginning and end of each RM test period for each paired RM run
(including the exact time of day) on the CEMS chart recordings or
other permanent record of output.
8.6.4 Number and length of RM Tests. Conduct a minimum of nine
paired sets of all necessary RM test runs that meet the relative
standard deviation criteria of this PS. Use a minimum sample run
time of 2 hours for each pair.
Note: More than nine paired sets of RM tests can be performed.
If this option is chosen, test results can be rejected so long as
the total number of paired RM test results used to determine the
CEMS RA is greater than or equal to nine. However, all data must be
reported, including the rejected data.
8.6.5 Correlation of RM and CEMS Data. Correlate the CEMS and
the RM test data as to the time and duration by first determining
from the CEMS final output (the one used for reporting) the
integrated average pollutant concentration or emission rate for each
pollutant RM test period. Consider system response time, if
important, and confirm that the results are on a consistent
moisture, temperature, and diluent concentration basis with the
paired RM test. Then, compare each integrated CEMS value against the
corresponding average of the paired RM values.
8.6.6 Paired RM Outliers.
8.6.6.1 Outliers are identified through the determination of
precision and any systematic bias of the paired RM tests. Data that
do not meet this criteria should be flagged as a data quality
problem. The primary reason for performing dual RM sampling is to
generate information to quantify the precision of the RM data. The
relative standard deviation (RSD) of paired data is the parameter
used to quantify data precision. Determine RSD for two
simultaneously gathered data points as follows:
[GRAPHIC] [TIFF OMITTED] TP30JA04.002
[[Page 4718]]
where:
Ca and Cb are concentration values determined from trains A and B
respectively. For RSD calculation, the concentration units are
unimportant so long as they are consistent.
8.6.6.2 A minimum precision criteria for RM Hg data is that RSD
for any data pair must be [le]10 percent as long as the mean Hg
concentration is greater than 1.0 [mu]g/m3. If the mean
Hg concentration is less than or equal to 1.0 [mu]g/m3,
the RSD must be [le]20 percent. Pairs of RM data exceeding these RSD
criteria should be eliminated from the data set used to develop a Hg
CEMS correlation or to assess CEMS RA.
8.6.7 Calculate the mean difference between the RM and CEMS
values in the units of the emission standard, the standard
deviation, the confidence coefficient, and the RA according to the
procedures in Section 12.0.
8.7 Reporting. At a minimum (check with the appropriate EPA
Regional Office, State, or local Agency for additional requirements,
if any), summarize in tabular form the results of the RD tests and
the RA tests or alternative RA procedure, as appropriate. Include
all data sheets, calculations, charts (records of CEMS responses),
reference gas concentration certifications, and any other
information necessary to confirm that the performance of the CEMS
meets the performance criteria.
9.0 Quality Control [Reserved]
10.0 Calibration and Standardization [Reserved]
11.0 Analytical Procedure.
Sample collection and analysis are concurrent for this
Performance Specification (see Section 8.0). Refer to the RM
employed for specific analytical procedures.
12.0 Calculations and Data Analysis
Summarize the results on a data sheet similar to that shown in
Figure 2-2 for Performance Specification 2.
12.1 Consistent Basis. All data from the RM and CEMS must be on
a consistent dry basis and, as applicable, on a consistent diluent
basis. Correct the RM and CEMS data for moisture and diluent as
follows:
12.1.1 Moisture Correction (as applicable). Correct each wet RM
run for moisture with the corresponding Method 4 data; correct each
wet CEMS run using the corresponding CEMS moisture monitor date
using Equation 12A-2.
[GRAPHIC] [TIFF OMITTED] TP30JA04.003
12.1.2 Correction to Units of Standard (as applicable). Correct
each dry RM run to the units of the emission standard with the
corresponding Method 3B data; correct each dry CEMS run using the
corresponding CEMS diluent monitor data as follows:
12.1.3 Correct to Diluent Basis. The following is an example of
concentration (ppm) correction to 7 percent oxygen.
[GRAPHIC] [TIFF OMITTED] TP30JA04.004
The following is an example of mass/gross calorific value (lbs/
million Btu) correction.
lbs/MMBtu = Conc(dry) (F-factor) ((20.9/(20.9 - percent
O2))
12.2 Arithmetic Mean. Calculate the arithmetic mean of the
difference, d, of a data set as follows:
[GRAPHIC] [TIFF OMITTED] TP30JA04.005
Where:
n = Number of data points.
12.3 Standard Deviation. Calculate the standard deviation,
Sd, as follows:
[GRAPHIC] [TIFF OMITTED] TP30JA04.006
Where:
[GRAPHIC] [TIFF OMITTED] TP30JA04.007
12.4 Confidence Coefficient. Calculate the 2.5 percent error
confidence coefficient (one-tailed), CC, as follows:
[GRAPHIC] [TIFF OMITTED] TP30JA04.008
12.5 Relative Accuracy. Calculate the RA of a set of data as
follows:
[GRAPHIC] [TIFF OMITTED] TP30JA04.009
Where:
[bond]d[bond] = Absolute value of the mean differences (from
Equation 12A-4).
[bond]CC[bond] = Absolute value of the confidence coefficient (from
Equation 12A-6).
RM = Average RM value. In cases where the average emissions for the
test are less than 50 percent of the applicable standard, substitute
the emission standard value in the denominator of Eq. 12A-7 in place
of RM. In all other cases, use RM.
13.0 Method Performance.
13.1 Measurement Error (ME). ME is assessed at mid-level and
high-level values as given below using standards for both
Hg0 and HgCl2. The mean difference between the
indicated CEMS concentration and the reference concentration value
for each standard shall be no greater than 5 percent of span. The
same difference for the zero reference gas shall be no greater than
5 percent of span.
13.2 Upscale Drift (UD). The CEMS design must allow the
determination of UD of the analyzer. The CEMS response can not drift
or deviate from the benchmark value of the reference standard by
more than 5 percent of span for the mid level value. Evaluate
upscale drift for Hg0 only.
13.3 Zero Drift (ZD). The CEMS design must allow the
determination of drift at the
[[Page 4719]]
zero level. This drift shall not exceed 5 percent of span.
13.4 Relative Accuracy (RA). The RA of the CEMS must be no
greater than 20 percent of the mean value of the RM test data in
terms of units of the emission standard, or 10 percent of the
applicable standard, whichever is greater.
14.0 Pollution Prevention. [Reserved]
15.0 Waste Management. [Reserved]
16.0 Alternative Procedures. [Reserved]
17.0 Bibliography.
17.1 40 CFR part 60, appendix B, ``Performance Specification 2--
Specifications and Test Procedures for SO2 and
NOX Continuous Emission Monitoring Systems in Stationary
Sources.''
17.2 40 CFR part 60, appendix A, ``Method 29--Determination of
Metals Emissions from Stationary Sources.''
17.3 ASTM Method D6784-02, ``Standard Test Method for Elemental,
Oxidized, Particle-Bound and Total Mercury in Flue Gas Generated
from Coal-Fired Stationary Sources (Ontario Hydro Method).''
18.0 Tables and Figures
Table 12A-1.--t-Values
----------------------------------------------------------------------------------------------------------------
n \a\ t 0.975 n a t 0.975 n a t 0.975
----------------------------------------------------------------------------------------------------------------
2.............................................. 12.706 7 2.447 12 2.201
3.............................................. 4.303 8 2.365 13 2.179
4.............................................. 3.182 9 2.306 14 2.160
5.............................................. 2.776 10 2.262 15 2.145
6.............................................. 2.571 11 2.228 16 2.131
----------------------------------------------------------------------------------------------------------------
\a\ The values in this table are already corrected for n-1 degrees of freedom. Use n equal to the number of
individual values.
------------------------------------------------------------------------
CEMS
Day Date and Reference value Measurement Drift
time value (C) (M) error
------------------------------------------------------------------------
Zero
Level
-----------
-----------
-----------
-----------
Mid-
level
-----------
-----------
=========
High-
level
-----------
-----------
-----------
Figure 12A-1. Zero and Upscale Drift Determination.
PART 63--[AMENDED]
4. The authority citation for part 63 continues to read as follows:
Authority: 42 U.S.C. 7401, et seq.
5. Section 63.14 is amended by adding paragraph (b)(35) to read as
follows:
Sec. 63.14 Incorporations by Reference.
* * * * *
(b) * * *
(35) ASTM D6784-02, Standard Test Method for Elemental, Oxidized,
Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired
Stationary Sources (Ontario Hydro Method), for appendix B to part 63,
Method 324.
* * * * *
6. Part 63 is amended by adding subpart UUUUU to read as follows:
Subpart UUUUU--National Emission Standards for Hazardous Air
Pollutants for Coal-or Oil-Fired Electric Utility Steam Generating
Units
Sec.
What This Subpart Covers
63.9980 What is the purpose of this subpart?
63.9981 Am I subject to this subpart?
63.9982 What parts of my facility does this subpart cover?
63.9983 When do I have to comply with this subpart?
Emissions Limitations
63.9990 What emissions limitations must I meet for coal-fired
electric utility steam generating units?
63.9991 What emissions limitations must I meet for oil-fired
electric utility steam generating units?
63.9992 What are my compliance options for multiple affected
sources?
General Compliance Requirements
63.10000 What are my general requirements for complying with this
subpart?
Initial Compliance Requirements
63.10005 By what date must I conduct performance tests or other
initial compliance demonstrations?
63.10006 When must I conduct subsequent performance tests?
63.10007 What performance test procedures must I use?
63.10008 What are my monitoring, installation, operation, and
maintenance requirements?
63.10009 How do I demonstrate initial compliance with the emissions
limitations?
Continuous Compliance Requirements
63.10020 How do I monitor and collect data to demonstrate continuous
compliance?
63.10021 How do I demonstrate continuous compliance with the
emissions limitations?
[[Page 4720]]
Notifications, Reports, and Records
63.10030 What notifications must I submit and when?
63.10031 What reports must I submit and when?
63.10032 What records must I keep?
63.10033 In what form and how long must I keep my records?
Other Requirements and Information
63.10040 What parts of the General Provisions apply to me?
63.10041 Who implements and enforces this subpart?
63.10042 What definitions apply to this subpart?
Tables to Subpart UUUUU of Part 63
Table 1 to Subpart UUUUU of Part 63--Performance Test Requirements
for Ni and Hg
Table 2 to Subpart UUUUU of Part 63--Initial Compliance With
Emissions Limitations for Ni and Hg
Table 3 to Subpart UUUUU of Part 63--Continuous Compliance with
Emissions Limitations for Hg and Ni
Table 4 to Subpart UUUUU of Part 63--Applicability of General
Provisions to Subpart UUUUU
What This Subpart Covers
Sec. 63.9980 What is the purpose of this subpart?
This subpart establishes national emissions limitations for
hazardous air pollutants (HAP) emitted from coal-fired electric utility
steam generating units and oil-fired electric utility steam generating
units. This subpart also establishes requirements to demonstrate
initial and continuous compliance with the emissions limitations.
Sec. 63.9981 Am I subject to this subpart?
You are subject to this subpart if you own or operate a coal-fired
electric utility steam generating unit or an oil-fired electric utility
steam generating unit.
Sec. 63.9982 What parts of my facility does this subpart cover?
(a) The affected source is each group of one or more coal- or oil-
fired electric utility steam generating units located at a facility. An
electric utility steam generating unit that combusts natural gas at
greater than or equal to 98 percent of the unit's annual fuel
consumption is not an affected source under this subpart.
(b) A coal or oil-fired electric utility steam generating unit is a
new affected source if you commenced construction of the unit after
January 30, 2004.
(c) An affected source is reconstructed if you meet the criteria as
defined in Sec. 63.2. An existing electric utility steam generating
unit that is switched completely to burning a different coal rank or
fuel type is considered to be an existing affected source under this
subpart.
(d) An affected source is existing if it is not new or
reconstructed.
Sec. 63.9983 When do I have to comply with this subpart?
(a) If you have a new or reconstructed affected source, you must
comply with this subpart according to paragraph (a) (1) or (2) of this
section.
(1) If you start up your affected source before [DATE THE FINAL
RULE IS PUBLISHED IN THE Federal Register], then you must comply with
the emissions limitations and work practice standards for new and
reconstructed sources in this subpart no later than [DATE THE FINAL
RULE IS PUBLISHED IN THE Federal Register].
(2) If you startup your affected source on or after [DATE THE FINAL
RULE IS PUBLISHED IN THE Federal Register], then you must comply with
the emissions limitations and work practice standards for new and
reconstructed sources in this subpart upon startup of your affected
source.
(b) If you have an existing affected source, you must comply with
the emissions limitations for existing sources no later than 3 years
after [DATE THE FINAL RULE IS PUBLISHED IN THE Federal Register].
(c) You must meet the notification requirements according to the
schedule applicable to your facility as specified in Sec. 63.10300 and
in subpart A of this part. Some of the notifications must be submitted
before you are required to comply with the emissions limitations in
this subpart.
Emissions Limitations
Sec. 63.9990 What emissions limitations must I meet for coal-fired
electric utility steam generating units?
(a) For each coal-fired electric utility steam generating unit
other than an integrated gasification combined-cycle (IGCC) electric
utility steam generating unit, you must meet the mercury (Hg) emissions
limit in paragraphs (a)(1) through (5) of this section that applies to
your unit. The Hg emissions limits in paragraphs (a)(1) through (5) of
this section are based on a 12-month rolling average using the
procedures in Sec. 63.10009.
(1) For each coal-fired electric utility steam generating unit that
burns only bituminous coal, you must meet the Hg emissions limit in
either paragraph (a)(1)(i) or (ii) of this section that applies to you.
(i) You must not discharge into the atmosphere from an existing
affected source any gases which contain Hg in excess of 2.0 pound per
trillion British thermal unit (lb/TBtu) on an input basis or 21 x
10-6 pound per Megawatt hour (lb/MWh) on an output basis.
(ii) You must not discharge into the atmosphere any gases from a
new affected source which contain Hg in excess of 6.0 x 10-6
lb/MWh on an output basis.
(2) For each coal-fired electric utility steam generating unit that
burns only subbituminous coal, you must meet the Hg emissions limit in
either paragraph (a)(2)(i) or (ii) of this section that applies to you.
(i) You must not discharge into the atmosphere any gases from an
existing affected source which contain Hg in excess of 5.8 lb/TBtu on
an input basis or 61 x 10-6 lb/MWh on an output basis.
(ii) You must not discharge into the atmosphere any gases from a
new affected source which contain Hg in excess of 20 x 10-6
lb/MWh on an output basis.
(3) For each coal-fired electric utility steam generating unit that
burns only lignite coal, you must meet the Hg emissions limit in either
paragraph (a)(3)(i) or (ii) of this section that applies to you.
(i) You must not discharge into the atmosphere any gases from an
existing affected source which contain Hg in excess of 9.2 lb/TBtu on
an input basis or 98 x 10-6 lb/MWh on an output basis.
(ii) You must not discharge into the atmosphere any gases from a
new affected source which contain Hg in excess of 62 x 10-6
lb/MWh on an output basis.
(4) For each coal-burning electric utility steam generating unit
that burns only coal refuse, you must meet the Hg emissions limit in
either paragraph (a)(4)(i) or (ii) of this section that applies to you.
(i) You must not discharge into the atmosphere any gases from an
existing affected source which contain Hg in excess of 0.38 lb/TBtu on
an input basis or 4.1 x 10-6 lb/MWh on an output basis.
(ii) You must not discharge into the atmosphere any gases from a
new affected source which contain Hg in excess of 1.1 x 10-6
lb/MWh on an output basis.
(5) For each coal-fired electric utility steam generating unit that
burns a blend of coals from different coal ranks (i.e., bituminous
coal, subbituminous coal, lignite) or a blend of coal and coal refuse,
you must not discharge into the atmosphere any gases from a new or
existing affected source that contain Hg in excess of the monthly unit-
specific Hg emissions limit established
[[Page 4721]]
according to paragraph (a)(5)(i) or (ii) of this section, as applicable
to your unit.
(i) If you operate a coal-fired electric utility steam generating
unit that burns a blend of coals from different coal ranks or a blend
of coal and coal refuse, you must not discharge into the atmosphere any
gases from a new or existing affected source that contain Hg in excess
of the computed weighted Hg emissions limit based on the proportion of
energy output (in Btu) contributed by each coal type burned during the
compliance period and its applicable Hg emissions limit in paragraphs
(a)(1) through (4) of this section as determined using Equation 1 of
this section. You must meet the weighted Hg emissions limit calculated
using Equation 1 of this section by calculating the unit emission rate
based on the total Hg loading of the unit and the total Btu or megawatt
hours contributed by all fuels burned during the compliance period.
[GRAPHIC] [TIFF OMITTED] TP30JA04.010
Where:
ELb = Total allowable Hg in lb/MWh (or lb/TBtu) that can be
emitted to the atmosphere from any affected source being averaged under
the blending provision.
ELi = Hg emissions limit for the subcategory that applies to
affected source i, lb/MWh (or lb/TBtu).
HHi = Heat input to, or electricity output from, affected
source i during the production period related to the corresponding H
i that falls within the compliance period, gross MWh
generated or MMBtu heat input to the electric utility steam generating
unit.
n = Number of coal ranks being averaged for an affected source.
(ii) If you operate a coal-fired electric utility steam generating
unit that burns a blend of coals from different coal ranks or a blend
of coal and coal refuse together with one or more non-regulated,
supplementary fuels, you must not discharge into the atmosphere any
gases from the unit that contain Hg in excess of the computed weighted
Hg emission limit based on the proportion of energy output (in Btu)
contributed by each coal type burned during the compliance period and
its applicable Hg emissions limit in paragraphs (a)(1) through (4) of
this section as determined using Equation 1 of this section. You must
meet the weighted Hg emissions limit calculated using Equation 1 of
this section by calculating the unit emission rate based on the total
Hg loading of the unit and the total Btu or megawatt hours contributed
by both regulated and nonregulated fuels burned during the compliance
period.
(b) For each IGCC electric utility steam generating unit, you must
meet the Hg emissions limit in either paragraph (b)(1) or (2) of this
section that applies to you. The Hg emissions limits in this paragraph
are based on a 12-month rolling average using the procedures in Sec.
63.10009.
(1) You must not discharge into the atmosphere any gases from an
existing affected source which contain Hg in excess of 19 lb/TBtu on an
input basis or 200 x 10-6 lb/MWh on an output basis.
(2) You must not discharge into the atmosphere any gases from a new
affected source which contain Hg in excess of 20 x 10-6 lb/
MWh on an output basis.
Sec. 63.9991 What emissions limitations must I meet for oil-fired
electric utility steam generating units?
(a) For each oil-fired electric utility steam generating unit, you
must meet the nickel (Ni) emissions limit in paragraphs (a)(1) and (2)
of this section that applies to you, except as provided in paragraph
(b) of this section.
(1) You must not discharge into the atmosphere any gases from an
existing affected source which contain Ni in excess of 210 lb/TBtu on
an input basis or 0.002 lb/MWh on an output basis.
(2) You must not discharge into the atmosphere any gases from a new
affected source which contain Ni in excess of 0.0008 lb/MWh on an
output basis.
(b) The emissions limit in paragraph (a) of this section does not
apply to a new or existing oil-fired electric utility steam generating
unit if during the reporting period, to burn 98 percent or more
distillate oil exclusively as the fuel for the unit. The emissions
limit in paragraph (a) of this section will apply immediately if you
subsequently burn a fuel other than distillate oil in the unit.
(c) If you use an electrostatic precipitator (ESP) to meet the
applicable Ni emissions limit, you must operate the ESP such that the
hourly average voltage and secondary current (or total power input) do
not fall below the limit established in the initial or subsequent
performance test.
(d) If you use a control device or combination of control devices
other than an ESP to meet the applicable Ni emissions limit, or you
wish to establish and monitor an alternative operating limit and
alternative monitoring parameters for an ESP, you must apply to the
Administrator for approval of alternative monitoring under Sec.
63.8(f).
Sec. 63.9992 What are my compliance options for multiple affected
sources?
(a) If you have two or more coal-fired electric utility steam
generating units at your facility that are subject to Hg emission
limits in Sec. 63.9990, you may choose to use the emissions averaging
compliance approach specified in paragraph (b) of this section as an
alternative to complying with the applicable Hg emission limits for
each individual unit. You may use emissions averaging only under the
conditions specified in paragraphs (a)(1) and (2) of this section.
(1) The emissions averaging compliance approach is applicable to
coal-fired electric utility steam generating units subject to the Hg
emission limits for existing affected sources under this subpart that
are located at a common contiguous facility. The emissions averaging
compliance approach is also applicable to coal-fired electric utility
stream generating units subject to the Hg emission limits for new
affected sources under this subpart as long as they meet the new source
limits specified under this subpart.
(2) All of the Hg emission limits used for the emissions averaging
compliance approach must meet the applicable limits expressed in the
same format (i.e., all of the Hg emission limits must be either the
applicable lb/TBtu limit values or the applicable lb/MWh limit values).
(b) If you choose to use the emissions averaging compliance
approach, you must meet the requirements specified in paragraphs (b)(1)
through (5) of this section.
(1) You must designate your emissions averaging source group by
identifying each of the existing coal-fired electric utility stream
generating units at your facility site to be included in your emissions
averaging source group.
(2) You must designate a common Hg emissions limit format to be
used for all of the coal-fired electric utility stream generating units
in your designated emissions averaging source group (either the lb/TBtu
limit format or the lb/MWh limit format).
(3) You must determine the Hg emissions limit value in Sec. 63.9990
for your selected format that is applicable to each of the individual
coal-fired electric utility stream generating units in your designated
emissions averaging source group.
(4) You must calculate the unit-specific Hg emissions limit for
your
[[Page 4722]]
designated emissions averaging source group using Equation 1 of this
section.
[GRAPHIC] [TIFF OMITTED] TP30JA04.011
Where:
AvEL = Total allowable Hg that can be emitted to the atmosphere from
all emission sources in the emissions averaging group, lb/MWh or lb/
TBtu;
Li = Hg emissions limit for the subcategory that applies to
emission source i or the calculated emissions limit derived for an
emissions averaging group using Equation 1 of this section, lb/MWh or
lb/MMBtu;
Vi = Volume of production for emissions source i during the
production period related to the corresponding Li that falls
within the 12-month compliance period, gross MWh generated or MMBtu
heat input to the electric utility steam generating unit; and
n = Number of emissions sources being averaged. This number may apply
to individual emissions sources or emissions averaging groups.
(5) You must not discharge into the atmosphere any gases from your
designated emissions averaging group that contain Hg in excess of the
unit-specific Hg emissions limit established according to paragraph
(b)(4) of this section as determined based on a 12-month rolling
average using the procedures in Sec. 63.10009.
(c) You may use the emissions averaging compliance approach or
revise an existing emissions averaging group at any time after the
compliance date by submitting an emissions averaging plan or revision,
respectively, using the title V operating permit amendment process
specified by the regulating authority. The emissions averaging plan
must contain the information specified in paragraphs (c)(1) and (2) of
this section.
(1) Identification of each coal-fired electric utility steam
generating unit in your designated emissions averaging group and the
applicable Hg emissions limit for each unit as determined in paragraph
(b) of this section.
(2) The Hg emissions limit for your designated emissions averaging
group as determined in paragraph (b) of this section, including all
calculations and supporting information.
General Compliance Requirements
Sec. 63.10000 What are my general requirements for complying with this
subpart?
(a) You must be in compliance with the emissions limitations
(including operating limits) in this subpart at all times, except
during periods of startup, shutdown, and malfunction.
(b) You must always operate and maintain your affected source,
including air pollution control and monitoring equipment, according to
the provisions in Sec. 63.6(e)(1)(i).
(c) For each monitoring system required by this subpart, you must
develop and submit to the Administrator for approval a unit-specific
monitoring plan according to the requirements in Sec. 63.10008(f).
(d) You must conduct a performance evaluation of each continuous
monitoring system (CMS) in accordance with your unit-specific
monitoring plan.
(e) You must operate and maintain the CMS in continuous operation
according to the unit-specific monitoring plan.
(f) You must develop and implement a written startup, shutdown, and
malfunction plan (SSMP) according to the provisions in Sec. 63.6(e)(3).
Initial Compliance Requirements
Sec. 63.10005 By what date must I conduct performance tests or other
initial compliance demonstrations?
(a) For each existing affected source, you must conduct performance
tests, set operating limits, and conduct monitoring equipment
performance evaluations, as applicable to your source, by the
compliance date that is specified for your source in Sec. 63.9983 and
according to the applicable provisions in Sec. 63.7(a)(2).
(b) For each new affected source, you must conduct performance
tests, set operating limits, and conduct monitoring equipment
performance evaluations, as applicable to your source, within 180 days
after the compliance date that is specified for your source in Sec.
63.9983 and according to the provisions in Sec. 63.7(a)(2).
Sec. 63.10006 When must I conduct subsequent performance tests?
For each affected oil-fired electric utility steam generating units
subject to a Ni emissions limit in this subpart, you must conduct a
subsequent performance test at least once each year to demonstrate
compliance and include the results in the next semiannual compliance
report.
Sec. 63.10007 What performance test procedures must I use?
(a) For each affected oil-fired electric utility steam generating
unit subject to a Ni emissions limit under this subpart, you must
conduct each performance test to demonstrate compliance with the
applicable emissions limit according to the requirements in paragraphs
(a)(1) through (4) of this section.
(1) You must conduct each performance test according to Sec.
63.7(c), (d), (f), and (h) and the procedures in Table 1 to this
subpart. You must also develop a site-specific test plan according to
the requirements in Sec. 63.7(c).
(2) You must conduct each performance test at the representative
process operating conditions that are expected to result in the highest
emissions of Ni, and you must demonstrate initial compliance and
establish your operating limits based on this test.
(3) You may not conduct performance tests during periods of
startup, shutdown, or malfunction.
(4) You must conduct three separate test runs for each performance
test required in this section, as specified in Sec. 63.7(e)(3). Each
test run must last at least 1 hour.
(b) You must submit a Notification of Compliance Status report
containing the results of the initial or annual compliance
demonstration according to the requirements in Sec. 63.10031(b).
Sec. 63.10008 What are my monitoring, installation, operation, and
maintenance requirements?
(a) If you use an ESP to meet a Ni limit in this subpart, you must
install and operate a continuous parameter monitoring system (CPMS) to
measure and record the voltage and secondary current (or total power
input) to the control device.
(b) You must install, operate, and maintain each CPMS by the
compliance date specified in Sec. 63.9983 according to the requirements
in paragraphs (b)(1) through (3) of this section.
(1) Each CPMS must complete a minimum of one cycle of operation for
each successive 15-minute period. You must have a minimum of four
successive cycles of operation to have a valid hour of data.
(2) Each CPMS must determine the 1-hour block average of all
recorded readings.
(3) You must record the results of each inspection, calibration,
and validation check for a CPMS.
(c) You must install and operate a continuous emissions monitoring
system (CEMS) to measure and record
[[Page 4723]]
the concentration of Hg in the exhaust gases from each stack.
(d) You must install, operate, and maintain each CEMS by the
compliance date specified in Sec. 63.9983 according to the requirements
in paragraphs (d)(1) through (4) of this section.
(1) You must install, operate, and maintain each CEMS according to
Performance Specification 12A in 40 CFR part 60, appendix B.
(2) You must conduct a performance evaluation of each CEMS
according to the requirements of Sec. 63.8 and Performance
Specification 12A in 40 CFR part 60, appendix B. id.
(3) You must operate each CEMS according to the requirements in
paragraphs (d)(3)(i) through (iv) of this section.
(i) As specified in 63.8(c)(4)(ii), each CEMS must complete a
minimum of one cycle of operation (sampling, analyzing, and data
recording) for each successive 15-minute period.
(ii) You must reduce CEMS data as specified in Sec. 63.8(g)(2).
(iii) Each CEMS must determine and record the 1 hour average
emissions using all the hourly averages collected for periods during
which the CEMS is not out of control.
(iv) You must record the results of each inspection, calibration,
and validation check.
(4) The provisions in paragraphs (d)(4)(i) through (iv) of this
section apply to data collection periods for your Hg CEMS.
(i) A complete day of data for continuous monitoring is 18 hours or
more in a 24-hour period.
(ii) A complete month of data for continuous monitoring is 21 days
or more in a calendar month.
(iii) If you collect less than 21 days of continuous emissions
data, you must discard the data collected that month and replace that
data with the mean of the individual monthly emission rate values
determined in the last 12 months.
(iv) If you collect less than 21 days per monthly period of
continuous data again in that same 12-month rolling average cycle, you
must discard the data collected that month and replace that data with
the highest individual monthly emission rate determined in the last 12
months.
(e) As an alternative to the CEMS required in paragraph (c) of this
section, the owner or operator must monitor Hg emissions using Method
324 in 40 CFR part 63, appendix A.
(f) You must prepare and submit to the Administrator for approval a
unit-specific monitoring plan for each monitoring system. You must
comply with the requirements in your plan. The plan must address the
requirements in paragraphs (f)(1) through (6) of this section.
(1) Installation of the CMS sampling probe or other interface at a
measurement location relative to each affected process unit such that
the measurement is representative of control of the exhaust emissions
(e.g., at or downstream of the last control device);
(2) Performance and equipment specifications for the sample
interface, the pollutant concentration or parametric signal analyzer,
and the data collection and reduction systems;
(3) Performance evaluation procedures and acceptance criteria
(e.g., calibrations);
(4) Ongoing operation and maintenance procedures in accordance with
the general requirements of Sec. 63.8(c)(1), (3), and (4)(ii);
(5) Ongoing data quality assurance procedures in accordance with
the general requirements of Sec. 63.8(d); and
(6) Ongoing recordkeeping and reporting procedures in accordance
with the general requirements of Sec. 63.10(c), (e)(1) and (e)(2)(i).
(g) Quarterly accuracy determinations and daily calibration drift
tests for gaseous Hg CEMS shall be performed in accordance with
Procedure 1 (appendix F of 40 CFR part 60). Annual relative accuracy
test audits (RATAs) for Hg sorbent trap monitoring systems shall also
be performed in accordance with Procedure 1.
Sec. 63.10009 How do I demonstrate initial compliance with the
emissions limitations?
(a) You must demonstrate initial compliance with each emission
limitation in Sec. 63.9990 that applies to you according to Table 2 to
this subpart.
(b) If you elect to comply with an emissions limit using emissions
averaging according to the requirements in Sec. 63.9992, you must
demonstrate compliance with the emissions limit established for each
emissions averaging group for the 12-month compliance period using
Equation 1 of this section.
[GRAPHIC] [TIFF OMITTED] TP30JA04.012
Where:
AvH = Total Hg emitted for the 12-month compliance period, lb/MWh or
lb/MMBtu;
Hi = Total mass of measured Hg from AvEL emissions averaging
group i during the 12-month compliance period, lb;
Vi = Total volume of production from AvEL emissions
averaging group i during 12-month compliance period, gross MWh
generated or MMBtu heat input to the electric utility steam generating
unit; and
n = Number of emission sources in the emissions averaging group or
number of emission averaging groups.
(c) If your affected electric utility steam generating unit is also
a cogeneration unit, you must use the procedures in paragraphs (c)(1)
and (2) of this section to calculate emission rates based on electrical
output to the grid plus half of the equivalent electrical energy in the
unit's process stream.
(1) All conversions from Btu/hr unit input to MWe unit output must
use equivalents found in 40 CFR part 60.40(a)(1) for electric utilities
(i.e., 250 million Btu/hr input to an electric utility steam generating
unit is equivalent to 73 MWe input to the electric utility steam
generating unit); 73 MWe input to the electric utility steam generating
unit is equivalent to 25 MWe output from the boiler electric utility
steam generating unit; therefore, 250 million Btu input to the electric
utility steam generating unit is equivalent to 25 MWe output from the
electric utility steam generating unit).
(2) You must use the Equation 2 of this section to determine the
cogeneration Hg or Ni emission rate over a specific compliance period.
[GRAPHIC] [TIFF OMITTED] TP30JA04.013
[[Page 4724]]
Where:
ERcogen = Cogeneration Hg or Ni emission rate over a
compliance period in lb/MWh (or lb Hg/TBtu);
E = Mass of Hg or Ni emitted from the stack over the same compliance
period (lb Hg or lb Ni);
Vgrid = Amount of energy sent to the grid over the same
compliance period (MWh or TBtu); and
Vprocess = Amount of energy converted to steam for process
use over the same compliance period (MWh or TBtu).
(d) If your coal-fired electric utility steam generating unit is
subject to an Hg limit in Sec. 63.9990, you must determine initial
compliance according to the applicable requirements in paragraphs
(d)(1) through (4) of this section.
(1) Begin compliance monitoring on the effective date of this
subpart.
(2) If you use a CEMS, determine the 12-month rolling average Hg
emission rate according to the applicable procedures in paragraphs
(d)(2)(i) through (iii) of this section.
(i) Calculate the total mass of Hg emissions over a month (M), in
micrograms ([mu]g), using Equation 3 of this section.
[GRAPHIC] [TIFF OMITTED] TP30JA04.014
Where:
M = Total mass of Hg emissions, ([mu]g);
C = Concentration of Hg recorded by CEMS per Performance Specification
12A, micrograms per dry standard cubic meter ([mu]g/dscm);
V = Volumetric flow rate recorded at the same frequency as the CEMS
reading for the Hg concentration indicated in Performance Specification
12A, cubic meters per hour (dscm/hr); and
t = total time period over which mass measurements are collected, (hr).
(ii) Calculate the Hg emission rate for an input-based limit (lb/
TBtu) using Equation 4 of this section.
[GRAPHIC] [TIFF OMITTED] TP30JA04.015
Where:
ER = Hg emission rate, (lb/TBtu);
M = Total mass of Hg emissions, micrograms ([mu]g);
Conversion factor = 2.205 x 10\-9\, used to convert micrograms to
pounds; and
TPinput-based = Total power, (TBtu).
(iii) Calculate the Hg emission rate for an output-based limit (lb/
MWh) using Equation 5 of this section:
[GRAPHIC] [TIFF OMITTED] TP30JA04.016
Where:
ER = Hg emission rate, (lb/MWh);
M = Total mass of Hg emissions, ([mu]g);
Conversion factor = 2.205 x 10\-9\; and
TPoutput-based = Total power, megawatt-hours (MWh).
(3) If you use Method 324 (40 CFR part 63, appendix A), determine
the 12-month rolling average Hg emission rate according to the
applicable procedures in paragraphs (d)(3)(i) through (v) of this
section.
(i) Sum the Hg concentrations for the emission rate period, ([mu]g/
dscm).
(ii) Calculate the total volumetric flow for the emission rate
period, (dscm).
(iii) Multiply the total Hg concentration times the total
volumetric flow to obtain the total mass of Hg for the emissions rate
period in micrograms.
(iv) Calculate the Hg emissions rate for an input-based limit (lb/
TBtu) using Equation 4 of this section.
(v) Calculate the Hg emissions rate for an output-based limit (lb/
MWh) using Equation 5 of this section.
(4) Report the 12-month rolling average Hg emissions rate in the
first semiannual compliance report.
(e) If your oil-fired unit is subject to a Ni emissions limit in
Sec. 63.9991, you must determine initial compliance using the
applicable procedures in paragraphs (e)(1) through (3) of this section.
(1) Begin compliance monitoring on the effective date of this
subpart.
(2) Use the applicable procedures in paragraphs (e)(2)(i) through
(v) of this section to convert the Method 29 Ni measurement to the
selected format.
(i) Sum the Ni concentrations obtained from the Method 29 test
runs, milligrams per dscm (mg/dscm).
(ii) Calculate the total volumetric flow obtained during the Method
29 test runs, (dscm).
(iii) Multiply the total Ni concentration times the total
volumetric flow for the duration of the initial compliance testing
period to obtain the total mass of Ni in milligrams.
(iv) Calculate the input-based Ni emissions rate in a lb/TBtu
format using Equation 6 of this section.
[GRAPHIC] [TIFF OMITTED] TP30JA04.017
Where:
ER = Ni emissions rate, (lb/TBtu);
M = Total mass of Ni emissions, (mg);
Conversion factor = 2.205 x 10-6, used to convert milligrams
to pounds; and
TPinput-based = Total power, (TBtu).
(v) Calculate the output-based Ni emissions rate in a lb/MWh format
using Equation 7 of this section.
[GRAPHIC] [TIFF OMITTED] TP30JA04.018
Where:
ER = Ni emissions rate, (lb/MWh);
M = Total mass of Ni emissions, (mg);
Conversion factor = 2.205 x 10-6 and
TPoutput-based = Total power, (MWH).
(f) You must submit the Notification of Compliance Status report
containing the results of the initial compliance demonstration
according to the requirements in Sec. 63.10030(e).
Continuous Compliance Requirements
Sec. 63.10020 How do I monitor and collect data to demonstrate
continuous compliance?
(a) Except for monitor malfunctions, associated repairs, and
required quality assurance or control activities (including, as
applicable, calibration checks and required zero and span adjustments),
you must monitor continuously (or collect data at all required
intervals) at all times that the affected source is operating.
(b) You may not use data recorded during monitoring malfunctions,
associated repairs, or required quality assurance or control
activities, in data averages and calculations used to report emission
or operating levels. You must use all the data collected during all
other periods in assessing the operation of the control device and
associated control system.
(c) A monitoring malfunction is any sudden, infrequent, not
reasonably preventable failure of the monitoring system to provide
valid data. Monitoring failures that are caused in part by poor
maintenance or careless operation are not malfunctions. Any period for
which the monitoring system is out-of-control and data are not
available for required calculations constitutes a deviation from the
monitoring requirements.
Sec. 63.10021 How do I demonstrate continuous compliance with the
emissions limitations?
(a) You must demonstrate continuous compliance with each emission
limitation that applies to you according to the methods specified in
Table 3 to this subpart.
(b) During periods of startup, shutdown, and malfunction, you must
operate in accordance with the startup, shutdown, and malfunction plan
as required in Sec. 63.10000(f).
(c) Consistent with Sec.Sec. 63.6(e) and 63.7(e)(1), deviations
that occur during
[[Page 4725]]
a period of startup, shutdown, or malfunction are not violations if you
demonstrate to the Administrator's satisfaction that you were operating
in accordance with the startup, shutdown, and malfunction plan. The
Administrator will determine whether deviations that occur during a
period of startup, shutdown, or malfunction are violations, according
to the provisions in Sec. 63.6(e).
Notification, Reports, and Records
Sec. 63.10030 What notifications must I submit and when?
(a) You must submit all of the notifications in Sec.Sec. 63.6(h)(4)
and (5), 63.7(b) and (c), 63.8(e), 63.8(f)(4) and (6), and 63.9(b)
through (h) that apply to you by the dates specified. Except as
provided in paragraph (f) of this section, if you comply with the
requirements in Sec. 63.9991(b) for switching fuel, you must notify the
Administrator in writing at least 30 days prior to using a fuel other
than distillate oil.
(b) As specified in Sec. 63.9(b)(2), if you operate an affected
source before [DATE OF PUBLICATION OF THE FINAL RULE IN THE Federal
Register], you must submit an Initial Notification not later than 120
days after [DATE THE FINAL RULE IS PUBLISHED IN THE Federal Register].
The Initial Notification must include the information required in
paragraphs (b)(1) through (4) of this section, as applicable.
(1) The name and address of the owner or operator;
(2) The address (i.e., physical location) of the affected source;
(3) An identification of the relevant standard, or other
requirement, that is the basis of the notification and the source's
compliance date;
(4) A brief description of the nature, size, design and method of
operation of the source and an identification of the types of emission
points within the affected source subject to the requirements and the
Hg or Ni pollutant being emitted.
(c) If you startup your new or reconstructed affected source on or
after [DATE THE FINAL RULE IS PUBLISHED IN THE Federal Register], you
must submit an Initial Notification not later than 120 days after you
become subject to this subpart. The Initial Notification must include
the information required in paragraphs (c)(1) through (4) of this
section, as applicable.
(1) The name and address of the owner or operator;
(2) The address (i.e., physical location) of the affected source;
(3) An identification of the relevant standard, or other
requirement, that is the basis of the notification and the source's
compliance date;
(4) A brief description of the nature, size, design and method of
operation of the source and an identification of the types of emission
points within the affected source subject to the requirements and the
Hg or Ni pollutant being emitted.
(d) If you are required to conduct a performance test, you must
submit a notification of intent to conduct a performance test at least
60 days before the performance test is scheduled to begin as required
in Sec. 63.7(b)(1).
(e) If you are required to conduct a performance test or other
initial compliance demonstration as specified in Sec. 63.10007, you
must submit a Notification of Compliance Status report according to
Sec. 63.9(h)(2)(ii) and the requirements specified in paragraphs (e)(1)
through (3) of this section.
(1) For each initial compliance demonstration, you must submit the
Notification of Compliance Status report, including all performance
test results, before the close of business on the 60th day following
the completion of the performance test and/or other initial compliance
demonstrations according to Sec. 63.10(d)(2).
(2) The Notification of Compliance Status report must contain all
the information specified in paragraphs (e)(2)(i) through (iv) of this
section, as applicable.
(i) A description of the affected source(s) including
identification of which subcategory the source is in, the capacity of
the source, a description of the add-on controls used on the source
description of the fuel(s) burned, and justification for the worst-case
fuel burned during the performance test.
(ii) Summary of the results of all performance tests, fuel
analyses, and calculations conducted to demonstrate initial compliance
including all established operating limits.
(iii) A signed certification that you have met all applicable
emissions limitations, including any emission limitation for an
emissions averaging group.
(iv) If you had a deviation from any emission limitation, you must
also submit a description of the deviation, the duration of the
deviation, and the corrective action taken in the Notification of
Compliance Status report.
(f) If you comply with the requirements in Sec. 63.9991(b) by using
distillate fuel, and you must switch fuel because of an emergency, you
must notify the Administrator in writing within 30 days of using a fuel
other than distillate oil.
Sec. 63.10031 What reports must I submit and when?
(a) Compliance report due dates. Unless the Administrator has
approved a different schedule for submission of reports under Sec.
63.10(a), you must submit a semiannual compliance report to the
permitting authority according to the requirements in paragraphs (a)(1)
through (5) of this section.
(1) The first compliance report must cover the period beginning on
the compliance date that is specified for your affected source in Sec.
63.9983 and ending on June 30 or December 31, whichever date comes
first after the compliance date that is specified for your affected
source in Sec. 63.9983.
(2) The first compliance report must be postmarked or delivered no
later than July 31 or January 31, whichever date comes first after the
first compliance report is due.
(3) Each subsequent compliance report must cover the semiannual
reporting period from January 1 through June 30 or the semiannual
reporting period from July 1 through December 31.
(4) Each subsequent compliance report must be postmarked or
delivered no later than July 31 or January 31, whichever date comes
first after the end of the semiannual reporting period.
(5) For each affected source that is subject to permitting
regulations pursuant to 40 CFR part 70 or 40 CFR part 71, and if the
permitting authority has established dates for submitting semiannual
reports pursuant to 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR
71.6(a)(3)(iii)(A), you may submit the first and subsequent compliance
reports according to the dates the permitting authority has established
instead of according to the dates in paragraphs (a)(1) through (4) of
this section.
(b) Compliance report contents. The compliance report must contain
the information required in paragraphs (b)(1) through (5) of this
section and, as applicable, paragraphs (b)(6) through (10) of this
section.
(1) Company name and address.
(2) Statement by a responsible official with that official's name,
title, and signature, certifying the truth, accuracy, and completeness
of the content of the report.
(3) Date of report and beginning and ending dates of the reporting
period.
(4) A summary of the results of the annual performance tests and
documentation of any operating limits that were reestablished during
this test, if applicable.
[[Page 4726]]
(5) If you had a startup, shutdown, or malfunction during the
reporting period and you took actions consistent with your SSMP, the
compliance report must include the information in Sec. 63.10(d)(5)(i).
(6) If there are no deviations from any emission limitation
(emissions limit or operating limit) in this subpart that apply to you,
a statement that there were no deviations from the emissions
limitations during the reporting period.
(7) If there were no periods during which a CMS, including CEMS or
CPMS, was out-of-control as specified in Sec. 63.8(c)(7), a statement
that there were no periods during which the CMS were out-of-control
during the reporting period.
(8) For each deviation from an emission limitation (emissions limit
or operating limit) in this subpart that occurs at an affected source
where you are not using a CMS to comply with that emission limitation,
the compliance report must contain the information in paragraphs
(b)(8)(i) through (iii) of this section. This includes periods of
startup, shutdown, and malfunction.
(i) The total operating time of each affected source during the
reporting period.
(ii) Information on the number, duration, and cause of the
deviation (including unknown cause) as applicable and the corrective
action taken.
(iii) A copy of the test report if the annual performance test
showed a deviation from the Ni emissions limit or a deviation from the
Hg emissions limit.
(9) For each deviation from an emission limitation (emissions limit
or operating limit) in this subpart occurring at an affected source
where you are using a CMS to comply with that emission limitation, you
must include the information in paragraphs (b)(9)(i) through (xii) of
this section. This includes periods of startup, shutdown, and
malfunction and any deviations from your unit-specific monitoring plan
as required in Sec. 63.10000(c).
(i) The date and time that each malfunction started and stopped and
description of the nature of the deviation (i.e., what you deviated
from).
(ii) The date and time that each CMS was inoperative, except for
zero (low-level) and high-level checks.
(iii) The date, time, and duration that each CMS was out-of-
control, including the information in Sec. 63.8(c)(8).
(iv) The date and time that each deviation started and stopped, and
whether each deviation occurred during a period of startup, shutdown,
or malfunction or during another period.
(v) A summary of the total duration of the deviation during the
reporting period and the total duration as a percent of the total
source operating time during that reporting period.
(vi) A breakdown of the total duration of the deviations during the
reporting period into those that are due to startup, shutdown, control
equipment problems, process problems, other known causes, and other
unknown causes.
(vii) A summary of the total duration of CMS downtime during the
reporting period and the total duration of CMS downtime as a percent of
the total source operating time during that reporting period.
(viii) An identification of each parameter that was monitored at
the affected source for which there was a deviation, including opacity,
carbon monoxide, and operating parameters for wet scrubbers and other
control devices.
(ix) A brief description of the source for which there was a
deviation.
(x) A brief description of each CMS for which there was a
deviation.
(xi) The date of the latest CMS certification or audit for the
system for which there was a deviation.
(xii) A description of any changes in CMS, processes, or controls
since the last reporting period for the source for which there was a
deviation.
(10) A statement that each emissions averaging group was in
compliance with its applicable limit during the semiannual reporting
period.
(c) Immediate startup, shutdown, and malfunction report. If you had
a startup, shutdown, or malfunction during the semiannual reporting
period that was not consistent with your SSMP, you must submit an
immediate startup, shutdown, and malfunction report according to the
requirements of Sec. 63.10(d)(5)(ii).
(d) Part 70 monitoring report. Each affected source that has
obtained a title V operating permit pursuant to 40 CFR part 70 or 40
CFR part 71 must report all deviations as defined in this subpart in
the semiannual monitoring report required by 40 CFR 70.6(a)(3)(iii)(A)
or 40 CFR 71.6(a)(3)(iii)(A). If an affected source submits a
compliance report along with, or as part of, the semiannual monitoring
report required by 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR
71.6(a)(3)(iii)(A), and the compliance report includes all required
information concerning deviations from any emission limitation
(including any operating limit), submission of the compliance report
satisfies any obligation to report the same deviations in the
semiannual monitoring report. However, submission of a compliance
report does not otherwise affect any obligation the affected source may
have to report deviations from permit requirements to the permitting
authority.
Sec. 63.10032 What records must I keep?
(a) You must keep records according to paragraphs (a)(1) through
(3) of this section.
(1) A copy of each notification and report that you submitted to
comply with this subpart, including all documentation supporting any
Initial Notification or Notification of Compliance Status or semiannual
compliance report that you submitted, according to the requirements in
Sec. 63.10(b)(2)(xiv).
(2) The records in Sec. 63.6(e)(3)(iii) through (v) related to
startup, shutdown, and malfunction.
(3) Records of performance tests or other compliance demonstrations
and performance evaluations as required in Sec. 63.10(b)(2)(viii).
(b) For each monitoring system required by this subpart, you must
keep records according to paragraphs (b)(1) through (4) of this
section.
(1) Records described in Sec. 63.10(b)(2)(vi) through (xi).
(2) Previous (i.e., superseded) versions of the performance
evaluation plan as required in Sec. 63.8(d)(3).
(3) Request for alternatives to relative accuracy test for CEMS as
required in Sec. 63.8(f)(6)(i).
(4) Records of the date and time that each deviation started and
stopped, and whether the deviation occurred during a period of startup,
shutdown, or malfunction or during another period.
(c) You must keep the records required in Table 3 to this subpart
including records of all monitoring data to show continuous compliance
with each emission limitation that applies to you.
Sec. 63.10033 In what form and how long must I keep my records?
(a) Your records must be in a form suitable and readily available
for expeditious review, according to Sec. 63.10(b)(1).
(b) As specified in Sec. 63.10(b)(1), you must keep each record for
5 years following the date of each occurrence, measurement,
maintenance, corrective action, report, or record.
(c) You must keep each record on site for at least 2 years after
the date of each occurrence, measurement, maintenance, corrective
action, report, or record, according to Sec. 63.10(b)(1). You can keep
the records offsite for the remaining 3 years.
[[Page 4727]]
Other Requirements and Information
Sec. 63.10040 What parts of the General Provisions apply to me?
Table 4 to this subpart shows which parts of the General Provisions
in Sec.Sec. 63.1 through 63.15 apply to you.
Sec. 63.10041 Who implements and enforces this subpart?
(a) This subpart can be implemented and enforced by the U.S.
Environmental Protection Agency (U.S. EPA), or a delegated authority
such as your State, local, or tribal agency. If the Administrator has
delegated authority to your State, local, or tribal agency, then that
agency has the authority to implement and enforce this subpart. You
should contact your EPA Regional Office to find out if this subpart is
delegated to your State, local, or tribal agency.
(b) In delegating implementation and enforcement authority to this
subpart to a State, local, or tribal agency under 40 CFR part 63,
subpart E, the authorities contained in paragraph (c) of this section
are retained by the Administrator and are not transferred to the State,
local, or tribal agency. The U.S. EPA retains oversight of this subpart
and can take enforcement actions, as appropriate.
(c) The authorities that will not be delegated to State, local, or
tribal agencies are listed in paragraphs (c)(1) through (5) of this
section.
(1) Approval of alternatives to the non-opacity emission limits in
63.9990(a) through (g) under Sec. 63.6(g).
(2) Approval of major alternatives to test methods under Sec.
63.7(e)(2)(ii) and (f) and as defined in Sec. 63.90.
(3) Approval of major alternatives to monitoring under Sec. 63.8(f)
and as defined in Sec. 63.90.
(4) Approval of major alternatives to recordkeeping and reporting
under Sec. 63.10(f) and as defined in Sec. 63.90.
(5) Approval of the unit-specific monitoring plan under Sec.
63.10000(c).
Sec. 63.10042 What definitions apply to this subpart?
Terms used in this subpart are defined in the Clean Air Act, in
Sec. 63.2, and in this section as follows:
Anthracite coal means solid fossil fuel classified as anthracite
coal by ASTM Designation D388-77, 90, 91, 95, or 98a (incorporated by
reference--see 40 CFR 60.17).
Bituminous coal means solid fossil fuel classified as bituminous
coal by ASTM D388-77, 90, 91, 95, or 98a (incorporated by reference--
see 40 CFR 60.17).
Coal means all solid fossil fuels classified as anthracite,
bituminous, subbituminous, or lignite by ASTM Designation D388-77, 90,
91, 95, or 98a (incorporated by reference--see 40 CFR 60.17).
Coal refuse means waste products of coal mining, physical coal
cleaning, and coal preparation operations (e.g., culm, gob, etc.)
containing coal, matrix material, clay, and other organic and inorganic
material.
Coal-fired electric utility steam generating unit means an electric
utility steam generating unit that burns coal, coal refuse, or a
synthetic gas derived from coal either exclusively, in any combination
together, or in any combination with other supplemental fuels. Examples
of supplemental fuels include, but are not limited to, petroleum coke
and tire-derived fuels.
Combined-cycle gas turbine means a stationary turbine combustion
system where heat from the turbine exhaust gases is recovered by a
waste heat boiler.
Deviation means any instance in which an affected source subject to
this subpart, or an owner or operator of such a source:
(1) Fails to meet any requirement or obligation established by this
subpart including, but not limited to, any emission limitation
(including any operating limit) or work practice standard;
(2) Fails to meet any term or condition that is adopted to
implement an applicable requirement in this subpart and that is
included in the operating permit for any affected source required to
obtain such a permit; or
(3) Fails to meet any emission limitation (including any operating
limit) or work practice standard in this subpart during startup,
shutdown, or malfunction, regardless of whether or not such failure is
permitted by this subpart.
Distillate oil means fuel oils that contain 0.05 weight percent
nitrogen or less and comply with the specifications for fuel oil
numbers 1 and 2, as defined by the American Society of Testing and
Materials in ASTM D396-78, 89, 90, 92, 96, or 98, Standard
Specifications for Fuel Oils (incorporated by reference--see 40 CFR
60.17).
Electric utility steam generating unit means any fossil fuel-fired
combustion unit of more than 25 megawatts electric (MWe) that serves a
generator that produces electricity for sale. A unit that cogenerates
steam and electricity and supplies more than one-third of its potential
electric output capacity and more than 25 MWe output to any utility
power distribution system for sale is also considered an electric
utility steam generating unit.
Electrostatic precipitator means an add-on air pollution control
device used to capture particulate matter by charging the particles
using an electrostatic field, collecting the particles using a grounded
collecting surface, and transporting the particles into a hopper.
Emission limitation means any emissions limit or operating limit.
Federally enforceable means all limitations and conditions that are
enforceable by the Administrator, including the requirements of 40 CFR
parts 60 and 61, requirements within any applicable State
implementation plan, and any permit requirements established under 40
CFR 52.21 or Sec.Sec. 51.18 and 51.24.
Fossil fuel means natural gas, petroleum, coal, and any form of
solid, liquid, or gaseous fuel derived from such material for the
purpose of creating useful heat.
Integrated gasification combined cycle (IGCC) electric utility
steam generating unit means a coal-fired electric utility steam
generating unit that burns a synthetic gas derived from coal in a
combined-cycle gas turbine. No coal is directly burned in the unit
during operation.
Lignite means solid fossil fuel classified as lignite coal by ASTM
D388-77, 90, 91, 95, or 98a (incorporated by reference--see 40 CFR
60.17).
Oil means crude oil or petroleum or a liquid fuel derived from
crude oil or petroleum, including distillate and residual oil.
Oil-fired electric utility steam generating unit means an electric
utility steam generating unit that either burns oil exclusively, or
burns oil alternately with burning fuels other than oil at other times.
Residual oil means crude oil, fuel oil numbers 1 and 2 that have a
nitrogen content greater than 0.05 weight percent, and all fuel oil
numbers 4, 5 and 6, as defined by the American Society of Testing and
Materials in ASTM D396-78, Standard Specifications for Fuel Oils
(incorporated by reference--see 40 CFR 60.17).
Responsible official means responsible official as defined in 40
CFR 70.2.
Steam generating unit means any furnace, boiler, or other device
used for combusting fuel for the purpose of producing steam (including
fossil-fuel fired steam generators associated with combined-cycle gas
turbines; nuclear steam generators are not included).
Subbituminous coal means solid fossil fuel that is classified as
subbituminous A, B, or C according to
[[Page 4728]]
the American Society of Testing and Materials (ASTM) Standard
Specification for Classification of Coals by Rank D388-77 (incorporated
by reference--see 40 CFR 60.17).
Tables to Subpart UUUUU of Part 63
As stated in Sec. 63.10007, you must comply with the following
requirements for performance tests:
Table 1 to Subpart UUUUU of Part 63.--Performance Test Requirements for Ni and Hg
----------------------------------------------------------------------------------------------------------------
According to the
For each affected source . . . You must . . . Using this method . . . following requirements .
. .
----------------------------------------------------------------------------------------------------------------
1. Subject to Ni emissions limit. a. Select sampling port Method 1 or 1A (40 CFR Sampling sites must be
locations and number of part 60, appendix A). located at the outlet
traverse points in each of the control device
stack or duct. (or at the outlet of
the emissions source if
no control device is
present) prior to any
releases to the
atmosphere.
b. Determine the Method 2, 2A, 2C, 2D,
volumetric flow rate of 2F, or 2G (40 CFR part
the stack gas. 60, appendix A).
c. Determine the dry Method 3A or 3B (40 CFR
molecular weight of the part 60, appendix A).
stack gas.
d. Determine the moisture Method 4 (40 CFR part
content of the stack gas. 60, appendix A).
e. Determine the Ni Method 29 (40 CFR part
concentration. 60, appendix A) for Ni.
2. Subject to Ni emissions limit Establish operating Data from the current (1) Collect secondary
and that use an ESP. limits for minimum and voltage monitors current and voltage or
voltage and secondary for the ESP and the Ni total power input for
current or total power performance test. the ESP every 15
input. minutes during the
entire period of the
three-run Ni
performance test.
(2) Determine the
average secondary
current and voltage or
total power input by
computing the average
of all 15 minute
readings taken during
each test run. You must
set the minimum
operating limits equal
to the minimum 1-hour
average values measured
during the three-run
performance test.
----------------------------------------------------------------------------------------------------------------
As stated in Sec. 63.10009, you must show initial compliance with
the emissions limitations according to the following:
Table 2 to Subpart UUUUU of Part 63.--Initial Compliance With Emissions
Limitations for Ni and Hg
------------------------------------------------------------------------
You have
For . . . That is controlled demonstrated initial
with . . . compliance if . . .
------------------------------------------------------------------------
1. Each oil-fired unit Electrostatic i. The average Ni
subject to a Ni emissions precipitator (ESP). emissions in lb/
limit in Sec. 63.9991. TBtu or lb/MWH over
the three-run
performance test do
not exceed the
applicable
emissions limit.
ii. You have a
record of the
average secondary
current and voltage
or total power
input of the ESP
for each test run
over the three-run
performance test
during which the Ni
emissions did not
exceed the
applicable limit.
2. Each oil-fired unit Any type............ i. You submit a
subject to alternative signed
standard in Sec. 63.9991(b) certification in
for fuel switching. the Notification of
Compliance Status
report that you
burn only
distillate oil as
the fuel in your
unit.
ii. You have records
demonstrating that
you burn only
distillate oil as
the fuel in your
unit.
3. Each coal-fired unit Any................. You have established
subject to Hg emissions a site specific Hg
limit in Sec. 63.9990. limit according to
the procedures in
Sec. 63.10009 and
reported the limit
in your
Notification of
Compliance Status.
------------------------------------------------------------------------
[[Page 4729]]
As stated in Sec. 63.10021, you must show continuous compliance
with the emissions limitations according to the following:
Table 3 to Subpart UUUUU of Part 63--Continuous Compliance with
Emissions Limitations for Hg and Ni
------------------------------------------------------------------------
You must demonstrate
That is controlled continuous
For . . . with . . . compliance by . . .
------------------------------------------------------------------------
i. Each unit subject to Hg Any type............ i. Continuously
emissions limit in Sec. monitoring the
63.9990. hourly average Hg
emissions using a
CEMS or monitoring
and recording the
Hg measurements by
semicontinous
method.
ii. Collecting and
reducing the
monitoring data
according to Sec.
63.100.20.
iii. Calculating for
each month the
monthly rolling
average emissions.
iv. Maintaining the
12-month rolling
average at or below
the applicable
limit.
2. Each unit subject to Ni Electrostatic i. Collecting and
limit in Sec. 63.9991. precipitator. reducing the
secondary current
and voltage (or
total power input)
monitoring data.
ii. Maintaining the
hoursly average
secondary current
and voltage or
total power input
at or above the
limits established
in the performance
test.
iii. Conducting
performance tests
at least once per
year and reporting
the results in the
semiannual
compliance report.
3. Each unit subject to Any type............ i. Submitting
alternative standard for written
distillate fuel switching certifications with
in Sec. 63.9991(b). each semiannual
compliance report
according to the
requirements in
Sec. 63.10031(b)
and keeping records
of fuel burned to
document
compliance.
ii. Notifying the
Adminsitrator if
resume burning fuel
other than
distillate oil
according to the
requirements in
Sec. 63.10030(a).
iii. If at any time
the unit does not
meet the
alternative limit,
the owner or
operator must
immediately comply
with the applicable
Ni limit, including
all initial and
continuous
compliance
requirements.
------------------------------------------------------------------------
As stated in Sec. 63.10040, you must comply with the applicable
General Provisions according to the following:
Table 4 to Subpart UUUUU of Part 63--Applicability of General Provisions to Subpart UUUUU
----------------------------------------------------------------------------------------------------------------
Citation Subject Brief description Comments
----------------------------------------------------------------------------------------------------------------
Sec. 63.1......................... Applicability............. Initial Applicability Yes.
Determination;
Applicability After
Standard Established;
Permit Requirements;
Extensions, Notifications.
Sec. 63.2......................... Definitions............... Definitions for part 63 Yes.
standards.
Sec. 63.3......................... Units and Abbreviations... Units and abbreviations Yes.
for part 63 standards.
Sec. 63.4......................... Prohibited Activities..... Prohibited Activities; Yes.
Compliance date;
Circumvention,
Severability.
Sec. 63.5......................... Construction/ Applicability; Yes.
Reconstruction. applications; approvals.
Sec. 63.6(a)...................... Applicability............. GP apply unless compliance Yes.
extension and GP apply to
area sources that become
major.
Sec. 63.6(b)(1)-(4)............... Compliance Dates for New Standards apply at Yes.
and Reconstructed sources. effective date; 3 years
after effective date;
upon startup; 10 years
after construction or
reconstruction commences
for 112(f).
Sec. 63.6(b)(5)................... Notification.............. Must notify if commenced Yes.
construction or
reconstruction after
proposal.
Sec. 63.6(b)(6)................... [Reserved]................
[[Page 4730]]
Sec. 63.6(b)(7)................... Compliance Dates for New Area sources that become Yes.
and Reconstructed Area major must comply with
Sources That Become Major. major source standards
immediately upon becoming
major, regardless of
whether required to
comply when they were an
area source.
Sec. 63.6(c)(1)-(2)............... Compliance Dates for Comply according to date Yes.
Existing Sources. in subpart, which must be
no later than 3 years
after effective date and
for 112(f) standards,
comply within 90 days of
effective date unless
compliance extension.
Sec. 63.6(c)(3)-(4)............... [Reserved]................
Sec. 63.6(c)(5)................... Compliance Dates for Area sources that become Yes.
Existing Area Sources major must comply with
That Become Major. major source standards by
date indicated in subpart
or by equivalent time
period (for example, 3
years).
Sec. 63.6(d)...................... [Reserved]................
Sec. 63.6(e)(1)-(2)............... Operation & Maintenance... Operate to minimize Yes.
emissions at all times.
AND.......................
Correct malfunctions as
soon as practicable.
AND.......................
Operation and maintenance
requirements
independently enforceable
information Administrator
will use to determine if
operation and maintenance
requirements were met.
Sec. 63.6(e)(3)................... Startup, Shutdown, and Requirement for SSM and Yes.
Malfunction Plan (SSMP). startup, shutdown,
malfunction plan.
Content of SSMP...........
Sec. 63.6(f)(1)................... Compliance Except During Comply with emission Yes.
SSM. standards at all times
except during SSM.
Sec. 63.6(f)(2)-(3)............... Methods for Determining Compliance based on Yes.
Compliance. performance test,
operation and maintenance
plans, records,
inspection.
Sec. 63.6(g)(1)-(3)............... Alternative Standard...... Procedures for getting an Yes.
alternative standard.
Sec. 63.6(h)(1)................... Compliance with Opacity/VE Comply with opacity/VE No.
Standards. emissions limitations at
all times except during
SSM.
Sec. 63.6(h)(2)(i)................ Determining Compliance If standard does not state No.
with Opacity/Visible test method, use Method 9
Emission (VE) Standards. for opacity and Method 22
for VE.
Sec. 63.6(h)(2)(ii)............... [Reserved]................
Sec. 63.6(h)(2)(iii).............. Using Previous Tests to Criteria for when previous No.
Demonstrate Compliance opacity/VE testing can be
with Opacity/VE Standards. used to show compliance
with this rule.
Sec. 63.6(h)(3)................... [Reserved]................
Sec. 63.6(h)(4)................... Notification of Opacity/VE Notify Administrator of No.
Observation Date. anticipated date of
observation.
Sec. 63.6(h)(5)(i), (iii)-(v)..... Conducting Opacity/VE Dates and Schedule for No.
Observations. conducting opacity/VE
observations.
Sec. 63.6(h)(5)(ii)............... Opacity Test Duration and Must have at least 3 hours No.
Averaging Times. of observation with
thirty, 6-minute averages.
Sec. 63.6(h)(6)................... Records of Conditions Keep records available and No.
During Opacity/VE allow Administrator to
observations. inspect.
Sec. 63.6(h)(7)(i)................ Report continuous opacity Submit continuous opacity No.
monitoring system data monitoring system data
monitoring data from with other performance
performance test. test.
Sec. 63.6(h)(7)(ii)............... Using continuous opacity Can submit continuous No.
monitoring system instead opacity monitoring system
of Method 9. data instead of Method 9
results even if rule
requires Method 9, but
must notify Administrator
before performance test.
Sec. 63.6(h)(7)(iii).............. Averaging time for To determine compliance, No.
continuous opacity must reduce continuous
monitoring system during opacity monitoring system
performance test. data to 6-minute averages.
[[Page 4731]]
Sec. 63.6(h)(7)(iv)............... Continuous opacity Demonstrate that No.
monitoring system continuous opacity
requirements. monitoring system
performance evaluations
are conducted according
to Sec.Sec. 63.8(e),
continuous opacity
monitoring system are
properly maintained and
operated according to
63.8(c) and data quality
as Sec. 63.8(d).
Sec. 63.6(h)(7)(v)................ Determining Compliance Continuous opacity No.
with Opacity/VE Standards. monitoring system is
probative but not
conclusive evidence of
compliance with opacity
standard, even if Method
9 observation shows
otherwise. Requirements
for continuous opacity
monitoring system to be
probative evidence-proper
maintenance, meeting PS
1, and data have not been
altered.
Sec. 63.6(h)(8)................... Determining Compliance Administrator will use all No.
with Opacity/VE Standards. continuous opacity
monitoring system, Method
9, and Method 22 results,
as well as information
about operation and
maintenance to determine
compliance.
Sec. 63.6(h)(9)................... Adjusted Opacity Standard. Procedures for No.
Administrator to adjust
an opacity standard.
Sec. 63.6(i)(1)-(14).............. Compliance Extension...... Procedures and criteria Yes.
for Administrator to
grant compliance
extension.
Sec. 63.6(j)...................... Presidential Compliance President may exempt Yes.
Exemption. source category from
requirement to comply
with rule.
Sec. 63.7(a)(1)................... Performance Test Dates.... Dates for Conducting Yes.
Initial Performance
Testing and Other
Compliance Demonstrations.
Sec. 63.7(a)(2)(i)................ Performance Test Dates.... New source with initial Yes.
startup date before
effective date has 180
days after effective date
to demonstrate compliance.
Sec. 63.7(a)(2)(ii)............... Performance Test Dates.... New source with initial Yes.
startup date after
effective date has 180
days after initial
startup date to
demonstrate compliance.
Sec. 63.7(a)(2)(iii).............. Performance Test Dates.... Existing source subject to Yes.
standard established
pursuant to 112(d) has
180 days after compliance
date to demonstrate
compliance.
AND.......................
Existing source with Yes.
startup date after
effective date has 180
days after startup to
demonstrate compliance.
Sec. 63.7(a)(2)(iv)............... Performance Test Dates.... Existing source subject to No.
standard established
pursuant to 112(f) has
180 days after compliance
date to demonstrate
compliance.
Sec. 63.7(a)(2)(v)................ Performance Test Dates.... Existing source that Yes.
applied for extension of
compliance has 180 days
after termination date of
extension to demonstrate
compliance.
Sec. 63.7(a)(2)(vi)............... Performance Test Dates.... New source subject to No.
standard established
pursuant to 112(f) that
commenced construction
after proposal date of
112(d) standard but
before proposal date of
112(f) standard, has 180
days after compliance
date to demonstrate
compliance.
Sec. 63.7(a)(2)(vii-viii)......... [Reserved]................
[[Page 4732]]
Sec. 63.7(a)(2)(ix)............... Performance Test Dates.... New source that commenced Yes.
construction between
proposal and promulgation
dates, when promulgated
standard is more
stringent than proposed
standard, has 180 days
after effective date or
180 days after startup of
source, whichever is
later, to demonstrate
compliance.
AND.......................
If source initially
demonstrates compliance
with less stringent
proposed standard, it has
3 years and 180 days
after the effective date
of the standard or 180
days after startup of
source, whichever is
later, to demonstrate
compliance with
promulgated standard.
Sec. 63.7(a)(3)................... Section 114 Authority..... Administrator may require Yes.
a performance test under
Act Section 114 at any
time.
Sec. 63.7(b)(1)................... Notification of Must notify Administrator Yes.
Performance Test. 60 days before the test.
Sec. 63.7(b)(2)................... Notification of If rescheduling a Yes.
Rescheduling. performance test is
necessary, must notify
Administrator 5 days
before scheduled date of
rescheduled date.
Sec. 63.7(c)...................... Quality Assurance/Test Requirement to submit unit Yes.
Plan. specific test plan 60
days before the test or
on date Administrator
agrees with:
Test plan approval
procedures.
AND.......................
Performance audit
requirements.
AND.......................
Internal and External QA
procedures for testing.
Sec. 63.7(d)...................... Testing Facilities........ Requirements for testing Yes.
facilities.
Sec. 63.7(e)(1)................... Conditions for Conducting Perfomance tests must be Yes.
Performance Tests. conducted under
representative conditions.
AND
Cannot conduct performance Yes.
tests during SSMs.
AND.......................
Not a deviation to exceed Yes.
standard during SSM
AND.......................
Upon request of Yes.
Administrator, make
available records
necessary to determine
conditions of performance
tests.
Sec. 63.7(e)(2)................... Conditions for Conducting Must conduct according to Yes.
Performance Tests. rule and EPA test methods
unless Administrator
approves alternative.
Sec. 63.7(e)(3)................... Test Run Duration......... Must have three separate Yes.
test runs.
AND.......................
Compliance is based on
arithmetic mean of three
runs.
AND.......................
Conditions when data from
an additional test run
can be used.
Sec. 63.7(f)...................... Alternative Test Method... Procedures by which Yes.
Administrator can grant
approval to use an
alternative test method.
Sec. 63.7(g)...................... Performance Test Data Must include raw data in Yes.
Analysis. performance test report.
AND.......................
Must submit performance
test data 60 days after
end of test with the
Notification of
Compliance Status.
AND.......................
Keep data for 5 years.....
Sec. 63.7(h)...................... Waiver of Tests........... Procedures for Yes.
Administrator to waive
performance test.
[[Page 4733]]
Sec. 63.7(a)(1)................... Applicability of Subject to all monitoring Yes.
Monitoring Requirements. requirements in standard.
Sec. 63.8(a)(2)................... Performance Specifications Performance Specifications Yes.
in appendix B of part 60
apply.
Sec. 63.8(a)(3)................... [Reserved]................
Sec. 63.8(a)(4)................... Monitoring with Flares.... Unless your rule says No.
otherwise, the
requirements for flares
in Sec. 63.11 apply.
Sec. 63.8(b)(1)(i)-(ii)........... Monitoring................ Must conduct monitoring Yes.
according to standard
unless Administrator
approves alternative.
Sec. 63.8(b)(1)(iii).............. Monitoring................ Flares not subject to this No.
section unless otherwise
specified in relevant
standard.
Sec. 63.8(b)(2)-(3)............... Multiple Effluents and Specific requirements for Yes.
Multiple Monitoring installing monitoring
Systems. systems.
AND.......................
Must install on each
effluent before it is
combined and before it is
released to the
atmosphere unless
Administrator approves
otherwise.
AND.......................
If more than one
monitoring system on an
emission point, must
report all monitoring
system results, unless
one monitoring system is
a backup.
Sec. 63.8(c)(1)................... Monitoring System Maintain monitoring system Yes.
Operation and Maintenance. in a manner consistent
with good air pollution
control practices.
Sec. 63.8(c)(1)(i)................ Routine and Predictable Follow the SSM plan for Yes.
SSM. routine repairs. Keep
parts for routine repairs
readily available.
Reporting requirements for
SSM when action is
described in SSM plan.
Sec. 63.8(c)(1)(ii)............... SSM not in SSMP........... Reporting requirements for Yes.
SSM when action is not
described in SSM plan.
Sec. 63.8(c)(1)(iii).............. Compliance with Operation How Administrator Yes.
and Maintenance determines if source
Requirements. complying with operation
and maintenance
requirements.
AND.......................
Review of source O&M
procedures, records,
Manufacturer's
instructions,
recommendations, and
inspection of monitoring
system.
Sec. 63.8(c)(2)-(3)............... Monitoring System Must install to get Yes.
Installation. representative emission
and parameter
measurements.
AND.......................
Must verify operational
status before or at
performance test.
Sec. 63.8(c)(4)................... Continuous Monitoring Continuous monitoring Yes.
System (CMS) Requirements. systems must be operating
except during breakdown,
out-of-control, repair,
maintenance, and high-
level calibration drifts.
Sec. 63.8(c)(4)(i)............... Continuous Monitoring Continuous opacity No.
System (CMS) Requirements. monitoring system must
have a minimum of one
cycle of sampling and
analysis for each
successive 10-second
period and one cycle of
data recording for each
successive 6-minute
period.
Sec. 63.8(c)(4)(ii).............. Continuous Monitoring Continuous emissions Yes.
System (CMS) Requirements. monitoring system must
have a minimum of one
cycle of operation for
each successive 15-minute
period.
Sec. 63.8(c)(7)-(8).............. Continuous monitoring Out-of-control periods, Yes.
systems Requirements. including reporting.
[[Page 4734]]
Sec. 63.8(d)..................... Continuous monitoring Requirements for Yes.
systems Quality Control. continuous monitoring
systems quality control,
including calibration,
etc.
AND.......................
Must keep quality control
plan on record for the
life of the affected
source. Keep old versions
for 5 years after
revisions.
Sec. 63.8(e)..................... Continuous monitoring Notification, performance Yes.
systems Performance evaluation test plan,
Evaluation. reports.
Sec. 63.8(f)(1)-(5).............. Alternative Monitoring Procedures for Yes.
Method. Administrator to approve
alternative monitoring.
Sec. 63.8(f)(6).................. Alternative to Relative Procedures for No.
Accuracy Test. Administrator to approve
alternative relative
accuracy tests for
continuous emissions
monitoring system.
Sec. 63.8(g)(1)-(4).............. Data Reduction............ Continuous emissions Yes.
monitoring system 1-hour
averages computed over at
least 4 equally spaced
data points.
Sec. 63.8(g)(5).................. Data Reduction............ Data that cannot be used No.
in computing averages for
continuous emissions
monitoring system and
continuous opacity
monitoring system.
Sec. 63.9(a)..................... Notification Requirements. Applicability and State Yes.
Delegation.
Sec. 63.9(b)(1)-(5).............. Initial Notifications..... Submit notification 120 Yes.
days after effective date.
AND.......................
Notification of intent to
construct/reconstruct.
AND.......................
Notification of
commencement of construct/
reconstruct; Notification
of startup..
AND.......................
Contents of each..........
Sec. 63.9(c)..................... Request for Compliance Can request if cannot Yes.
Extension. comply by date or if
installed BACT/LAER.
Sec. 63.9(d)..................... Notification of Special For sources that commence Yes.
Compliance Requirements construction between
for New Source. proposal and promulgation
and want to comply 3
years after effective
date.
Sec. 63.9(e)..................... Notification of Notify Administrator 60 Yes.
Performance Test. days prior.
Sec. 63.9(f)..................... Notification of VE/Opacity Notify Administrator 30 No.
Test. days prior.
Sec. 63.9(g)...................... Additional Notifications Notification of Yes.
When Using Continuous performance evaluation.
Monitoring Systems. AND.......................
Notification that exceeded
criterion for relative
accuracy.
Sec. 63.9(h)(1)-(6)............... Notification of Compliance Contents.................. Yes.
Status. AND.......................
Due 60 days after end of
performance test or other
compliance demonstration.
When to submit to Federal
vs. State authority.
Sec. 63.9(i)...................... Adjustment of Submittal Procedures for Yes.
Deadlines. Administrator to approve
change in when
notifications must be
submitted.
Sec. 63.9(j)...................... Change in Previous Must submit within 15 days Yes.
Information. after the change.
Sec. 63.10(a)..................... Recordkeeping/Reporting... Applies to all, unless Yes.
compliance extension.
AND.......................
When to submit to Federal
vs. State authority.
AND.......................
Procedures for owners of
more than 1 source.
[[Page 4735]]
Sec. 63.10(b)(1).................. Recordkeeping/Reporting... General Requirements...... Yes.
AND.......................
Keep all records readily
available.
AND.......................
Keep for 5 years..........
Sec. 63.10(b)(2)(i)-(v)........... Records related to Occurrence of each of Yes.
Startup, Shutdown, and operation (process
Malfunction. equipment).
AND.......................
Occurrence of each
malfunction of air
pollution equipment.
AND.......................
Maintenance on air
pollution control
equipment.
AND.......................
Actions during startup,
shutdown, and malfunction.
Sec. 63.10(b)(2)(vi) and (x-xi)... Continuous monitoring Malfunctions, inoperative, Yes.
systems Records. out-of-control.
AND.......................
Calibration checks........
AND.......................
Adjustments, maintenance..
Sec. 63.10(b)(2)(vii)-(ix)........ Records................... Measurements to Yes.
demonstrate compliance
with emissions
limitations.
AND.......................
Performance test and
performance evaluation.
AND.......................
Measurements to determine
conditions of performance
test and performance
evaluations..
Sec. 63.10(b)(2)(xii)............. Records................... Records when under waiver. Yes.
Sec. 63.10(b)(2)(xiii)............ Records................... Records when using Yes.
alternative to relative
accuracy test.
Sec. 63.10(b)(2)(xiv)............. Records................... All documentation Yes.
supporting Initial
Notification and
Notification of
Compliance Status.
Sec. 63.10(b)(3).................. Records................... Applicability Yes.
Determinations.
Sec. 63.10(c)(1)-(6), (9)-(15).... Records................... Additional Records for Yes.
continuous monitoring
systems.
Sec. 63.10(c)(7)-(8).............. Records................... Records of excess Yes.
emissions and parameter
monitoring exceedances
for continuous monitoring
systems.
Sec. 63.10(d)(1).................. General Reporting Requirement to report..... Yes.
Requirements.
Sec. 63.10(d)(2).................. Report of Performance Test When to submit to Federal Yes.
Results. or State authority.
Sec. 63.10(d)(3).................. Reporting Opacity or VE What to report and when... No.
Observations.
Sec. 63.10(d)(4).................. Progress Reports.......... Must submit progress Yes.
reports on schedule if
under compliance
extension.
Sec. 63.10(d)(5).................. Startup, Shutdown, and Contents and submission... Yes.
Malfunction Reports.
Sec. 63.10(e)(1)-(92)............. Additional continuous Must report results for Yes.
monitoring systems each CEM on a unit.
Reports. AND.......................
Written copy of
performance evaluation.
Sec. 63.10(e)(3).................. Reports................... Excess Emission Reports... No.
Sec. 63.10(e)(3)(i-iii)........... Reports................... Schedule for reporting No.
excess emission and
parameter monitor
exceedance (now defined
as deviations).
[[Page 4736]]
Sec. 63.10(e)(3)(iv-v)............ Excess Emissions Reports.. Requirement to revert to No.
quarterly submission if
there is an excess
emissions and parameter
monitor exceedance (now
defined as deviations).
AND.......................
Provision to request
semiannual reporting
after compliance for one
year.
AND.......................
Submit report by 30th day
following end of quarter
or calendar half.
AND.......................
If there has not been an
exceedance or excess
emission (now defined as
deviations), report
contents is a statement
that there have been no
deviations.
Sec. 63.10(e)(3)(iv-v)............ Excess Emissions Reports.. Must submit report No.
containing all of the
information in Sec.
63.10(c)(5-13), Sec.
63.8(c)(7-8).
Sec. 63.10(e)(3)(vi-viii)......... Excess Emissions Report Requirements for reporting No.
and Summary Report. excess emissions for
continuous monitoring
systems (now called
deviations).
Sec. 63.10(e)(4).................. Reporting continuous Must submit continuous No.
opacity monitoring system opacity monitoring system
data. data with performance
test data.
Sec. 63.10(f)..................... Waiver for Recordkeeping Procedures for Yes.
Reporting. Administrator to waive.
Sec. 63.11........................ Flares.................... Requirements for flares... No.
Sec. 63.12........................ Delegation................ State authority to enforce Yes.
standards.
Sec. 63.13........................ Addresses................. Addresses where reports, Yes.
notifications, and
requests are sent.
Sec. 63.14........................ Incorporation by Reference Test methods incorporated Yes.
by reference.
Sec. 63.15........................ Availability of Public and confidential Yes.
Information. information.
----------------------------------------------------------------------------------------------------------------
APPENDIX B--PART 63
7. Appendix B to part 63 is amended by adding in numerical order
new Method 324 to read as follows:
Method 324--Determination of Vapor Phase Flue Gas Mercury Emissions
From Stationary Sources Using Dry Sorbent Trap Sampling
1.0 Introduction.
This method describes sampling criteria and procedures for the
continuous sampling of mercury (Hg) emissions in combustion flue gas
streams using sorbent traps. Analysis of each trap can be by cold
vapor atomic fluorescence spectrometry (AF) which is described in
this method, or by cold vapor atomic absorption spectrometry (AA).
Only the AF analytical method is detailed in this method, with
reference being made to other published methods for the AA
analytical procedure. The Electric Power Research Institute has
investigated the AF analytical procedure in the field with the
support of ADA-ES and Frontier Geosciences, Inc. The AF procedure is
based on EPA Method 1631, Revision E: Mercury in Water by Oxidation,
Purge and Trap, and Cold Vapor Atomic Fluorescence Spectrometry.
Persons using this method should have a thorough working knowledge
of Methods 1, 2, 3, 4 and 5 of 40 CFR part 60, appendix A.
1.1 Scope and Application.
1.1.1 Analytes. The analyte measured by this method is total
vapor-phase Hg, which represents the sum of elemental (CAS Number
7439-97-6) and oxidized forms of Hg, mass concentration (micrograms/
dscm) in flue gas samples.
1.1.2 Applicability. This method is applicable to the
determination of vapor-phase Hg concentrations ranging from 0.03
[mu]g/dncm to 100 [mu]g/dncm in low-dust applications, including
controlled and uncontrolled emissions from stationary sources, only
when specified within the regulations. When employed to demonstrate
compliance with an emission regulation, paired sampling is to be
performed as part of the method quality control procedure. The
method is appropriate for flue gas Hg measurements from combustion
sources. Very low Hg concentrations will require greater sample
volumes. The method can be used over any period from 30 minutes to
several days in duration, provided appropriate sample volumes are
collected and all the quality control criteria in Section 9.0 are
met. When sampling for periods greater than 12 hours, the sample
rate is required to be maintained at a constant proportion to the
total stack flowrate, 25 percent to ensure
representativeness of the sample collected.
2.0 Summary of Method.
Known volumes of flue gas are extracted from a duct through a
single or paired sorbent traps with a nominal flow rate of 0.2 to
0.6 liters per minute through each trap. Each trap is then acid
leached and the resulting leachate is analyzed by cold vapor atomic
fluorescence spectrometry (CVAFS) detection. The AF analytical
procedure is described in detail in EPA Method 1631. Analysis by AA
can be performed by existing recognized procedures, such as that
contained in ASTM Method D6784-02 (incorporated by reference, see
Sec. 63.14) or EPA Method 29.
3.0 Definitions. [Reserved]
4.0 Clean Handling and Contamination.
During preparation of the sorbent traps, as well as transport,
field handling, sampling, recovery, and laboratory analysis, special
attention must be paid to cleanliness procedures. This is to avoid
Hg contamination of the samples, which generally contain very small
amounts of Hg. For specifics on how to avoid contamination, Section
4 of Method 1631 should be well understood.
5.0 Safety.
5.1 Site hazards must be prepared for in advance of applying
this method in the field. Suitable clothing to protect against site
hazards is required, and requires advance coordination with the site
to understand the conditions and applicable safety policies. At a
minimum, portions of the sampling system will be hot, requiring
appropriate gloves, long sleeves, and caution in handling this
equipment.
5.2 Laboratory safety policies are to minimize risk of chemical
exposure and to properly handle waste disposal. Personnel will don
appropriate laboratory attire according to a Chemical Hygiene Plan
established by the laboratory. This includes, but is not limited to,
laboratory coat, safety goggles, and nitrile gloves under clean
gloves.
[[Page 4737]]
5.3 The toxicity or carcinogenicity of reagents used in this
method has not been fully established. The procedures required in
this method may involve hazardous materials, operations, and
equipment. This method may not address all of the safety problems
associated with these procedures. It is the responsibility of the
user to establish appropriate safety and health practices and
determine the applicable regulatory limitations prior to performing
these procedures. Each chemical should be regarded as a potential
health hazard and exposure to these compounds should be minimized.
Chemists should refer to the MSDS for each chemical with which they
are working.
5.4 Any wastes generated by this procedure must be disposed of
according to a hazardous materials management plan that details and
tracks various waste streams and disposal procedures.
6.0 Equipment and Supplies.
6.1 Hg Sampling Train. A Schematic of a single trap sampling
train used for this method is shown in Figure 324-1. Where this
method is used to collect data to demonstrate compliance with a
regulation, it must be performed with paired sorbent trap equipment.
[GRAPHIC] [TIFF OMITTED] TP30JA04.019
Figure 324-1. Hg Sampling Train Illustrating Single Trap.
6.1.1 Sorbent Trap. Use sorbent traps with separate main and
backup sections in series for collection of Hg. Selection of the
sorbent trap shall be based on: (1) Achievement of the performance
criteria of this method, and (2) data is available to demonstrate
the method can pass the criteria in EPA Method 301 when used in this
method and when the results are compared with those from EPA Method
29, EPA Method 101A, or ASTM Method 6784-02 for the measurement of
vapor-phase Hg in a similar flue gas matrix. Appropriate traps are
referred to as ``sorbent trap'' throughout this method. The method
requires the analysis of Hg in both main and backup portions of the
sorbent within each trap. The sorbent trap should be obtained from a
reliable source that has clean handling procedures in place for
ultra low-level Hg analysis. This will help assure the low Hg
environment required to manufacture sorbent traps with low blank
levels of Hg. Sorbent trap sampling requirements or needed
characteristics are shown in Table 324-1. Blank/cleanliness and
other requirements are described in Table 324-2. The sorbent trap is
supported on a probe and inserted directly into the flue gas stream,
as shown on Figure 324-1. The sampled sorbent trap is the entire Hg
sample.
6.1.2 Sampling Probe. The probe assembly shall have a leak-free
attachment to the sorbent trap. For duct temperatures from 200 to
375F, no heating is required. For duct temperatures
less than 200F, the sorbent tube must be heated to at
least 200F or higher to avoid liquid condensation in
the sorbent trap by using a heated probe. For duct temperatures
greater than 375F, a large sorbent trap must be used,
as shown in Table 324-1, and no heating is required. A thermocouple
is used to monitor stack temperature.
6.1.3 Umbilical Vacuum Line. A 250F heated
umbilical line shall be used to convey to the moisture knockout the
sampled gas that has passed through the sorbent trap and probe
assembly.
6.1.4 Moisture Knockout. Impingers and desiccant can be combined
to dry the sample gas prior to entering the dry gas meter.
Alternative sample drying methods are acceptable as long as they do
not affect sample volume measurement.
6.1.5 Vacuum Pump. A leak tight vacuum pump capable of
delivering a controlled extraction flow rate between 0.1 to 0.8
liters per minute.
6.1.6 Dry Gas Meter. Use a dry gas meter that is calibrated
according to the procedures in 40 CFR part 60, appendix A, Method 5,
to measure the total sample volume collected. The dry gas meter must
be sufficiently accurate to measure the sample volume within 2
percent, calibrated at the selected flow rate and conditions
actually encountered during sampling, and equipped with a
temperature sensor capable of measuring typical meter temperatures
accurately to within 3C (5.4F).
6.2 Sample Analysis Equipment. Laboratory equipment as described
in Method 1631, Sections 6.3 to 6.7 is required for analysis by AF.
For analysis by AA, refer to Method 29 or ASTM Method 6784-02.
[[Page 4738]]
Table 324-1.--Sorbent Trap and Sampling Requirements.
------------------------------------------------------------------------
Item to be determined Small sorbent trap Large sorbent trap
------------------------------------------------------------------------
Sampling Target: Hg Loading Minimum = 0.025..... Minimum = 0.10 [mu]g/
Range, [mu]g. [mu]g/trap Maximum = trap
150 [mu]g/trap. Maximum = 1800 [mu]g/
trap
Sampling Duration Required: Minimum = 30 minutes Minimum = 24 hours
limits on sample times. Maximum = 24 hours.. Maximum = 10 days
Sampling Temperature 200 to 375F. thn-eq>F
Sampling Rate Required...... 0.2 to 0.6 L/min; 0.2 to 0.6 L/min;
start at 0.4 L/min start at 0.4 L/min
Must be constant Must be constant
proportion within +/ proportion of stack
- 25% if greater flowrate within +/-
than 12 hours; 25%
constant rate
within +/- 25 % if
less than 12 hours.
------------------------------------------------------------------------
7.0 Analysis by AF, Reagents and Standards.
For analysis by AF, use Method 1631, Sections 7.1-7.3 and 7.5-
7.12 for laboratory reagents and standards. Refer to Method 29 or
ASTM Method 6784-02 for analysis by AA.
7.1 Reagent Water. Same as Method 1631, Section 7.1.
7.2 Air. Same as Method 1631, Section 7.2.
7.3 Hydrochloric Acid. Same as Method 1631, Section 7.3.
7.4 Stannous Chloride. Same as Method 1631, Section 7.5.
7.5 Bromine Monochloride (BrCl, 0.01N). Same as Method 1631,
Section 7.6.
7.6 Hg Standards. Same as Method 1631, Sections 7.7 to 7.11.
7.7 Nitric Acid. Reagent grade, low Hg.
7.8 Sulfuric Acid. Reagent grade, low Hg.
7.9 Nitrogen. Same as Method 1631, Section 7.12.
7.10 Argon. Same as Method 1631, Section 7.13.
8.0 Sample Collection and Transport.
8.1 Pre-Test.
8.1.1 Site information should be obtained in accordance with
Method 1 (40 CFR part 60, appendix A). Identify a location that has
been shown to be free of stratification for SO2 and
NOX through concentration measurement traverses for those
gases. An estimation of the expected Hg concentration is required to
establish minimum sample volumes. Based on estimated minimum sample
volume and normal sample rates for each size trap used, determine
sampling duration with the data provided in Table 324-1.
8.1.2 Sorbent traps must be obtained from a reliable source such
that high quality control and trace cleanliness are maintained.
Method detection limits will be adversely affected if adequate
cleanliness is not maintained. Sorbent traps should be handled only
with powder-free low Hg gloves (vinyl, latex, or nitrile are
acceptable) that have not touched any other surface. The sorbent
traps should not be removed from their clean storage containers
until after the preliminary leak check has been completed. Field
efforts at clean handling of the sorbent traps are key to the
success of this method.
8.1.3 Assemble the sample train according to Figure 324-1,
except omit the sorbent trap.
8.1.4 Preliminary Leak Check. Perform system leak check without
the single or dual sorbent traps in place. This entails plugging the
end of the probe to which each sorbent trap will be affixed, and
using the vacuum pump to draw a vacuum in each sample train. Adjust
the vacuum in the sample train to 15 inches Hg. A rotameter on the
dry gas meter will indicate the leakage rate. The leakage rate must
be less than 2 percent of the planned sampling rate.
8.1.5 Release the vacuum in the sample train, turn off the pump,
and affix the sorbent trap to the end of the probe, using clean
handling procedures. Leave the flue gas end of the sorbent trap
plugged.
8.1.6 Pre-test Leak Check. Perform a leak check with the Sorbent
trap in place. Use the sampling vacuum pump to draw a vacuum in the
sample train. Adjust the vacuum in the sample train to 15 inches Hg.
A rotameter on the dry gas meter will indicate the leakage rate.
Record the leakage rate. The leakage rate must be less than 2
percent of the planned sampling rate. Once the leak check passes
this criterion, carefully release the vacuum in the sample train
(the sorbent trap must not be exposed to abrupt changes in pressure
or to backflow), then re-cap the flue gas end of the sorbent trap
until the probe is ready for insertion. The sorbent trap packing
beds must be undisturbed by the leak test to prevent gas channeling
through the media during sampling.
8.1.7 Use temperature controllers to heat the portions of the
trains that require it. The sorbent trap must be maintained between
200 and 375 F during sampling.
8.1.8 Gas temperature and static pressure must be considered
prior to sampling in order to maintain proper safety precautions
during sampling.
8.2 Sample Collection.
8.2.1 Remove the plug from the end of a sorbent trap and store
it in a clean sorbent trap storage container. Remove the sample duct
port cap and insert the probe. Secure the probe and ensure that no
leakage occurs between the duct and environment.
8.2.2 Record initial data including the start time, starting dry
gas meter readings, and the name of the field tester(s). Set the
initial sample flow rate to 0.4 L/min (+/- 25 percent).
8.2.3 For constant-flow sampling (samples less than 12 hours in
duration), every 10-15 minutes during the sampling period: record
the time, the sample flow rate, the gas meter readings, the duct
temperature, the flow meter temperatures, temperatures of heated
equipment such as the vacuum lines and the probes (if heated), and
the sampling vacuum reading. Adjust the sample rate as needed,
maintaining constant sampling within +/- 25 percent of the initial
reading.
8.2.4 For constant proportion sampling (samples 12 hours or
greater in duration), every hour during the sampling period: record
the time, the sample flow rate, the gas meter readings, the duct
temperature, the flow meter temperatures, temperatures of heated
equipment such as the vacuum lines and the probes (if heated), and
the sampling vacuum readings. Also record the stack flow rate
reading, whether provided as a CEM flow monitor signal, a pitot
probe or other direct flow indication, or a plant input signal.
Adjust the sampling rate to maintain proportional sampling within +/
- 25 percent relative to the total stack flowrate.
8.2.5 Obtain and record operating data for the facility during
the test period, including total stack flowrate and the oxygen
concentration at the flue gas test location. Barometric pressure
must be obtained for correcting sample volume to standard
conditions.
8.2.6 Post Test Leak Check. When sampling is completed, turn off
the sample pump, remove the probe from the port and carefully re-
plug the end of the sorbent trap. Perform leak check by turning on
the sampling vacuum pumps with the plug in place. The rotameter on
the dry gas meters will indicate the leakage rates. Record the
leakage rate and vacuum. The leakage rate must be less than 2
percent of the actual sampling rate. Following the leak check,
carefully release the vacuum in the sample train.
8.2.7 Sample Recovery. Recover each sampled sorbent trap by
removing it from the probe, plugging both ends with the clean caps
provided with the sorbent trap, and then wiping any dirt off the
outside of the sorbent trap. Place the sorbent trap into the clean
sample storage container in which it was provided, along with the
data sheet that includes the post-test leak check, final volume, and
test end time.
8.3 Quality Control Samples and Requirements.
8.3.1 Field blanks. Refer to Table 324-2.
8.3.2 Duplicate (paired or side by side) samples. Refer to
Section 8.6.6 of Performance Specification 12A of 40 CFR part 60,
appendix B for this criteria.
8.3.3 Breakthrough performance data (``B'' bed in each trap, or
second traps behind). Refer to Table 324-2.
8.3.4 Field spikes (sorbent traps spiked with Hg in the lab and
periodically sampled in the field to determine overall accuracy).
Refer to Table 324-2.
[[Page 4739]]
8.3.5 Laboratory matrix and matrix spike duplicates. Refer to
Table 324-2.
9.0 Quality Control.
Table 324-2 summarizes the major quantifiable QC components.
Table 324-2.--Quality Control for Samples
----------------------------------------------------------------------------------------------------------------
QA/QC specification Acceptance criteria Frequency Corrective action
----------------------------------------------------------------------------------------------------------------
Leak-check........................... <2% of sampling rate... Pre and post-sampling.. Pre-sampling: repair
leak. Post-sampling:
Flag data and repeat
run if for regulatory
compliance.
Sample Flow Rate for samples less 0.4 L/min initially and Throughout run every 10- Adjust when data is
than 12 hours in duration. +/- 25% of initial 15 minutes. recorded.
rate throughout run.
Sample Flow Rate for samples greater 0.4 L/min initially and Throughout run every Adjust when data is
than 12 hours in duration. maintain +/- 25% of hour. recorded.
ratio to flue gas flow
rate throughout
sampling.
Sorbent trap laboratory blank (same <5 ng/trap and a 3 per analysis set of .......................
lot as samples). standard deviation of 20 sorbent traps.
<1.0 ng/trap (n=3).
Sorbent trap field blank (same lot as <5 ng/trap and a 1 per every 10 field .......................
samples). standard deviation of samples collected.
<1.0 ng/trap (n=3) OR
<5% of average sample
collected.
B-Trap Bed Analysis.................. <2% of A-Trap Bed Value Every sample........... .......................
OR < 5 ng/trap.
Paired Train Results................. Same as Section 8.6.6 .......................
of PS-12A of 40 CFR
Part 60, Appendix B.
Field Spikes......................... 80% to 120% recovery... For long-term If the first 4 field
regulatory monitoring, spikes do not meet the
1 per every 3 samples +/- 20% criteria, take
for the first 12 corrective sampling
samples. and laboratory
measures and repeat at
the 1 per every 3
sample rate until the
+/- 20% criteria is
met.
Laboratory matrix and matrix spike 85% to 115% recovery... 1 per every 10 or 20 .......................
duplicates. samples--to be
determined.
----------------------------------------------------------------------------------------------------------------
10.0 Calibration and Standards.
Same as Sections 10.1, 10.2 and 10.4 of Method 1631.
10.1 Calibration and Standardization. Same as Sections 10.1 and
10.4 of Method 1631.
10.2 Bubbler System. Same as Section 10.2 of M1631.
10.3 Flow-Injection System. Not applicable.
11.0 Analytical Procedures.
11.1 Preparation Step. The sorbent traps are received and
processed in a low-Hg environment (class-100 laminar-flow hood and
gaseous Hg air concentrations below 20 ng/m3) following
clean-handling procedures. Any dirt or particulate present on the
exterior of the trap must be removed to avoid contamination of the
sample. The sorbent traps are then opened and the sorbent bed(s)
transferred to an appropriate sized trace-clean vessel. It is
recommended that the height of the trace-clean vessel be at least 3
times the diameter to facilitate a refluxing action.
11.2 Leaching Step. The sorbent trap is then subjected to a hot-
acid leach using a 70:30 ratio mixture of concentrated
HNO3/H2SO4. The acid volume must be
40 percent of the expected end volume of the digest after dilution.
The HNO3/H2SO4 acid to carbon ratio
should be approximately 35:1. The leachate is then heated to a
temperature of 50 to 60C for 1.5 to 2.0 hours in the
finger-tight capped vessels. This process may generate significant
quantities of noxious and corrosive gasses and must only be
performed in a well-ventilated fume hood. Care must be taken to
prevent excessive heated leaching of the samples as this will begin
to break down the charcoal material.
11.3 Dilution Step. After the leached samples have been removed
from the hot plate and allowed to cool to room temperature, they are
brought to volume with a 5 percent (v/v) solution of 0.01 N BrCl. As
the leaching digest contains a substantial amount of dissolved
gasses, add the BrCl slowly, especially if the samples are still
warm. As before, this procedure must be performed in a properly
functioning fume hood. The sample is now ready for analysis.
11.4 Hg Reduction and Purging. (Reference Section 11.2 of M1631
except that NH2OH is not used.)
11.4.1 Bubbler System. Pipette an aliquot of the digested sample
into the bubbler containing pre-blanked reagent water and a soda
lime trap connected to the exhaust port. Add stannous chloride
(SnCl2) to reduce the aliquot and then seal the bubbler.
Connect gold sample traps to the end of the soda lime trap as shown
in Figures 1 and 2 of Method 1631. Finally, connect the
N2 lines and purge for 20 minutes. The sample trap can
then be added into the analytical train. M1631, Section 11.2.1.
11.4.2 Flow Injection System. If required.
11.5 Desorption of Hg from the gold trap, and peak evaluation.
Use Section 11.3 and 11.4 in M1631.
11.6 Instrument Calibration. Analyze the standards by AA or AF
following the guidelines specified by the instrument manufacturer.
Construct a calibration curve by plotting the absorbances of the
standards versus [mu]g/l Hg. The R2 for the calibration
curve should be 0.999 or better. If the curve does not have an
R2 value equal to or better than 0.999 then the curve
should be rerun. If the curve still does not meet this criteria then
new standards should be prepared and the instrument recalibrated.
All calibration points contained in the curve must be within 10
percent of the calibration value when the calibration curve is
applied to the calibration standards.
11.7 Sample Analysis. Analyze the samples in duplicate following
the same procedures used for instrument calibration. From the
calibration curve, determine sample Hg concentrations. To determine
total Hg mass in each sample fraction, refer to calculations in
Section 15. Record all sample dilutions.
11.8 Continued Calibration Performance. To verify continued
calibration performance, a continuing calibration check standard
should be run every 10 samples. The measured Hg concentration of the
continuing calibration check standard must be within 10 percent of
the expected value.
11.9 Measurement Precision. The QA/QC for the analytical portion
of this method is that every sample, after it has been prepared, is
to be analyzed in duplicate with every tenth sample analyzed in
triplicate. These results must be within 10 percent of each other.
If this is not the case, then the instrument must be recalibrated
and the samples reanalyzed.
11.10 Measurement Accuracy. Following calibration, an
independently prepared standard (not from same calibration stock
solution) should be analyzed. In addition, after every ten samples,
a known spike sample (standard addition) must be analyzed.
[[Page 4740]]
The measured Hg content of the spiked samples must be within 10
percent of the expected value.
11.11 Independent QA/QC Checks. It is suggested that the QA/QC
procedures developed for a test program include submitting, on
occasion, spiked Hg samples to the analytical laboratory by either
the prime contractor, if different from the laboratory, or an
independent organization. The measured Hg content of reference
samples must be within 15 percent of the expected value. If this
limit is exceeded, corrective action (e.g., re-calibration) must be
taken and the samples re-analyzed.
11.12 Quality Assurance/Quality Control. For this method, it is
important that both the sampling team and analytical people be very
well trained in the procedures. This is a complicated method that
requires a high-level of sampling and analytical experience. For the
sampling portion of the QA/QC procedure, both solution and field
blanks are required. It should be noted that if high-quality
reagents are used and care is taken in their preparation and in the
train assembly, there should be little, if any, Hg measured in
either the solution or field blanks.
11.13 Solution Blanks. Solution blanks must be taken and
analyzed every time a new batch of solution is prepared. If Hg is
detected in these solution blanks, the concentration is subtracted
from the measured sample results. The maximum amount that can be
subtracted is 10 percent of the measured result or 10 times the
detection limit of the instrument which ever is lower. If the
solution blanks are greater than 10 percent the data must be flagged
as suspect.
11.14 Field Blanks. A field blank is performed by assembling a
sample train, transporting it to the sampling location during the
sampling period, and recovering it as a regular sample. These data
are used to ensure that there is no contamination as a result of the
sampling activities. A minimum of one field blank at each sampling
location must be completed for each test site. Any Hg detected in
the field blanks cannot be subtracted from the results. Whether or
not the Hg detected in the field blanks is significant is determined
based on the QA/QC procedures established prior to the testing. At a
minimum, if field blanks exceed 30 percent of the measured value at
the corresponding location, the data must be flagged as suspect.
12.0 Calculations and Data Analysis.
Use Section 12 in M1631.
13.0 Constant Proportion Sampling.
Calculate the Sample Rate/Stack Flow = ``x.'' ``X'' must be
maintained within 0.75 ``x'' to 1.25 ``x'' for sampling times in
excess of 12 hours. For mass emission rate calculations, use the
flow CEM total measured flow corresponding to the sorbent trap
sample time period.
14.0 Sampling and Data Summary Calculations.
Refer to 40 CFR part 60, appendix A, Methods 2, 4, and 5 for
example calculations.
15.0 Pollution Prevention.
Refer to Section 13 in Method 1631.
16.0 Waste Management.
Refer to Section 14 in Method 1631.
17.0 Bibliography.
17.1 EPA Method 1631, Revision E ``Mercury in Water by
Oxidation, Purge and Trap, and Cold Vapor Atomic Fluorescence
Spectrometry,'' August 2002.
17.2 ``Comparison of Sampling Methods to Determine Total and
Speciated Mercury in Flue Gas,'' CRADA F00-038 Final Report, DOE/
NETL-2001/1147, January 4, 2001.
17.3 40 CFR part 60, appendix A, ``Method 29--Determination of
Metals Emissions from Stationary Sources.''
17.4 40 CFR part 60, appendix B, ``Performance Specification
12A, Specification and Test Procedures for Total Vapor Phase Mercury
Continuous Emission Monitoring Systems in Stationary Sources.''
17.5 ASTM Method D6784-02, ``Standard Test Method for Elemental,
Oxidized, Particle-bound and Total Mercury in Flue Gas Generated
from Coal-Fired Stationary Sources (Ontario Hydro Method).''
Option 2--Proposed Amendments to Parts 60 and 63
PART 60--[AMENDED]
1. The authority citation for part 60 continues to read as follows:
Authority: 42 U.S.C. 7401, et seq.
2. Section 60.17 is amended by adding paragraph (a)(65) to read as
follows:
Sec. 60.17 Incorporations by Reference.
* * * * *
(a) * * *
(65) ASTM D6784-02, Standard Test Method for Elemental, Oxidized,
Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired
Stationary Sources (Ontario Hydro Method), for appendix B to part 60,
Performance Specification 12A.
* * * * *
Subpart Da--[Amended]
3. Subpart Da is amended by:
a. Redesignate Sec. 60.49a as Sec. 60.51a;
b. Redesignate Sec. 60.48a as Sec. 60.50a;
c. Redesignate Sec. 60.47a as Sec. 60.49a;
d. Redesignate Sec. 60.46a as Sec. 60.48a;
e. Redesignate Sec. 60.45a as Sec. 60.47a; and
f. Adding new Sec.Sec. 60.45a and 60.46a to read as follows:
Sec. 60.45a Standard for Mercury
(a) For each coal-fired electric utility steam generating unit
other than an integrated gasification combined cycle (IGCC) electric
utility steam generating unit, you must meet each mercury (Hg)
emissions limit in paragraphs (a)(1) through (5) of this section that
applies to you. The Hg emissions limits in paragraphs (a)(1) through
(5) of this section are based on a 12-month rolling average using the
procedures in Sec. 60.50a(h).
(1) For each coal-fired electric utility steam generating unit that
burns only bituminous coal, you must not discharge into the atmosphere
any gases from a new affected source which contain Hg in excess of 6.0
x 10 -6 pound per Megawatt hour (lb/MWh) or 0.0060 lb/
gigawatt-hour (GWh) on an output basis. The SI equivalent is 0.00075
nanograms per joule (ng/J).
(2) For each coal-fired electric utility steam generating unit that
burns only subbituminous coal, you must not discharge into the
atmosphere any gases from a new affected source which contain Hg in
excess of 20 x 10 -6 lb/MWh or 0.020 lb/GWh on an output
basis. The SI equivalent is 0.0025 ng/J.
(3) For each coal-fired electric utility steam generating unit that
burns only lignite, you must not discharge into the atmosphere any
gases from a new affected source which contain Hg in excess of 62 x 10
-6 lb/MWh or 0.062 lb/GWh on an output basis. The SI
equivalent is 0.0078 ng/J.
(4) For each coal-burning electric utility steam generating unit
that burns only coal refuse, you must not discharge into the atmosphere
any gases from a new affected source which contain Hg in excess of 1.1
x 10 -6 lb/MWh or 0.0011 lb/GWh on an output basis. The SI
equivalent is 0.00087 ng/J.
(5) For each coal-fired electric utility steam generating unit that
burns a blend of coals from different coal ranks (i.e., bituminous
coal, subbituminous coal, lignite) or a blend of coal and coal refuse,
you must not discharge into the atmosphere any gases from a new
affected source that contain Hg in excess of the monthly unit-specific
Hg emissions limit established according to paragraph (a)(5)(i) or (ii)
of this section, as applicable to your unit.
(i) If you operate a coal-fired electric utility steam generating
unit that burns a blend of coals from different coal ranks or a blend
of coal and coal refuse, you must not discharge into the atmosphere any
gases from a new affected source that contain Hg in excess of the
computed weighted Hg emissions limit based on the proportion of energy
output (in Btu) contributed by each coal-rank burned during the
compliance period and its applicable Hg emissions limit in paragraphs
(a)(1) through (4) of this section as determined using Equation 1 of
this section. You must meet the weighted Hg emissions limit calculated
using Equation 1 of this section by calculating the unit emission rate
based on the total Hg loading of the unit and the total Btu or megawatt
hours contributed by all fuels burned during the compliance period.
[[Page 4741]]
[GRAPHIC] [TIFF OMITTED] TP30JA04.020
Where:
ELb = Total allowable Hg in lb/MWh that can be emitted to
the atmosphere from any affected source being averaged under the
blending provision.
ELi = Hg emissions limit for the subcategory that applies to
affected source i, lb/MWh.
HHi = Electricity output from affected source i during the
production period related to the corresponding Hi that falls
within the compliance period, gross MWh generated by the electric
utility steam generating unit.
n = Number of coal ranks being averaged for an affected source.
(ii) If you operate a coal-fired electric utility steam generating
unit that burns a blend of coals from different coal ranks or a blend
of coal and coal refuse together with one or more non-regulated,
supplementary fuels, you must not discharge into the atmosphere any
gases from the unit that contain Hg in excess of the computed weighted
Hg emission limit based on the proportion of electricity output (in
MWh) contributed by each coal rank burned during the compliance period
and its applicable Hg emissions limit in paragraphs (a)(1) through (4)
of this section as determined using Equation 1 of this section. You
must meet the weighted Hg emissions limit calculated using Equation 1
of this section by calculating the unit emission rate based on the
total Hg loading of the unit and the total megawatt hours contributed
by both regulated and nonregulated fuels burned during the compliance
period.
(b) For each IGCC electric utility steam generating unit, you must
not discharge into the atmosphere any gases from a new affected source
which contain Hg in excess of 20 x 10-\6\ lb/MWh or 0.020
lb/GWh on an output basis. The SI equivalent is 0.0025 ng/J. This Hg
emissions limit is based on a 12-month rolling average using the
procedures in Sec. 60.50a(g).
Sec. 60.46a Standard for Nickel
(a) On and after the date on which the initial performance test
required to be conducted under Sec. 60.8 is completed, the owner or
operator of each oil-fired unit subject to the provisions of this
subpart shall not discharge into the atmosphere any gases from an oil-
fired electric utility steam generating unit which contain Ni in excess
of 0.0008 lb/MWh on an output basis. The SI equivalent is 0.010 ng/J.
(b) The emissions limit for an oil-fired electric utility steam
generating unit in paragraph (a) of this section does not apply if the
owner or operator uses distillate oil as fuel. Except as noted in
paragraph (e) of this section, the emissions limit in paragraph (a) of
this section will apply immediately if the owner or operator
subsequently uses a fuel other than distillate oil.
(c) If you use an ESP to meet a Ni emissions limit in this subpart,
you must operate the ESP such that the hourly average voltage and
secondary current (or total power input) do not fall below the limit
established in the initial or subsequent performance test.
(d) If you use a control device or combination of control devices
other than an ESP to meet the Ni emissions limit, or you wish to
establish and monitor an alternative operating limit and alternative
monitoring parameters for an ESP, you must apply to the Administrator
for approval of alternative monitoring under Sec. 60.13(i).
(e) If you comply with the requirements in Sec. 60.46a(b) for
switching fuel, and you must switch fuel because of an emergency, you
must notify the Administrator in writing within 30 days of using a fuel
other than distillate oil.
4. Newly redesignated Sec. 60.48a is amended by:
a. Revising paragraph (c);
b. In paragraph (h) by revising the existing references from ``Sec.
60.47a'' to ``Sec. 60.49a'';
c. In paragraph (i) by revising the existing references for
``Sec.Sec. 60.47a(c),'' ``60.47a(l),'' and ``60.47a(k)'' to ``Sec.Sec.
60.49a(c),'' ``60.49a(l),'' and ``60.49a(k),'' respectively;
d. In paragraph (j)(2) by revising the existing references from
``Sec. 60.47a'' to ``Sec. 60.49a'' twice;
e. In paragraph (k)(2)(ii) by revising the existing references from
``Sec. 60.47a'' and ``60.47a(l)'' to ``Sec. 60.49a'' and ``60.49a(l),''
respectively; in paragraph (k)(2)(iii) by revising the existing
references from ``Sec. 60.47a(k)'' to ``Sec. 60.49a(k)''; and in
paragraph (k)(2)(iv) by revising the existing references from ``Sec.
60.47a(l)'' to ``Sec. 60.49a(l)''; and
f. Adding new paragraphs (m) and (n).
The revision and additions read as follows:
Sec. 60.48a Compliance provisions.
* * * * *
(c) The particulate matter emission standards under Sec. 60.42a,
the nitrogen oxides emission standards under Sec. 60.44a, the Hg
emission standards under Sec. 60.45a, and the Ni emission standards
under Sec. 60.46a apply at all times except during periods of startup,
shutdown, or malfunction.
* * * * *
(m) Compliance provisions for sources subject to Sec. 60.45a. The
owner or operator of an affected facility subject to Sec. 60.45a (new
sources constructed after January 30, 2004) shall calculate Hg
emissions by multiplying the average hourly Hg output concentration
measured according to the provisions of Sec. 60.49a(c) by the average
hourly flow rate measured according to the provisions of Sec. 60.49a(l)
and divided by the average hourly gross heat rate measured according to
the provisions in Sec. 60.49a(k).
(n) Compliance provisions for sources subject to Sec. 60.46a. (1)
The owner or operator of an affected facility subject to Sec. 60.46a(a)
(new source constructed after January 30, 2004) shall calculate Ni
emissions rate according to the procedures outlined in Sec. 60.50a(i).
5. Newly redesignated Sec. 60.49a is amended by:
a. In paragraph (c)(2) by revising the existing references from
``Sec. 60.49a'' to ``Sec. 60.51a'' twice;
b. In paragraph (g) by revising the existing reference from ``Sec.
60.46a'' to ``Sec. 60.48a.''
c. Revising paragraph (k) introductory text; and
d. Adding new paragraphs (p) through (s).
The revision and additions read as follows:
Sec. 60.49a Emission monitoring.
* * * * *
(k) The procedures specified in paragraphs (k)(1) through (3) of
this section shall be used to determine compliance with the output-
based standards under Sec.Sec. 60.42a(c), 60.43a(i), 60.44a(d)(1),
60.44a(e), 60.45a, and 60.46a.
* * * * *
(p) The owner or operator of an affected facility demonstrating
compliance with an Hg limit in Sec. 60.45a shall install and operate a
continuous emissions monitoring system (CEMS) to measure and record the
concentration of Hg in the exhaust gases from each stack according to
the requirements in paragraphs (p)(1) through (3) of this section.
(1) The owner or operator must install, operate, and maintain each
CEMS according to Performance Specification 12A in 40 CFR part 60,
appendix B.
(2) The owner or operator must conduct a performance evaluation of
[[Page 4742]]
each CEMS according to the requirements of Sec. 60.13 and Performance
Specification 12A in 40 CFR part 60, appendix B.
(3) The owner or operator must operate each CEMS according to the
requirements in paragraphs (p)(3)(i) through (iv) of this section.
(i) As specified in Sec. 60.13(e)(2), each CEMS must complete a
minimum of one cycle of operation (sampling, analyzing, and data
recording) for each successive 15-minute period.
(ii) The owner or operator must reduce CEMS data as specified in
Sec. 60.13(h).
(iii) Each CEMS must determine and record the 1-hour average
emissions using all the hourly averages collected for periods during
which the CEMS is not out of control.
(iv) The owner or operator must record the results of each
inspection, calibration, and validation check.
(4) Mercury CEMS data collection must conform to paragraphs
(p)(4)(i) through (iv) of this section.
(i) A complete day of data for continuous monitoring is 18 hours or
more in a 24-hour period.
(ii) A complete month of data for continuous monitoring is 21 days
or more in a calendar month.
(iii) If you collect less than 21 days of continuous emissions
data, you must discard the data collected that month and replace the
data with the mean of the individual monthly emission rate values
determined in the last 12 months.
(iv) If you collect less than 21 days per monthly period of
continuous data again in that same 12-month rolling average cycle, you
must discard the data collected that month and replace that data with
the highest individual monthly emission rate determined in the last 12
months.
(q) As an alternative to the CEMS required in paragraph (p) of this
section, the owner or operator must monitor Hg emissions using Method
324 in 40 CFR part 63, appendix A.
(r) The owner or operator of an affected facility which uses an ESP
to meet a Ni limit in Sec. 60.46a shall install and operate a
continuous parameter monitoring system (CPMS) to measure and record the
voltage and secondary current (or total power input) to the control
device according to the requirements in paragraphs (r)(1) through (3)
of this section.
(1) Each CPMS must complete a minimum of one cycle of operation for
each successive 15-minute period. The owner or operator must have a
minimum of four successive cycles of operation to have a valid hour of
data.
(2) Each CPMS must determine the 1-hour block average of all
recorded readings.
(3) The owner or operator must record the results of each
inspection, calibration, and validation check for a CPMS.
(s) The owner or operator shall prepare and submit to the
Administrator for approval a unit-specific monitoring plan for each
monitoring system. The owner or operator shall comply with the
requirements in your plan. The plan must address the requirements in
paragraphs (s)(1) through (6) of this section.
(1) Installation of the CMS sampling probe or other interface at a
measurement location relative to each affected process unit such that
the measurement is representative of control of the exhaust emissions
(e.g., on or downstream of the last control device);
(2) Performance and equipment specifications for the sample
interface, the pollutant concentration or parametric signal analyzer,
and the data collection and reduction systems;
(3) Performance evaluation procedures and acceptance criteria
(e.g., calibrations);
(4) Ongoing operation and maintenance procedures in accordance with
the general requirements of Sec. 60.13(d);
(5) Ongoing data quality assurance procedures in accordance with
the general requirements of Sec. 60.13; and
(6) Ongoing recordkeeping and reporting procedures in accordance
with the general requirements of Sec. 60.7.
6. Newly redesignated Sec. 60.50a is amended by:
a. In paragraph (c)(5) by revising the existing references from
``Sec. 60.47a(b) and (d)'' to ``Sec. 60.49a(b) and (d),'' respectively;
b. In paragraph (d)(2) by revising the existing references from
``Sec. 60.47a(c) and (d)'' to ``Sec. 60.49a(c) and (d),'' respectively;
c. In paragraph (e)(2) by revising the existing reference from
``Sec. 60.46a(d)(1)'' to ``Sec. 60.48a(d)(1)''; and
d. Adding new paragraphs (g) through (j).
The additions read as follows:
Sec. 60.50a Compliance determination procedures and methods.
* * * * *
(g) For the purposes of determining compliance with the emission
limits in Sec.Sec. 60.45a and 60.46a, the owner or operator of an
electric utility steam generating unit which is also a cogeneration
unit shall use the procedures in paragraphs (g)(1) and (2) of this
section to calculate emission rates based on electrical output to the
grid plus half of the equivalent electrical energy in the unit's
process stream.
(1) All conversions from Btu/hr unit input to MWe unit output must
use equivalents found in 40 CFR 60.40(a)(1) for electric utilities
(i.e., 250 million Btu/hr input to an electric utility steam generating
unit is equivalent to 73 MWe input to the electric utility steam
generating unit); 73 MWe input to the electric utility steam generating
unit is equivalent to 25 MWe output from the boiler electric utility
steam generating unit; therefore, 250 million Btu input to the electric
utility steam generating unit is equivalent to 25 MWe output from the
electric utility steam generating unit).
(2) Use the Equation 1 of this section to determine the
cogeneration Hg or Ni emission rate over a specific compliance period.
[GRAPHIC] [TIFF OMITTED] TP30JA04.021
Where:
ERcogen = Cogeneration Hg or Ni emission rate over a
compliance period in lb/MWh;
E = Mass of Hg or Ni emitted from the stack over the same compliance
period (lb);
Vgrid = Amount of energy sent to the grid over the same
compliance period (MWh); and
Vprocess = Amount of energy converted to steam for process
use over the same compliance period (MWh).
(h) The owner or operator shall determine compliance with the Hg
limit in Sec. 60.45a according to the procedures
[[Page 4743]]
in paragraphs (h)(1) through (3) of this section.
(1) The owner or operator shall demonstrate compliance by
calculating the arithmetic average of all weekly emission rates for Hg
for the 12 successive calendar months, except for data obtained during
startup, shutdown, or malfunction.
(2) If a CEMS is used to demonstrate compliance, follow the
procedures in paragraphs (h)(2)(i) through (ii) of this section to
determine the 12-month rolling average.
(i) Calculate the total mass of Hg emissions over a month (M), in
micrograms ([mu]g), using Equation 2 of this section.
[GRAPHIC] [TIFF OMITTED] TP30JA04.022
Where:
M = Total mass of Hg emissions, ([mu]g);
C = Concentration of Hg recorded by CEMS per Performance Specification
12A (40 CFR part 60, appendix B), micrograms per dry standard cubic
meter ([mu]g/dscm);
V = Volumetric flow rate recorded at the same frequency as the CEMS
reading for the Hg concentration indicated in PS-12A, cubic meters per
hour (dscm/hr); and
t = total time period over which mass measurements are collected, (hr).
(ii) Calculate the Hg emission rate for an output-based limit (lb/
hr) using Equation 3 of this section:
[GRAPHIC] [TIFF OMITTED] TP30JA04.035
Where:
ER = Hg emission rate, (lb/hr);
M = Total mass of Hg emissions, ([mu]g);
Conversion factor = 2.205 x 10-\9\; and
TPoutput-based = Total power, megawatt-hours (MWh).
(3) If you use Method 324 (40 CFR part 63, appendix B), determine
the 12-month rolling average Hg emission rate according to the
applicable procedures in paragraphs (h)(3)(i) through (iv) of this
section.
(i) Sum the Hg concentrations for the emission rate period, ([mu]g/
dscm).
(ii) Calculate the total volumetric flow rate for the emission rate
period, (dscm).
(iii) Multiply the total Hg concentration times the total
volumetric rate to obtain the total mass of Hg for the emission rate
period in micrograms.
(iv) Calculate the Hg emission rate for an output-based limit (lb/
hr) using Equation 3 of this section.
(i) The owner or operator shall determine compliance with the Ni
limit in Sec. 60.46a according to the procedures in paragraphs (i)(1)
through (2) of this section.
(1) Ni emissions concentration for compliance under Sec. 60.46a is
determined by the three-run average (nominal 1-hour runs) by Method 29
of 40 CFR part 60, Appendix A, for the initial and subsequent
performance tests.
(2) Use the applicable procedures in paragraphs (2)(i) through (v)
of this section to convert the Method 29 Ni emissions measurement to
the output-based format for comparison to the Sec. 60.46a Ni emission
limit.
(i) Sum the Ni concentrations obtained from the Method 29 test
runs, milligrams per dscm (mg/dscm).
(ii) Calculate the total volumetric flow rate obtained during the
Method 29 test runs, (dscm).
(iii) Multiply the total Ni concentration times the total
volumetric flow rate for the duration of the initial compliance testing
period to obtain the total mass of Ni in milligrams.
(iv) Calculate the output-based Ni emissions rate in a lb/ format
using Equation 4 of this section.
[GRAPHIC] [TIFF OMITTED] TP30JA04.023
Where:
ER = Ni emission rate, (lb/hr);
M = Total mass of Ni emissions, (mg);
Conversion factor = 2.205 x 10-\6\; and
TPoutput-based = Total power, (MWh).
(3) Compliance with the Ni emission limits under Sec. 60.46a is
determined by the three-run average (nominal 1-hour runs) by Method 29
for the initial and subsequent performance tests.
(j) Quarterly accuracy determinations and daily calibration drift
tests for gaseous Hg CEMS shall be performed in accordance with
Procedure 1 (appendix F of 40 CFR part 60). Annual RATAs for Hg sorbent
trap monitoring systems shall also be performed in accordance with
Procedure 1.
7. Newly redesignated Sec. 60.51a is amended by:
a. Revising paragraph (a);
b. In paragraph (c) introductory text by revising the existing
references from ``Sec. 60.47a'' and ``Sec. 60.46a(h)'' to ``Sec.
60.49a'' and ``Sec. 60.48a(h),'' respectively;
c. In paragraph (d)(1) by revising the existing reference from
``Sec. 60.46a(d)'' to ``Sec. 60.48a(d)''; and
d. In paragraph (e)(1) by revising the existing reference from
``Sec. 60.48a'' to ``Sec. 60.50a.''
The revisions and additions read as follows:
Sec. 60.51a Reporting requirements.
(a) For sulfur dioxide, nitrogen oxides, particulate matter, Hg,
and Ni emissions, the performance test data from the initial and
subsequent performance test and from the performance evaluation of the
continuous monitors (including the transmissometer) are submitted to
the Administrator.
* * * * *
8. Section 60.52a is added to read as follows:
Sec. 60.52a Recordkeeping Requirements
The owner or operator of an affected facility subject to the
emissions limitations in Sec. 60.45a or Sec. 60.46a shall maintain
records of all information needed to demonstrate compliance including
performance tests, monitoring data, fuel analyses, and calculations.
Subpart GGGG--[Added]
9. Part 60 is amended by adding subpart GGGG to read as follows:
Subpart GGGG--Emission Guidelines and Compliance Times for Oil-
fired Electric Utility Steam Generating Units
Sec.
60.4000 Scope
60.4005 Definitions
60.4010 Designated Facilities
60.4015 Emission Guidelines for Oil-fired Electric Utility Steam
Generating Units
60.4020 Compliance Provisions and Performance Testing
60.4025 Reporting and Recordkeeping Guidelines
60.4030 Compliance Times
Sec. 60.4000 Scope
This subpart contains emission guidelines and compliance times for
the control of certain designated pollutants from certain designated
electric utility steam generating units in accordance with section
111(d) of the Act and subpart B of this part.
Sec. 60.4005 Definitions
Terms used but not defined in this subpart have the meaning given
them in the Act and in subparts A, B, and Da of this part.
Sec. 60.4010 Designated Facilities
(a) The designated facility to which the emission guidelines apply
is each existing electric utility steam generating unit for which
construction, reconstruction or modification was commenced before
January 30, 2004.
(b) Physical or operational changes made to an existing electric
utility steam generating unit solely to comply with an emission
guideline are not considered a modification or reconstruction and
[[Page 4744]]
would not subject an existing electric utility steam generating unit to
the requirements of subpart Da (see Sec. 60.40a of subpart Da).
Sec. 60.4015 Emission Guidelines for Oil-fired Electric Utility Steam
Generating Units
For approval, a State plan shall include emission limits for nickel
(Ni) at least as protective as the provisions specified in paragraphs
(a) and (b) of this section.
(a) The emission limit for Ni contained in the gases discharged to
the atmosphere from a designated facility is 210 pounds of Ni per
trillion Btu (lb/TBtu) in an input-based format and 0.002 pounds of Ni
per megawatt hour (lb/MWh) in an output-based format. The SI equivalent
is 0.25 ng/J.
(b) The emission limit for Ni for oil-fired electric utility steam
generating units does not apply if the owner/operator permanently uses
distillate oil as fuel. Except as provided in paragraph (5) of this
section, the emissions limit for Ni for oil-fired electric utility
steam generating units will immediately apply if the owner/operator
subsequently uses a fuel other than distillate oil.
(c) If you use an electrostatic precipitator (ESP) to meet a Ni
emissions limit in this part, you must operate the ESP such that the
hourly average voltage and secondary current (or total power input) do
not fall below the limit established in the initial or subsequent
performance test.
(d) If you use a control device or combination of control devices
other than an ESP to meet the Ni emissions limit, or you wish to
establish and monitor an alternative operating limit and alternative
monitoring parameters for an ESP, you must apply to the Administrator
for approval of alternative monitoring under Sec. 60.13(i).
(e) If you comply with the requirements in Sec. 60.4015(b) for
switching fuel, and you must switch fuel because of an emergency, you
must notify the Administrator in writing within 30 days of using a fuel
other than distillate oil.
Sec. 60.4020 Compliance Provisions and Performance Testing
For approval, a State plan shall include the performance testing
compliance demonstration requirements as listed in paragraphs (a) and
(b) of this section.
(a) Affected facilities will conduct a performance test to
demonstrate compliance with this section no later than 180 days after
the initial startup or 180 days after publication of the final
amendments, whichever is later and annually thereafter. The performance
test is to be conducted using Method 29 of appendix A of this part to
determine Ni emission concentration in the flue gas stream. The Ni
emissions concentration for compliance under this part is determined by
the three-run average (nominal 1-hour runs) using Method 29 of appendix
A of this part for the initial and subsequent performance tests.
(b) The owner or operator shall demonstrate compliance with the Ni
limit in Sec. 60.46a according to the procedures in this paragraph to
convert the Method 29 Ni measurement from the performance test to the
selected format for comparison to the applicable Sec. 60.46a Ni
emission limits.
(1) Sum the Ni concentrations obtained from the Method 29 test
runs, milligrams per dscm (mg/dscm).
(2) Calculate the total volumetric flow obtained during the Method
29 test runs, (dscm).
(3) Multiply the total Ni concentration times the total volumetric
flow for the duration of the initial compliance testing period to
obtain the total mass of Ni in milligrams.
(4) Calculate the input-based Ni emissions rate in a lb/TBtu format
using Equation 1 of this section.
[GRAPHIC] [TIFF OMITTED] TP30JA04.024
Where:
ER = Ni emissions rate, (lb/TBtu);
M = Total mass of Ni emissions, (mg);
Conversion factor = 2.205 x 10-6; used to convert milligrams
to pounds; and
TPinput-based = Total power, (TBtu).
(5) Calculate the output-based Ni emissions rate in a lb/MWh format
using Equation 2 of this section.
[GRAPHIC] [TIFF OMITTED] TP30JA04.025
Where:
ER = Ni emissions rate, (lb/MWh);
M = Total mass of Ni emissions, (mg);
Conversion factor = 2.205 x 10-6; and
TPoutput-based = Total power, (MWh).
Sec. 60.4025 Reporting and Recordkeeping Guidelines
For approval, a State plan shall include the reporting and
recordkeeping provisions listed in Sec. 60.52a of subpart Da of this
part, as applicable.
Sec. 60.4030 Compliance Times
(a) Except as provided for under paragraph (b) of this section,
planning, awarding of contracts, and installation of electric utility
steam generating unit air emission control equipment capable of meeting
the emission guidelines established under Sec. 60.4015 shall be
accomplished within 30 months after the effective date of a State
emission standard for electric utility steam generating units.
APPENDIX B PART 60
10. Appendix B to part 60 is amended by adding in numerical
order new Performance Specification 12A to read as follows:
Performance Specification 12a--Specifications and Test Procedures for
Total Vapor Phase Mercury Continuous Emission Monitoring Systems in
Stationary Sources
1.0 Scope and Application
1.1 Analyte.
------------------------------------------------------------------------
Analyte CAS No.
------------------------------------------------------------------------
Mercury (Hg)................................................ 7439-97-6
------------------------------------------------------------------------
1.2 Applicability.
1.2.1 This specification is for evaluating the acceptability of
total vapor phase Hg continuous emission monitoring systems (CEMS)
installed on the exit gases from fossil fuel fired boilers at the
time of or soon after installation and whenever specified in the
regulations. The Hg CEMS must be capable of measuring the total
concentration in [mu]g/m3 (regardless of speciation) of
vapor phase Hg, and recording that concentration on a dry basis,
corrected to 20 degrees C and 7 percent CO2. Particle
bound Hg is not included. The CEMS must include a) a diluent
(CO2) monitor, which must meet Performance Specification
3 in 40 CFR part 60, appendix B, and b) an automatic sampling
system. Existing diluent and flow monitoring equipment can be used.
This specification is not designed to evaluate an installed
CEMS's performance over an extended period of time nor does it
identify specific calibration techniques and auxiliary procedures to
assess the CEMS's performance. The source owner or operator,
however, is responsible to calibrate, maintain, and operate the CEMS
properly. The Administrator may require, under CAA section 114, the
operator to conduct CEMS performance evaluations at other times
besides the initial test to evaluate the CEMS performance. See 40
CFR 60.13(c).
2.0 Summary of Performance Specification
Procedures for measuring CEMS relative accuracy, measurement
error and drift are outlined. CEMS installation and measurement
location specifications, and data reduction procedures are included.
Conformance of the CEMS with the Performance Specification is
determined.
3.0 Definitions
3.1 Continuous Emission Monitoring System (CEMS) means the total
equipment required for the determination of a pollutant
concentration. The system consists of the following major
subsystems:
3.2 Sample Interface means that portion of the CEMS used for one
or more of the following: sample acquisition, sample transport,
sample conditioning, and protection of the monitor from the effects
of the stack effluent.
[[Page 4745]]
3.3 Hg Analyzer means that portion of the CEMS that measures the
total vapor phase Hg mass concentration and generates a proportional
output.
3.4 Diluent Analyzer (if applicable) means that portion of the
CEMS that senses the diluent gas (CO2) and generates an
output proportional to the gas concentration.
3.5 Data Recorder means that portion of the CEMS that provides a
permanent electronic record of the analyzer output. The data
recorder can provide automatic data reduction and CEMS control
capabilities.
3.6 Span Value means the upper limit of the intended Hg
concentration measurement range. The span value is a value equal to
two times the emission standard.
3.7 Measurement Error (ME) means the difference between the
concentration indicated by the CEMS and the known concentration
generated by a reference gas when the entire CEMS, including the
sampling interface, is challenged. An ME test procedure is performed
to document the accuracy and linearity of the CEMS at several points
over the measurement range.
3.8 Upscale Drift (UD) means the difference in the CEMS output
responses to a Hg reference gas when the entire CEMS, including the
sampling interface, is challenged after a stated period of operation
during which no unscheduled maintenance, repair, or adjustment took
place.
3.9 Zero Drift (ZD) means the difference in the CEMS output
responses to a zero gas when the entire CEMS, including the sampling
interface, is challenged after a stated period of operation during
which no unscheduled maintenance, repair, or adjustment took place.
3.10 Relative Accuracy (RA) means the absolute mean difference
between the pollutant concentration(s) determined by the CEMS and
the value determined by the reference method (RM) plus the 2.5
percent error confidence coefficient of a series of tests divided by
the mean of the RM tests or the applicable emission limit.
4.0 Interferences [Reserved]
5.0 Safety
The procedures required under this performance specification may
involve hazardous materials, operations, and equipment. This
performance specification may not address all of the safety problems
associated with these procedures. It is the responsibility of the
user to establish appropriate safety and health practices and
determine the applicable regulatory limitations prior to performing
these procedures. The CEMS user's manual and materials recommended
by the reference method should be consulted for specific precautions
to be taken.
6.0 Equipment and Supplies
6.1 CEMS Equipment Specifications.
6.1.1 Data Recorder Scale. The CEMS data recorder output range
must include zero and a high level value. The high level value must
be approximately 2 times the Hg concentration corresponding to the
emission standard level for the stack gas under the circumstances
existing as the stack gas is sampled. If a lower high level value is
used, the CEMS must have the capability of providing multiple high
level values (one of which is equal to the span value) or be capable
of automatically changing the high level value as required (up to
specified high level value) such that the measured value does not
exceed 95 percent of the high level value.
6.1.2 The CEMS design should also provide for the determination
of response drift at both the zero and mid-level value. If this is
not possible or practical, the design must allow these
determinations to be conducted at a low-level value (zero to 20
percent of the high-level value) and at a value between 50 and 100
percent of the high-level value.
6.2 Reference Gas Delivery System. The reference gas delivery
system must be designed so that the flowrate of reference gas
introduced to the CEMS is the same at all three challenge levels
specified in Section 7.1 and at all times exceeds the flow
requirements of the CEMS.
6.3 Other equipment and supplies, as needed by the applicable
reference method used. See Section 8.6.2.
7.0 Reagents and Standards
7.1 Reference Gases.
7.1.1 Zero--N2 or Air. Less than 0.1 [mu]g Hg/m\3\.
7.1.2 Mid-level Hg\0\ and HgCl2. 40 to 60 percent of
span.
7.1.3 High-level Hg\0\ and HgCl2. 80 to 100 percent
of span.
7.2 Reagents and Standards. May be required for the reference
methods. See Section 8.6.2.
8.0 Performance Specification Test Procedure
8.1 Installation and Measurement Location Specifications.
8.1.1 CEMS Installation. Install the CEMS at an accessible
location downstream of all pollution control equipment. Since the Hg
CEMS sample system normally extracts gas from a single point in the
stack, use a location that has been shown to be free of
stratification for SO2 and NOX through
concentration measurement traverses for those gases. If the cause of
failure to meet the RA test requirement is determined to be the
measurement location and a satisfactory correction technique cannot
be established, the Administrator may require the CEMS to be
relocated.
Measurement locations and points or paths that are most likely
to provide data that will meet the RA requirements are listed below.
8.1.2 Measurement Location. The measurement location should be
(1) at least eight equivalent diameters downstream of the nearest
control device, point of pollutant generation, bend, or other point
at which a change of pollutant concentration or flow disturbance may
occur, and (2) at least two equivalent diameters upstream from the
effluent exhaust. The equivalent duct diameter is calculated as per
40 CFR part 60, appendix A, Method 1.
8.1.3 Hg CEMS Sample extraction Point. Use a sample extraction
point (1) no less than 1.0 meter from the stack or duct wall, or (2)
within the centroidal velocity traverse area of the stack or duct
cross section.
8.2 Reference Method (RM) Measurement Location and Traverse
Points. The RM measurement location should be at a point or points
in the same stack cross sectional area as the CEMS is located,
according to the criteria above. The RM and CEMS locations need not
be immediately adjacent. They should be as close as possible without
causing interference with one another.
8.3 Measurement Error (ME) Test Procedure. The Hg CEMS must be
constructed to permit the introduction of known (NIST traceable)
concentrations of elemental mercury (Hg\0\) and mercuric chloride
(HgCl2) separately into the sampling system of the CEMS
immediately preceding the sample extraction filtration system such
that the entire CEMS can be challenged. Inject sequentially each of
the three reference gases (zero, mid-level, and high level) for each
Hg species. CEMS measurements of each reference gas shall not differ
from their respective reference values by more than 5 percent of the
span value. If this specification is not met, identify and correct
the problem before proceeding.
8.4 Upscale Drift (UD) Test Procedure.
8.4.1 UD Test Period. While the affected facility is operating
at more than 50 percent of normal load, or as specified in an
applicable subpart, determine the magnitude of the UD once each day
(at 24-hour intervals) for 7 consecutive days according to the
procedure given in Sections 8.4.2 through 8.4.3.
8.4.2 The purpose of the UD measurement is to verify the ability
of the CEMS to conform to the established CEMS response used for
determining emission concentrations or emission rates. Therefore, if
periodic automatic or manual adjustments are made to the CEMS zero
and response settings, conduct the UD test immediately before these
adjustments, or conduct it in such a way that the UD can be
determined.
8.4.3 Conduct the UD test at the mid-level point specified in
Section 7.1. Evaluate upscale drift for elemental Hg
(Hg0) only. Introduce the reference gas to the CEMS.
Record the CEMS response and subtract the reference value from the
CEM value (see example data sheet in Figure 12A-1).
8.5 Zero Drift (ZD) Test Procedure.
8.5.1 ZD Test Period. While the affected facility is operating
at more than 50 percent of normal load, or as specified in an
applicable subpart, determine the magnitude of the ZD once each day
(at 24-hour intervals) for 7 consecutive days according to the
procedure given in Sections 8.5.2 through 8.5.3.
8.5.2 The purpose of the ZD measurement is to verify the ability
of the CEMS to conform to the established CEMS response used for
determining emission concentrations or emission rates. Therefore, if
periodic automatic or manual adjustments are made to the CEMS zero
and response settings, conduct the ZD test immediately before these
adjustments, or conduct it in such a way that the ZD can be
determined.
8.5.3 Conduct the ZD test at the zero level specified in Section
7.1. Introduce the zero gas to the CEMS. Record the CEMS response
and subtract the zero value from the CEM value (see example data
sheet in Figure 12A-1).
8.6 Relative Accuracy (RA) Test Procedure.
[[Page 4746]]
8.6.1 RA Test Period. Conduct the RA test according to the
procedure given in Sections 8.6.2 through 8.6.6 while the affected
facility is operating at normal full load, or as specified in an
applicable subpart. The RA test can be conducted during the UD test
period.
8.6.2 Reference Method (RM). Unless otherwise specified in an
applicable subpart of the regulations, use either Method 29 in
appendix A to 40 CFR part 60, or ASTM Method D 6784-02 (incorporated
by reference in Sec. 60.17) as the RM for Hg. Do not include the
filterable portion of the sample when making comparisons to the CEMS
results. Conduct all RM tests with paired or duplicate sampling
systems.
8.6.3 Sampling Strategy for RM Tests. Conduct the RM tests in
such a way that they will yield results representative of the
emissions from the source and can be compared to the CEMS data. It
is preferable to conduct the diluent (if applicable), moisture (if
needed), and Hg measurements simultaneously. However, diluent and
moisture measurements that are taken within an hour of the Hg
measurements can used to adjust the results to a consistent basis.
In order to correlate the CEMS and RM data properly, note the
beginning and end of each RM test period for each paired RM run
(including the exact time of day) on the CEMS chart recordings or
other permanent record of output.
8.6.4 Number and length of RM Tests. Conduct a minimum of nine
paired sets of all necessary RM test runs that meet the relative
standard deviation criteria of this PS. Use a minimum sample run
time of 2 hours for each pair.
Note: More than nine paired sets of RM tests can be performed.
If this option is chosen, test results can be rejected so long as
the total number of paired RM test results used to determine the
CEMS RA is greater than or equal to nine. However, all data must be
reported, including the rejected data.
8.6.5 Correlation of RM and CEMS Data. Correlate the CEMS and
the RM test data as to the time and duration by first determining
from the CEMS final output (the one used for reporting) the
integrated average pollutant concentration or emission rate for each
pollutant RM test period. Consider system response time, if
important, and confirm that the results are on a consistent
moisture, temperature, and diluent concentration basis with the
paired RM test. Then, compare each integrated CEMS value against the
corresponding average of the paired RM values.
8.6.6 Paired RM Outliers.
8.6.6.1 Outliers are identified through the determination of
precision and any systematic bias of the paired RM tests. Data that
do not meet this criteria should be flagged as a data quality
problem. The primary reason for performing dual RM sampling is to
generate information to quantify the precision of the RM data. The
relative standard deviation (RSD) of paired data is the parameter
used to quantify data precision. Determine RSD for two
simultaneously gathered data points as follows:
[GRAPHIC] [TIFF OMITTED] TP30JA04.026
where Ca and Cb are concentration values determined from trains A
and B respectively. For RSD calculation, the concentration units are
unimportant so long as they are consistent.
8.6.6.2 A minimum precision criteria for RM Hg data is that RSD
for any data pair must be [le]10 percent as long as the mean Hg
concentration is greater than 1.0 [mu]g/m3. If the mean
Hg concentration is less than or equal to 1.0 [mu]g/m3,
the RSD must be [le]20 percent. Pairs of RM data exceeding these RSD
criteria should be eliminated from the data set used to develop a Hg
CEMS correlation or to assess CEMS RA.
8.6.7 Calculate the mean difference between the RM and CEMS
values in the units of the emission standard, the standard
deviation, the confidence coefficient, and the RA according to the
procedures in Section 12.0.
8.7 Reporting. At a minimum (check with the appropriate EPA
Regional Office, State, or local Agency for additional requirements,
if any), summarize in tabular form the results of the RD tests and
the RA tests or alternative RA procedure, as appropriate. Include
all data sheets, calculations, charts (records of CEMS responses),
reference gas concentration certifications, and any other
information necessary to confirm that the performance of the CEMS
meets the performance criteria.
9.0 Quality Control [Reserved]
10.0 Calibration and Standardization [Reserved]
11.0 Analytical Procedure
Sample collection and analysis are concurrent for this
Performance Specification (see Section 8.0). Refer to the RM
employed for specific analytical procedures.
12.0 Calculations and Data Analysis
Summarize the results on a data sheet similar to that shown in
Figure 2-2 for Performance Specification 2.
12.1 Consistent Basis. All data from the RM and CEMS must be on
a consistent dry basis and, as applicable, on a consistent diluent
basis. Correct the RM and CEMS data for moisture and diluent as
follows:
12.1.1 Moisture Correction (as applicable). Correct each wet RM
run for moisture with the corresponding Method 4 data; correct each
wet CEMS run using the corresponding CEMS moisture monitor date
using Equation 12A-2.
[GRAPHIC] [TIFF OMITTED] TP30JA04.027
12.1.2 Correction to Units of Standard (as applicable). Correct
each dry RM run to the units of the emission standard with the
corresponding Method 3B data; correct each dry CEMS run using the
corresponding CEMS diluent monitor data as follows:
12.1.3 Correct to Diluent Basis. The following is an example of
concentration (ppm) correction to 7 percent oxygen.
[GRAPHIC] [TIFF OMITTED] TP30JA04.028
[[Page 4747]]
The following is an example of mass/gross calorific value (lbs/
million Btu) correction. lbs/MMBtu = Conc(dry) (F-factor)
((20.9/(20.9--percent O2))
12.2 Arithmetic Mean. Calculate the arithmetic mean of the
difference, d, of a data set as follows:
[GRAPHIC] [TIFF OMITTED] TP30JA04.029
Where:
n = Number of data points.
12.3 Standard Deviation. Calculate the standard deviation,
Sd, as follows:
[GRAPHIC] [TIFF OMITTED] TP30JA04.030
Where:
[GRAPHIC] [TIFF OMITTED] TP30JA04.031
12.4 Confidence Coefficient. Calculate the 2.5 percent error
confidence coefficient (one-tailed), CC, as follows:
[GRAPHIC] [TIFF OMITTED] TP30JA04.032
12.5 Relative Accuracy. Calculate the RA of a set of data as
follows:
Where:
[verbar]d[verbar] = Absolute value of the mean differences (from
Equation 12A-4).
[verbar]CC[verbar] = Absolute value of the confidence coefficient
(from Equation 12A-6).
RM = Average RM value. In cases where the average emissions for the
test are less than 50 percent of the applicable standard, substitute
the emission standard value in the denominator of Eq. 12A-7 in place
of R[bond]M[bond]. In all other cases, use R[bond]M[bond]
13.0 Method Performance
13.1 Measurement Error (ME). ME is assessed at mid-level and
high-level values as given below using standards for both
Hg0 and HgCl2. The mean difference between the
indicated CEMS concentration and the reference concentration value
for each standard shall be no greater than 5 percent of span. The
same difference for the zero reference gas
[GRAPHIC] [TIFF OMITTED] TP30JA04.033
shall be no greater than 5 percent of span.
13.2 Upscale Drift (UD). The CEMS design must allow the
determination of UD of the analyzer. The CEMS response can not drift
or deviate from the benchmark value of the reference standard by
more than 5 percent of span for the mid level value. Evaluate
upscale drift for Hg0 only.
13.3 Zero Drift (ZD). The CEMS design must allow the
determination of drift at the zero level. This drift shall not
exceed 5 percent of span.
13.4 Relative Accuracy (RA). The RA of the CEMS must be no
greater than 20 percent of the mean value of the RM test data in
terms of units of the emission standard, or 10 percent of the
applicable standard, whichever is greater.
14.0 Pollution Prevention. [Reserved]
15.0 Waste Management. [Reserved]
16.0 Alternative Procedures. [Reserved]
17.0 Bibliography.
17.1 40 CFR part 60, appendix B, ``Performance Specification 2--
Specifications and Test Procedures for SO2 and
NOX Continuous Emission Monitoring Systems in Stationary
Sources.''
17.2 40 CFR part 60, appendix A, ``Method 29--Determination of
Metals Emissions from Stationary Sources.''
17.3 ASTM Method D6784-02, ``Standard Test Method for Elemental,
Oxidized, Particle-Bound and Total Mercury in Flue Gas Generated
from Coal-Fired Stationary Sources (Ontario Hydro Method).''
18.0 Tables and Figures.
Table 12A-1.--t-Values.
----------------------------------------------------------------------------------------------------------------
n a t0.975 n a t0.975 n a t0.975
----------------------------------------------------------------------------------------------------------------
2........................................................ 12.706 7 2.447 12 2.201
3........................................................ 4.303 8 2.365 13 2.179
4........................................................ 3.182 9 2.306 14 2.160
5........................................................ 2.776 10 2.262 15 2.145
6........................................................ 2.571 11 2.228 16 2.131
----------------------------------------------------------------------------------------------------------------
a The values in this table are already corrected for n-1 degrees of freedom. Use n equal to the number of
individual values.
------------------------------------------------------------------------
Reference CEMS
Day Date and value value Measurement Drift
time (C) (M) error
------------------------------------------------------------------------
Zero
Level
-----------
-----------
-----------
-----------
Mid-
level
-----------
-----------
[[Page 4748]]
-----------
-----------
High-
level
-----------
-----------
-----------
---------
Figure 12A-1.--Zero and Upscale Drift Determination
PART 63--[AMENDED]
11. The authority citation for part 63 continues to read as
follows:
Authority: 42 U.S.C. 7401, et seq.
12. Section 63.14 is amended by adding paragraph (b)(35) to read as
follows:
Sec. 63.14 Incorporations by Reference.
* * * * *
(b) * * *
(35) ASTM D6784-02, Standard Test Method for Elemental, Oxidized,
Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired
Stationary Sources (Ontario Hydro Method), for appendix B to part 63,
Method 324.
* * * * *
APPENDIX B PART 63
13. Appendix B to part 63 is amended by adding in numerical
order new Method 324 to read as follows:
Method 324--Determination of Vapor Phase Flue Gas Mercury Emissions
From Stationary Sources Using Dry Sorbent Trap Sampling
1.0 Introduction.
This method describes sampling criteria and procedures for the
continuous sampling of mercury (Hg) emissions in combustion flue gas
streams using sorbent traps. Analysis of each trap can be by cold
vapor atomic fluorescence spectrometry (AF) which is described in
this method, or by cold vapor atomic absorption spectrometry (AA).
Only the AF analytical method is detailed in this method, with
reference being made to other published methods for the AA
analytical procedure. The Electric Power Research Institute has
investigated the AF analytical procedure in the field with the
support of ADA-ES and Frontier Geosciences, Inc. The AF procedure is
based on EPA Method 1631, Revision E: Mercury in Water by Oxidation,
Purge and Trap, and Cold Vapor Atomic Fluorescence Spectrometry.
Persons using this method should have a thorough working knowledge
of Methods 1, 2, 3, 4 and 5 of 40 CFR part 60, appendix A.
1.1 Scope and Application.
1.1.1 Analytes. The analyte measured by this method is total
vapor-phase Hg, which represents the sum of elemental (CAS Number
7439-97-6) and oxidized forms of Hg, mass concentration (micrograms/
dscm) in flue gas samples.
1.1.2 Applicability. This method is applicable to the
determination of vapor-phase Hg concentrations ranging from 0.03
[mu]g/dncm to 100 [mu]g/dncm in low-dust applications, including
controlled and uncontrolled emissions from stationary sources, only
when specified within the regulations. When employed to demonstrate
compliance with an emission regulation, paired sampling is to be
performed as part of the method quality control procedure. The
method is appropriate for flue gas Hg measurements from combustion
sources. Very low Hg concentrations will require greater sample
volumes. The method can be used over any period from 30 minutes to
several days in duration, provided appropriate sample volumes are
collected and all the quality control criteria in Section 9.0 are
met. When sampling for periods greater than 12 hours, the sample
rate is required to be maintained at a constant proportion to the
total stack flowrate, 25 percent to ensure
representativeness of the sample collected.
2.0 Summary of Method.
Known volumes of flue gas are extracted from a duct through a
single or paired sorbent trap with a nominal flow rate of 0.2 to 0.6
liters per minute through each trap. Each trap is then acid leached
and the resulting leachate is analyzed by cold vapor atomic
fluorescence spectrometry (CVAFS) detection. The AF analytical
procedure is described in detail in EPA Method 1631. Analysis by AA
can be performed by existing recognized procedures, such as that
contained in ASTM Method D6784-02 (incorporated by reference, see
Sec. 63.14) or EPA Method 29.
3.0 Definitions. [Reserved]
4.0 Clean Handling and Contamination.
During preparation of the sorbent traps, as well as transport,
field handling, sampling, recovery, and laboratory analysis, special
attention must be paid to cleanliness procedures. This is to avoid
Hg contamination of the samples, which generally contain very small
amounts of Hg. For specifics on how to avoid contamination, Section
4 of Method 1631 should be well understood.
5.0 Safety.
5.1 Site hazards must be prepared for in advance of applying
this method in the field. Suitable clothing to protect against site
hazards is required, and requires advance coordination with the site
to understand the conditions and applicable safety policies. At a
minimum, portions of the sampling system will be hot, requiring
appropriate gloves, long sleeves, and caution in handling this
equipment.
5.2 Laboratory safety policies are to minimize risk of chemical
exposure and to properly handle waste disposal. Personnel will don
appropriate laboratory attire according to a Chemical Hygiene Plan
established by the laboratory. This includes, but is not limited to,
laboratory coat, safety goggles, and nitrile gloves under clean
gloves.
5.3 The toxicity or carcinogenicity of reagents used in this
method has not been fully established. The procedures required in
this method may involve hazardous materials, operations, and
equipment. This method may not address all of the safety problems
associated with these procedures. It is the responsibility of the
user to establish appropriate safety and health practices and
determine the applicable regulatory limitations prior to performing
these procedures. Each chemical should be regarded as a potential
health hazard and exposure to these compounds should be minimized.
Chemists should refer to the MSDS for each chemical with which they
are working.
5.4 Any wastes generated by this procedure must be disposed of
according to a hazardous materials management plan that details and
tracks various waste streams and disposal procedures.
6.0 Equipment and Supplies.
6.1 Hg Sampling Train. A Schematic of a single trap sampling
train used for this method is shown in Figure 324-1. Where this
method is used to collect data to demonstrate compliance with a
regulation, it must be performed with paired sorbent trap equipment.
[[Page 4749]]
Figure 324-1. Hg Sampling Train illustrating Single Trap.
[GRAPHIC] [TIFF OMITTED] TP30JA04.034
6.1.1 Sorbent Trap. Use sorbent traps with separate main and
backup sections in series for collection of Hg. Selection of the
sorbent trap shall be based on: (1) Achievement of the performance
criteria of this method, and (2) data is available to demonstrate
the method can pass the criteria in EPA Method 301 when used in this
method and when the results are compared with those from EPA Method
29, EPA Method 101A, or ASTM Method 6784-02 for the measurement of
vapor-phase Hg in a similar flue gas matrix. Appropriate traps are
referred to as ``sorbent trap'' throughout this method. The method
requires the analysis of Hg in both main and backup portions of the
sorbent within each trap. The sorbent trap should be obtained from a
reliable source that has clean handling procedures in place for
ultra low-level Hg analysis. This will help assure the low Hg
environment required to manufacture sorbent traps with low blank
levels of Hg. Sorbent trap sampling requirements or needed
characteristics are shown in Table 324-1. Blank/cleanliness and
other requirements are described in Table 324-2. The sorbent trap is
supported on a probe and inserted directly into the flue gas stream,
as shown on Figure 324-1. The sampled sorbent trap is the entire Hg
sample.
6.1.2 Sampling Probe. The probe assembly shall have a leak-free
attachment to the sorbent trap. For duct temperatures from 200 to
375F, no heating is required. For duct temperatures
less than 200F, the sorbent tube must be heated to at
least 200F or higher to avoid liquid condensation in
the sorbent trap by using a heated probe. For duct temperatures
greater than 375F, a large sorbent trap must be used,
as shown in Table 324-1, and no heating is required. A thermocouple
is used to monitor stack temperature.
6.1.3 Umbilical Vacuum Line. A 250 F heated
umbilical line shall be used to convey to the moisture knockout the
sampled gas that has passed through the sorbent trap and probe
assembly.
6.1.4 Moisture Knockout. Impingers and desiccant can be combined
to dry the sample gas prior to entering the dry gas meter.
Alternative sample drying methods are acceptable as long as they do
not affect sample volume measurement.
6.1.5 Vacuum Pump. A leak tight vacuum pump capable of
delivering a controlled extraction flow rate between 0.1 to 0.8
liters per minute.
6.1.6 Dry Gas Meter. Use a dry gas meter that is calibrated
according to the procedures in 40 CFR part 60, appendix A, Method 5,
to measure the total sample volume collected. The dry gas meter must
be sufficiently accurate to measure the sample volume within 2
percent, calibrated at the selected flow rate and conditions
actually encountered during sampling, and equipped with a
temperature sensor capable of measuring typical meter temperatures
accurately to within 3 C (5.4 F).
6.2 Sample Analysis Equipment. Laboratory equipment as described
in Method 1631, Sections 6.3 to 6.7 is required for analysis by AF.
For analysis by AA, refer to Method 29 or ASTM Method 6784-02.
Table 324-1.--Sorbent Trap and Sampling Requirements
------------------------------------------------------------------------
Item to be determined Small sorbent trap Large sorbent trap
------------------------------------------------------------------------
Sampling Target: Hg Loading Minimum = 0.025 Minimum = 0.10 [mu]g/
Range, ug. [mu]g/trap.. trap.
Maximum = 150 [mu]g/ Maximum = 1800 [mu]g/
trap. trap.
Sampling Duration Required: Minimum = 30 minutes Minimum = 24 hours.
limits on sample times. Maximum = 24 hours.. Maximum = 10 days.
Sampling Temperature 200 to 375 F. thn-eq>F.
Sampling Rate Required...... 0.2 to 0.6 L/min; 0.2 to 0.6 L/min;
start at 0.4 L/min. start at 0.4 L/min.
Must be constant Must be constant
proportion within proportion of stack
25% if greater 25%.
constant rate
within 25%
if less than 12
hours.
------------------------------------------------------------------------
[[Page 4750]]
7.0 Analysis by AF, Reagents and Standards.
For analysis by AF, use Method 1631, Sections 7.1-7.3 and 7.5-
7.12 for laboratory reagents and standards. Refer to Method 29 or
ASTM Method 6784-02 for analysis by AA.
7.1 Reagent Water. Same as Method 1631, Section 7.1.
7.2 Air. Same as Method 1631, Section 7.2.
7.3 Hydrochloric Acid. Same as Method 1631, Section 7.3.
7.4 Stannous Chloride. Same as Method 1631, Section 7.5.
7.5 Bromine Monochloride (BrCl, 0.01N). Same as Method 1631,
Section 7.6.
7.6 Hg Standards. Same as Method 1631, Sections 7.7 to 7.11.
7.7 Nitric Acid. Reagent grade, low Hg.
7.8 Sulfuric Acid. Reagent grade, low Hg.
7.9 Nitrogen. Same as Method 1631, Section 7.12.
7.10 Argon. Same as Method 1631, Section 7.13.
8.0 Sample Collection and Transport.
8.1 Pre-Test.
8.1.1 Site information should be obtained in accordance with
Method 1 (40 CFR part 60, appendix A). Identify a location that has
been shown to be free of stratification for SO2 and
NOX through concentration measurement traverses for those
gases. An estimation of the expected Hg concentration is required to
establish minimum sample volumes. Based on estimated minimum sample
volume and normal sample rates for each size trap used, determine
sampling duration with the data provided in Table 324-1.
8.1.2 Sorbent traps must be obtained from a reliable source such
that high quality control and trace cleanliness are maintained.
Method detection limits will be adversely affected if adequate
cleanliness is not maintained. Sorbent traps should be handled only
with powder-free low Hg gloves (vinyl, latex, or nitrile are
acceptable) that have not touched any other surface. The sorbent
traps should not be removed from their clean storage containers
until after the preliminary leak check has been completed. Field
efforts at clean handling of the sorbent traps are key to the
success of this method.
8.1.3 Assemble the sample train according to Figure 324-1,
except omit the sorbent trap.
8.1.4 Preliminary Leak Check. Perform system leak check without
the single or dual sorbent traps in place. This entails plugging the
end of the probe to which each sorbent trap will be affixed, and
using the vacuum pump to draw a vacuum in each sample train. Adjust
the vacuum in the sample train to 15 inches Hg. A rotameter on the
dry gas meter will indicate the leakage rate. The leakage rate must
be less than 2 percent of the planned sampling rate.
8.1.5 Release the vacuum in the sample train, turn off the pump,
and affix the sorbent trap to the end of the probe, using clean
handling procedures. Leave the flue gas end of the sorbent trap
plugged.
8.1.6 Pre-test leak check. Perform a leak check with the Sorbent
trap in place. Use the sampling vacuum pump to draw a vacuum in the
sample train. Adjust the vacuum in the sample train to 15 inches Hg.
A rotameter on the dry gas meter will indicate the leakage rate.
Record the leakage rate. The leakage rate must be less than 2
percent of the planned sampling rate. Once the leak check passes
this criterion, carefully release the vacuum in the sample train
(the sorbent trap must not be exposed to abrupt changes in pressure
or to backflow), then re-cap the flue gas end of the sorbent trap
until the probe is ready for insertion. The sorbent trap packing
beds must be undisturbed by the leak test to prevent gas channeling
through the media during sampling.
8.1.7 Use temperature controllers to heat the portions of the
trains that require it. The sorbent trap must be maintained between
200 and 375 F during sampling.
8.1.8 Gas temperature and static pressure must be considered
prior to sampling in order to maintain proper safety precautions
during sampling.
8.2 Sample Collection.
8.2.1 Remove the plug from the end of a sorbent trap and store
it in a clean sorbent trap storage container. Remove the sample duct
port cap and insert the probe. Secure the probe and ensure that no
leakage occurs between the duct and environment.
8.2.2 Record initial data including the start time, starting dry
gas meter readings, and the name of the field tester(s). Set the
initial sample flow rate to 0.4 L/min (+/-25 percent).
8.2.3 For constant-flow sampling (samples less than 12 hours in
duration), every 10-15 minutes during the sampling period: record
the time, the sample flow rate, the gas meter readings, the duct
temperature, the flow meter temperatures, temperatures of heated
equipment such as the vacuum lines and the probes (if heated), and
the sampling vacuum reading. Adjust the sample rate as needed,
maintaining constant sampling within +/-25 percent of the initial
reading.
8.2.4 For constant proportion sampling (samples 12 hours or
greater in duration), every hour during the sampling period: record
the time, the sample flow rate, the gas meter readings, the duct
temperature, the flow meter temperatures, temperatures of heated
equipment such as the vacuum lines and the probes (if heated), and
the sampling vacuum readings. Also record the stack flow rate
reading, whether provided as a CEM flow monitor signal, a pitot
probe or other direct flow indication, or a plant input signal.
Adjust the sampling rate to maintain proportional sampling within +/
-25 percent relative to the total stack flowrate.
8.2.5 Obtain and record operating data for the facility during
the test period, including total stack flowrate and the oxygen
concentration at the flue gas test location. Barometric pressure
must be obtained for correcting sample volume to standard
conditions.
8.2.6 Post Test Leak Check. When sampling is completed, turn off
the sample pump, remove the probe from the port and carefully re-
plug the end of the sorbent trap. Perform leak check by turning on
the sampling vacuum pumps with the plug in place. The rotameter on
the dry gas meters will indicate the leakage rates. Record the
leakage rate and vacuum. The leakage rate must be less than 2
percent of the actual sampling rate. Following the leak check,
carefully release the vacuum in the sample train.
8.2.7 Sample Recovery. Recover each sampled sorbent trap by
removing it from the probe, plugging both ends with the clean caps
provided with the sorbent trap, and then wiping any dirt off the
outside of the sorbent trap. Place the sorbent trap into the clean
sample storage container in which it was provided, along with the
data sheet that includes the post-test leak check, final volume, and
test end time.
8.3 Quality Control Samples and Requirements.
8.3.1 Field blanks. Refer to Table 324-2.
8.3.2 Duplicate (paired or side by side) samples. Refer to
Section 8.6.6 of Performance Specification 12A of 40 CFR part 60,
appendix B for this criteria.
8.3.3 Breakthrough performance data (``B'' bed in each trap, or
second traps behind). Refer to Table 324-2.
8.3.4 Field spikes (sorbent traps spiked with Hg in the lab and
periodically sampled in the field to determine overall accuracy).
Refer to Table 324-2.
8.3.5 Laboratory matrix and matrix spike duplicates. Refer to
Table 324-2.
9.0 Quality Control.
Table 324-2 summarizes the major quantifiable QC components.
Table 324-2.--Quality Control for Samples
------------------------------------------------------------------------
QA/QC Acceptance Corrective
specification criteria Frequency action
------------------------------------------------------------------------
Leak-check. <2% of sampling Pre- and post- Pre-sampling:
rate. sampling. repair leak.
Post sampling:
Flag data and
repeat run if
for regulatory
compliance.
Sample Flow Rate 0.4 L/min Throughout run Adjust when data
for samples less initially and every 10-15 is recorded.
than 12 hours in 25% of
initial rate
throughout run.
Sample Flow Rate 0.4 L/min Throughout run Adjust when data
for samples initially and every hour. is recorded.
greater than 12 maintain
duration. 25% of ration of
flue gas flow
rate throughout
sampling.
[[Continued on page 4751]]
[Federal Register: January 30, 2004 (Volume 69, Number 20)]
[Proposed Rules]
[Page 4751-4752]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr30ja04-14]
[[pp. 4751-4752]] 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
[[Continued from page 4750]]
[[Page 4751]]
Sorbent trap <5 ng/trap and a 3 per analysis ................
laboratory blank standard set of 20
(same lot as deviation of sorbent traps.
samples). <1:0 ng/trap
(n=3).
Sorbet trap field <5 ng/trap and a 1 per every 10 ................
blank (same lot standard field samples
as samples) deviation of collected.
<1.0 ng/trap
(n=3) OR <5% of
average sample
collected.
B-Trap Bed <2% of A-Trap Bed Every sample. ................
Analysis. Value OR < 5 ng/
trap.
Paired Train Same as Section ................ ................
Results. 8.6.6 of PS-12A
of 40 CFR Par
60, Appendix B.
Field Spikes. 80% to 120% For long-term If the first 4
recovery. regulatory field spikes do
monitoring, 1 not meet the
per every 3 20%
first 12 criteria, take
samples. corrective
sampling and
laboratory
measures and
repeat at the 1
per every 3
sample rate
until the 20% criteria
is met.
Laboratory matrix 85% to 115% 1 per every 10
and matrix spike recovery. or 20 samples--
duplicates. to be
determined.
------------------------------------------------------------------------
10.0 Calibration and Standards.
Same as Sections 10.1, 10.2 and 10.4 of Method 1631.
10.1 Calibration and Standardization. Same as Sections 10.1 and
10.4 of Method 1631.
10.2 Bubbler System. Same as Section 10.2 of M1631.
10.3 Flow-Injection System. Not applicable.
11.0 Analytical Procedures.
11.1 Preparation Step. The sorbent traps are received and
processed in a low-Hg environment (class-100 laminar-flow hood and
gaseous Hg air concentrations below 20 ng/m3) following
clean-handling procedures. Any dirt or particulate present on the
exterior of the trap must be removed to avoid contamination of the
sample. The sorbent traps are then opened and the sorbent bed(s)
transferred to an appropriate sized trace-clean vessel. It is
recommended that the height of the trace-clean vessel be at least 3
times the diameter to facilitate a refluxing action.
11.2 Leaching Step. The sorbent trap is then subjected to a hot-
acid leach using a 70:30 ratio mixture of concentrated
HNO3/H2SO4. The acid volume must be
40 percent of the expected end volume of the digest after dilution.
The HNO3/H2SO4 acid to carbon ratio
should be approximately 35:1. The leachate is then heated to a
temperature of 50 to 60C for 1.5 to 2.0 hours in the
finger-tight capped vessels. This process may generate significant
quantities of noxious and corrosive gasses and must only be
performed in a well-ventilated fume hood. Care must be taken to
prevent excessive heated leaching of the samples as this will begin
to break down the charcoal material.
11.3 Dilution Step. After the leached samples have been removed
from the hot plate and allowed to cool to room temperature, they are
brought to volume with a 5 percent (v/v) solution of 0.01 N BrCl. As
the leaching digest contains a substantial amount of dissolved
gasses, add the BrCl slowly, especially if the samples are still
warm. As before, this procedure must be performed in a properly
functioning fume hood. The sample is now ready for analysis.
11.4 Hg Reduction and Purging. (Reference Section 11.2 of M1631
except that NH2OH is not used.)
11.4.1 Bubbler System. Pipette an aliquot of the digested sample
into the bubbler containing pre-blanked reagent water and a soda
lime trap connected to the exhaust port. Add stannous chloride
(SnCl2) to reduce the aliquot and then seal the bubbler.
Connect gold sample traps to the end of the soda lime trap as shown
in Figures 1 and 2 of Method 1631. Finally, connect the
N2 lines and purge for 20 minutes. The sample trap can
then be added into the analytical train. M1631, Section 11.2.1.
11.4.2 Flow Injection System. If required.
11.5 Desorption of Hg from the gold trap, and peak evaluation.
Use Section 11.3 and 11.4 in M1631.
11.6 Instrument Calibration. Analyze the standards by AA or AF
following the guidelines specified by the instrument manufacturer.
Construct a calibration curve by plotting the absorbances of the
standards versus [mu]g/l Hg. The R2 for the calibration
curve should be 0.999 or better. If the curve does not have an
R2 value equal to or better than 0.999 then the curve
should be rerun. If the curve still does not meet this criteria then
new standards should be prepared and the instrument recalibrated.
All calibration points contained in the curve must be within 10
percent of the calibration value when the calibration curve is
applied to the calibration standards.
11.7 Sample Analysis. Analyze the samples in duplicate following
the same procedures used for instrument calibration. From the
calibration curve, determine sample Hg concentrations. To determine
total Hg mass in each sample fraction, refer to calculations in
Section 15. Record all sample dilutions
11.8 Continued Calibration Performance. To verify continued
calibration performance, a continuing calibration check standard
should be run every 10 samples. The measured Hg concentration of the
continuing calibration check standard must be within 10 percent of
the expected value.
11.9 Measurement Precision. The QA/QC for the analytical portion
of this method is that every sample, after it has been prepared, is
to be analyzed in duplicate with every tenth sample analyzed in
triplicate. These results must be within 10 percent of each other.
If this is not the case, then the instrument must be recalibrated
and the samples reanalyzed.
11.10 Measurement Accuracy. Following calibration, an
independently prepared standard (not from same calibration stock
solution) should be analyzed. In addition, after every ten samples,
a known spike sample (standard addition) must be analyzed. The
measured Hg content of the spiked samples must be within 10 percent
of the expected value.
11.11 Independent QA/QC Checks. It is suggested that the QA/QC
procedures developed for a test program include submitting, on
occasion, spiked Hg samples to the analytical laboratory by either
the prime contractor, if different from the laboratory, or an
independent organization. The measured Hg content of reference
samples must be within 15 percent of the expected value. If this
limit is exceeded, corrective action (e.g., re-calibration) must be
taken and the samples re-analyzed.
11.12 Quality Assurance/Quality Control. For this method, it is
important that both the sampling team and analytical people be very
well trained in the procedures. This is a complicated method that
requires a high-level of sampling and analytical experience. For the
sampling portion of the QA/QC procedure, both solution and field
blanks are required. It should be noted that if high-quality
reagents are used and care is taken in their preparation and in the
train assembly, there should be little, if any, Hg measured in
either the solution or field blanks.
11.13 Solution Blanks. Solution blanks must be taken and
analyzed every time a new batch of solution is prepared. If Hg is
detected in these solution blanks, the concentration is subtracted
from the measured sample results. The maximum amount that can be
subtracted is 10 percent of the measured result or 10 times the
detection limit of the instrument whichever is lower. If the
solution blanks are greater
[[Page 4752]]
than 10 percent the data must be flagged as suspect.
11.14 Field Blanks. A field blank is performed by assembling a
sample train, transporting it to the sampling location during the
sampling period, and recovering it as a regular sample. These data
are used to ensure that there is no contamination as a result of the
sampling activities. A minimum of one field blank at each sampling
location must be completed for each test site. Any Hg detected in
the field blanks cannot be subtracted from the results. Whether or
not the Hg detected in the field blanks is significant is determined
based on the QA/QC procedures established prior to the testing. At a
minimum, if field blanks exceed 30 percent of the measured value at
the corresponding location, the data must be flagged as suspect.
12.0 Calculations and Data Analysis
Use Section 12 in M1631.
13.0 Constant Proportion Sampling
Calculate the Sample Rate/Stack Flow = ``x.'' ``X'' must be
maintained within 0.75 ``x'' to 1.25 ``x'' for sampling times in
excess of 12 hours. For mass emission rate calculations, use the
flow CEM total measured flow corresponding to the sorbent trap
sample time period.
14.0 Sampling and Data Summary Calculations
Refer to 40 CFR part 60, appendix A, Methods 2, 4, and 5 for
example calculations.
15.0 Pollution Prevention
Refer to Section 13 in Method 1631.
16.0 Waste Management
Refer to Section 14 in Method 1631.
17.0 Bibliography
17.1 EPA Method 1631, Revision E ``Mercury in Water by
Oxidation, Purge and Trap, and Cold Vapor Atomic Fluorescence
Spectrometry,'' August 2002.
17.2 ``Comparison of Sampling Methods to Determine Total and
Speciated Mercury in Flue Gas,'' CRADA F00-038 Final Report, DOE/
NETL-2001/1147, January 4, 2001.
17.3 40 CFR part 60, appendix A, ``Method 29--Determination of
Metals Emissions From Stationary Sources.''
17.4 40 CFR part 60, appendix B, ``Performance Specification
12A, Specification and Test Procedures for Total Vapor Phase Mercury
Continuous Emission Monitoring Systems in Stationary Sources.''
17.5 ASTM Method D6784-02, ``Standard Test Method for Elemental,
Oxidized, Particle-bound and Total Mercury in Flue Gas Generated
from Coal-Fired Stationary Sources (Ontario Hydro Method).''
[FR Doc. 04-1539 Filed 1-29-04; 8:45 am]
BILLING CODE 6560-50-P