[Federal Register Volume 69, Number 51 (Tuesday, March 16, 2004)]
[Proposed Rules]
[Pages 12398-12472]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 04-4457]
[[Page 12397]]
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Part II
Environmental Protection Agency
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40 CFR Parts 60, 72, and 75
Supplemental Notice for the Proposed National Emission Standards for
Hazardous Air Pollutants; and, in the Alternative, Proposed Standards
of Performance for New and Existing Stationary Sources: Electric
Utility Steam Generating Units; Proposed Rule
Federal Register / Vol. 69, No. 51 / Tuesday, March 16, 2004 /
Proposed Rules
[[Page 12398]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 60, 72, and 75
[OAR-2002-0056; FRL-7628-8]
RIN 2060-AJ65
Supplemental Notice for the 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: Supplemental notice of proposed rulemaking (SNPR).
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SUMMARY: Today's action is a SNPR to a notice of proposed rulemaking
(NPR) published on January 30, 2004. The NPR proposed 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 EPA made by notice dated December 20, 2000 pursuant
to CAA section 112(n)(1)(A); and if the December 2000 finding is
revised as proposed, to set standards of performance, under CAA section
111, 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. Thus, regardless of whether it would base its action on section
111 or 112, EPA intends to require reductions in the emissions of Hg
and Ni from coal- and oil-fired utility units, respectively.
Today's SNPR includes proposed rule language for the action
proposed in the NPR published on January 30, 2004, proposed state plan
approvability criteria, and a proposed model cap-and-trade rule. EPA is
also proposing to revise regulations to establish methodologies to
measure mercury (Hg) emissions from new and existing coal-fired
electric utility steam generating units. Today's SNPR and the
associated NPR are part of a broader effort to issue a coordinated set
of emissions limitations for the power sector.
DATES: Comments. Submit comments on or before April 30, 2004.
Public Hearing. The EPA will hold a public hearing. 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/interstateairquality.
ADDRESSES: Comments. Comments may be submitted by mail (in duplicate,
if possible) to EPA Docket Center (Air Docket), U.S. EPA West (6102T),
Room B-108, 1200 Pennsylvania Ave., NW., Washington, DC 20460,
Attention Docket ID No. OAR-2002-0056. By hand delivery/courier,
comments may be submitted (in duplicate, if possible) to EPA Docket
Center, Room B-108, U.S. EPA West, 1301 Constitution Ave., NW.,
Washington, DC 20460, Attention Docket ID No. OAR-2002-0056. Also,
comments may be submitted electronically according to the detailed
instructions as provided in the SUPPLEMENTARY INFORMATION section.
Docket. The official public docket is available for public viewing
at the EPA Docket Center, EPA West, Room B-108, 1301 Constitution Ave.,
NW., Washington, DC 20460.
FOR FURTHER INFORMATION CONTACT: For general information on today's
SNPR and specific information on today's action under CAA section 112,
contact William Maxwell, Combustion Group (mail stop C439-01), Emission
Standards Division, Office of Air Quality Planning and Standards, U.S.
EPA, Research Triangle Park, NC 27711, telephone number (919) 541-5430,
fax number (919) 541-5450, electronic mail (e-mail) address,
[email protected]. For information on section 111 Hg Model Trading
Rule contact Mary Jo Krolewski, U.S. EPA, 1200 Pennsylvania Ave (MC
6204J), Washington, DC 20460, telephone number (202) 343-9847, fax
number (202) 343-2358, electronic mail (e-mail) address,
[email protected]. For information on the part 75 Hg monitoring
requirements contact Ruben Deza, U.S. EPA, 1200 Pennsylvania Ave (MC
6204J), Washington, DC 20460, telephone number (202) 343-3956, fax
number (202) 343-2358, electronic mail (e-mail) address,
[email protected].
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\ 22112 Fossil fuel-fired
electric utility steam
generating units owned
by the Federal
government.
State/local/tribal government..... \2\ 22112 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 are aware of 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)
[[Page 12399]]
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
comment due to technical difficulties and cannot contact you for
clarification, EPA may not be able to consider your comment.
Your use of EPA's electronic public docket to submit comments to
EPA electronically is EPA's preferred method for receiving comments. Go
directly to EPA Dockets at http://www.epa.gov/edocket and follow the
online instructions for submitting comments. To access EPA's electronic
public docket from the EPA Internet home page, select ``Information
Sources,'' ``Dockets,'' and ``EPA Dockets.'' Once in the system, select
``search,'' and then key in Docket ID No. OAR-2002-0056. The system is
an anonymous access system, which means EPA will not know your
identity, e-mail address, or other contact information unless you
provide it in the body of your comment.
Comments may be sent by e-mail to [email protected], Attention
Docket ID No. OAR-2002-0056. In contrast to EPA's electronic public
docket, EPA's e-mail system is not an anonymous access system. If you
send an e-mail comment directly to the Docket without going through
EPA's electronic public docket, EPA's e-mail system automatically
captures your e-mail address. E-mail addresses that are automatically
captured by EPA's e-mail system are included as part of the comment
that is placed in the official public docket and made available in
EPA's electronic public docket.
You may submit comments on a disk or CD-ROM that you mail to the
mailing address identified below. These electronic submissions will be
accepted in WordPerfect or ASCII file format. Avoid the use of special
characters and any form of encryption.
By Mail. Send your comments (in duplicate if possible) to EPA
Docket Center (Air Docket), U.S. EPA West (6102T), Room B-108, 1200
Pennsylvania Ave., NW., Washington, DC, 20460, Attention Docket ID No.
OAR-2002-0056. The EPA requests a separate copy also be sent to the
contact person listed above (see FOR FURTHER INFORMATION CONTACT).
By Hand Delivery or Courier. Deliver your comments (in duplicate,
if possible) to EPA Docket Center, Room B-102, U.S. EPA West, 1301
Constitution Ave., NW., Washington, DC, 20460, Attention Docket ID No.
OAR-2002-0056. Such deliveries are only accepted during the Docket's
normal hours of operation as identified above.
By Facsimile. Fax your comments to (202) 566-1741, Attention Docket
ID No. OAR-2002-0056.
CBI. Do not submit information that you consider to be CBI
electronically through EPA's electronic public docket or by e-mail.
Send or deliver information identified as CBI only to the following
address: Mr. William Maxwell, c/o OAQPS Document Control Officer (Room
C404-2), U.S. EPA, Research Triangle Park, 27711, Attention Docket ID
No. OAR-2002-0056. You may claim information that you submit to EPA as
CBI by marking any part or all of that information as CBI (if you
submit CBI on disk or CD-ROM, mark the outside of the disk or CD-ROM as
CBI and then identify electronically within the disk or CD-ROM the
specific
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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. If no requests
to present oral testimony are received by this date, EPA will cancel
the hearing and announce the cancellation on the Web site for this
rulemaking, http://www.epa.gov/interstateairquality.
The public hearing will provide interested parties the opportunity
to present data, views, or arguments concerning the proposed rule. If a
public hearing is requested and held, 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
A. Summary of January 30, 2004 NPR
B. Overview of today's action
II. Standards of Performance Requirements
A. Introduction
B. Performance Standard Approvability Criteria
C. Best Demonstrated Technology--Activated Carbon Injection
1. Mercury Control Technologies
a. Sorbent Injection Technologies
b. Enhanced Conventional Technologies
c. Multi-Pollutant Capture Technologies
d. Novel Approaches to Mercury Control
2. Longer-Term Field Tests
3. Initial Mercury Demonstration Projects
4. The Timing of Technology Development and Commercialization
D. Compliance Date for Nickel Controls
III. Emission Guidelines and Compliance Times for Coal-Fired
Electric Utility Steam Generating Units
A. Program Summary
B. Hg Budget Trading Program
1. General Provisions
a. Overview and Purpose
b. Definitions, Measurements, Abbreviations and Acronyms
c. Applicability
i. Monitoring
ii. Responsible Party
d. Retired Unit Exemption
e. Standard Requirements
f. Computation of Time
2. Hg Authorized Account Representative (AAR)
3. Permits
a. General Requirements
b. Hg Budget Permit Application Deadlines
c. Hg Budget Trading Program Permit Application
d. Hg Budget Permit Issuance
e. Hg Budget Permit Revisions
4. Compliance Certification
5. Hg Allowance Allocations
a. State Trading Program Budget
b. Timing Requirements
c. Options for Hg Allowance Allocation Methodology
Recommendation
6. Safety Valve Provision
7. Hg Allowance Tracking System
a. Compliance Accounts
b. Compliance
c. General Accounts
8. Banking
9. Allowance Transfers
10. Emissions Monitoring and Reporting
11. Program Audits
12. Administration of Program
C. Approvability of Trading Rule within a State Plan
1. Necessary Common Components of the trading Rule
2. Revisions to Regulations
D. Co-Proposal of Cap- and Trade Program under CAA Section 112
IV. Statutory and Executive Order Reviews
Appendix A to the Preamble--Proposed Changes to Parts 72 and 75
Appendix B to the Preamble--Unit Allocations
I. Background
A. Summary of January 30, 2004 NPR
In a notice of proposed rulemaking (NPR) published on January 30,
2004 (69 FR 4651), EPA proposed: (1) Set national emission standards
for hazardous air pollutants (NESHAP) pursuant to section 112 of the
Clean Air Act (CAA); (2) alternatively, to revise the regulatory
finding that it made on December 20, 2000 (65 FR 79825) pursuant to CAA
section 112(n)(1)(A) (December 2000 Finding); and (3) if the December
2000 finding is revised as proposed, to set standards of performance
pursuant to CAA section 111 for both mercury (Hg) for new and existing
coal-fired electric utility steam generating units (Utility Units), as
defined in CAA section 112(a)(8); and nickel (Ni) for new and existing
oil-fired Utility Units. Thus, regardless of whether it would base its
actions on section 111 or 112, EPA intends to require reductions in the
emissions of Hg and Ni from coal- and oil-fired utility units,
respectively. The January 30, 2004 NPR, and today's SNPR, are part of a
broader effort to issue a coordinated set of emissions limitations for
the power sector.
The December 2000 Finding consisted of a finding, 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. The section
112 ``MACT'' rule proposed in the January 30, 2004 NPR 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). In the January 30, 2004
NPR, EPA also co-proposed and solicited comment on implementing a cap-
and-trade program under section 112, similar to that proposed under
section 111 of the CAA.
The proposed NPR CAA section 112 MACT rule would limit emissions of
Hg from coal-fired EGUs and Ni from oil-fired EGUs. Exposure to Hg or
Ni above identified thresholds has been demonstrated to cause a variety
of adverse health effects. The NPR also proposed an alternative to
regulate Hg from coal-fired EGUs and Ni from oil-fired EGUs under
Section 111.
In the January 30, 2004 NPR, EPA also proposed, in the alternative,
standards of performance under CAA section 111 to 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 would become
effective 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. EPA believes 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
[[Page 12401]]
Quality Rule (IAQR) that was also proposed through a notice January 30,
2004 (69 FR 4565). 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'
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.
B. Overview of Today's Action
Today's action is a SNPR augmenting EPA's January 30, 2004 NPR.
This SNPR includes proposed rule language for the action proposed in
the NPR and proposed state plan approvability criteria. This SNPR also
includes a model cap-and-trade rule, including the proposed CFR rule
language for the basic elements of the proposed Hg Budget Trading
Program. The rule language is located at the end of the preamble.
In today's SNPR, EPA is proposing that each state impose control
requirements that demonstrate it will meet its statewide Hg emissions
budget, proposed in the NPR. States may join the trading program by
adopting or referencing the model trade rule in State regulations or
adopting regulations that mirror the necessary components of the model
trading rule. Today's SNPR identifies the necessary common components
of state rule rules and identifies EPA and state responsibilities for
administering a Hg trading program. Today's notice also discusses the
program elements of the model trading program, including applicability,
allowance allocations, banking, compliance, and enforcement.
EPA is also proposing to revise Parts 72 and 75 to establish
methodologies to measure mercury (Hg) emissions from new and existing
coal-fired electric utility steam generating units. In today's proposed
rule, EPA would add subpart I to Part 75. Subpart I would provide
mercury monitoring requirements that could be adopted by State agencies
(or, if necessary, by EPA) as part of any regulatory requirements
included in the final rules. Proposed Subpart I sets forth general
procedures for measuring total vapor phase mercury mass emissions from
fossil fuel-fired electric generating units, using continuous emission
monitoring systems or sorbent trap monitoring systems. In addition to
adding Subpart I to Part 75, today's proposed rule would revise the
regulatory language at several places in Parts 72 and 75 to include
specific mercury monitoring definitions and provisions.
II. Standard of Performance Requirements
A. Introduction
The January 30, 2004 NPR explained that under the section 111 co-
proposal each State would be required to submit a state plan
demonstrating ``that each State will meet the assigned statewide
mercury emission budget.'' Each state plan should include fully-adopted
State rules for the mercury reduction strategy with compliance dates
providing for controls by 2010 and 2018.
The purpose of this section is to identify criteria for determining
approvability of a State submittal in response to the performance
standard requirements. In addition, this section describes the actions
the Agency intends to take if a State fails to submit a satisfactory
plan.
B. Performance Standard Approvability Criteria
As discussed in the NPR, Section 111(a) and (d)(1) authorizes EPA
to promulgate a ``standard of performance'' that States must apply to
existing sources through a State plan. As also discussed in the NPR,
EPA is interpreting the term ``standard of performance'', as applied to
existing sources, to include a cap-and-trade program.
The State budgets are not an independently enforceable requirement.
Rather, each State must impose control requirements that the State
demonstrates will limit state-wide emissions from affected new and
existing sources to the amount of the budget. EPA believes that the
best way to assure this emission limitation is for the State to assign
to each affected source--new and existing--an amount of allowances that
sum to the state budget. Therefore, EPA proposes that all regulatory
requirements be in the form of a maximum level of emissions--that is, a
cap--for the sources. Also, consistent with the IAQR, EPA is proposing
that States may meet their Statewide emission budget by allowing their
sources to participate in a national cap-and-trade program. That is, a
State may authorize its affected sources to buy and sell allowances out
of state, so that any difference between the State's budget and the
total amount of statewide emissions will be offset in another State (or
States).
EPA notes that the January 30, 2004 NPR stated that States not
participating in the trading program would be required to make the
individual source allocations specified in the NPR (as noted above) as
the basis for the Statewide budget. In today's supplemental notice, EPA
is proposing that each State must submit a demonstration that it will
meet its assigned Statewide emission budget, but that regardless of
whether the State participates in a trading program, the State may
allocate its allowances by its own methodology rather than following
the method used by EPA to derive the state emissions budgets. This
alternative approach is consistent with the approach in the IAQR (see
69 FR 4565).
Moreover, States remain authorized to require emissions reductions
beyond those required by the State budget, and nothing in today's SNPR
or the associated NPR would preclude the States from requiring such
stricter controls.
In addition, EPA proposes today that sources would be required to
comply with the 40 CFR part 75 requirements proposed today. EPA
believes that compliance with these requirements are necessary to
demonstrate compliance with a mass emissions limit.
If a State fails to submit a State plan as proposed to be required
in the January 30, 2004 NPR and today's SNPR, EPA would prescribe a
Federal plan for that State, under CAA section 111(d)(2)(A). EPA
proposes today's model rule as that Federal plan. By the same token, as
discussed below, EPA proposes today's model rule (with some changes) as
the regulatory requirements under section 112(n)(1)(A), as co-proposed
in the NPR as the basis for Hg regulation.
C. Best Demonstrated Technology--Activated Carbon Injection
Mercury-specific air pollution control device development has made
major strides since the EPA announced its Information Collection
Request in 1998. Currently, there are a broad range of technologies
under consideration, consistent with the view that the EPA believes a
portfolio approach is required to adequately and effectively implement
significant reductions in mercury emissions from coal-fired power
plants. In selecting a Hg emissions control
[[Page 12402]]
technology approach, there are temporal relationships between research
and development projects, technology demonstration projects, and
commercial deployment of new technologies, which must be taken into
consideration when designing and proposing long-term regulatory
development programs similar to the section 111 Trading Program of this
proposal.
1. Mercury Control Technologies
Ongoing Hg Research and Development (R&D) programs recognize that
conventional air pollution control technologies (e.g., scrubbers, SCRs
and fabric filters) remove about one-third of the potential Hg
emissions from today's coal-fired power plants. EPA's Office of
Research and Development (ORD) has published an excellent report that
describes these technologies and their effectiveness in reducing Hg
emissions.\1\ Additionally, they have recently completed a memo which
updates the status of Hg control technologies relative to coal-fired
power plants.\2\ These existing criteria pollutant control technologies
are commercially deployed today, but generally show inconsistent levels
of mercury control from plant to plant. These R&D programs focus on
ways to make these existing technologies more effective and more
consistent at controlling Hg emissions, and on altogether new
approaches for Hg emissions control. The Department of Energy (DOE) is
committed to an aggressive R&D program in support of EPA's commitment
to significantly reduce Hg emissions from coal-fired power plants.\3\
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\1\ See Control of Mercury Emissions from Coal-fired Electric
Utility Boilers: Interim Report, EPA-600/R-01-109, April 2002.
\2\ See ``Control of Mercury Emissions from Coal-fired Electric
Utility Boilers'', U.S. EPA, Office of Research and Development
memorandum, February 2004.
\3\ See Mercury Control Technologies, U.S. Department of Energy
memorandum, January 8, 2004.
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There are two overarching goals for the DOE R&D program: (1) to
develop control technologies capable of 50-70% Hg capture for
commercial demonstration at bituminous coal-fired power plants by 2005,
and at lower rank coal-fired power plants by 2007 and (2) to develop
lower cost control technologies capable of 90% Hg capture for
commercial demonstration by 2010. The DOE R&D program takes
technologies from a conceptual level through bench scale and pilot
scale proof of concept. For the more promising technologies, defined in
terms of performance and cost, full-scale field tests are conducted to
generate the information necessary for a multi-year demonstration
project. In addition to funding for the Hg R&D program, DOE is also
provided funds by Congress to conduct such full-scale technology
demonstrations under the Clean Coal Power Initiative.
Several categories of technologies are now under development and
evaluation at DOE and ORD, which EPA has considered in proposing
regulations for Hg emissions from coal-fired power plants. These
include sorbent injection technologies, technologies that enhance the
Hg capture of traditional pollutant controls, such as SO2
``scrubbers'' and electrostatic precipitators (ESPs), multi-pollutant
control technologies, and novel concepts.
a. Sorbent Injection Technologies. DOE and ORD have supported
sorbent injection projects at the bench, pilot, and commercial-scale.
This type of technology has the greatest promise for taking Hg control
beyond the performance of conventional (non-Hg) technologies in the
near-term. During short-term tests, these technologies have achieved
emissions reductions as high as 90% of inlet Hg levels on bituminous
coals. Performance on subbituminous coals has been as high as 65%
reduction. In addition, systems with supplemental fabric filters have
been more effective than those with ESPs. Although full scale sorbent
injection tests have focused on activated carbon injection, DOE is also
sponsoring pilot scale research on lower cost sorbents. DOE is now
engaged in longer-term studies of sorbent injection technologies in
order to gain the information needed to conduct multi-year commercial
demonstrations of this technology. Given the differences in the
effectiveness of this technology on coals of different rank and
chlorine content, it is likely that several demonstration projects will
be necessary to establish predictable cost and performance for this
type of Hg control.
b. Enhanced Conventional Technologies. Air pollution systems
designed to capture emissions of sulfur dioxide (SO2) and
particulate matter (PM) generally capture some Hg emissions as well.
DOE is investigating methods to enhance the performance of such systems
on Hg emissions capture. In general, these systems seek to increase the
oxidized fraction of Hg present in the power plant's flue gas, and
decrease the fraction of elemental Hg, which is more difficult to
capture. DOE has had mixed results from injecting chemicals to enhance
the Hg removal by wet scrubbers designed for SO2 capture.
URS Corporation is working with DOE to develop catalytic approaches to
oxidizing elemental Hg in flue gases. This program began in 2001 and
will continue through 2004.
c. Multi-Pollutant Capture Technologies. Multi-pollutant approaches
have potential synergies which could increase pollution reduction and
lower control costs. Work with the Electro-catalytic oxidation process
under development by Powerspan Corporation was initiated in 2001 and
will continue through 2004. Early pilot-scale results have been
encouraging, but the inlet Hg for these tests was much lower in
elemental Hg than levels expected at many commercial sites. Additional
elemental Hg is being added to the test system to simulate removal at
other sites.
Calcium-based sorbents and oxidizing agents are being evaluated
under a cooperative agreement between DOE and the Southern Research
Institute. These systems could remove both SO2 and Hg, and
could be helpful particularly with lower rank coals.
d. Novel Approaches to Mercury Control. It has long been observed
that poorly tuned coal burners generate higher levels of unburned
carbon in coal ash than properly tuned burners. This unburned carbon,
although undesirable from an efficiency perspective, can function like
activated carbon injection and adsorb Hg emissions. DOE has patented a
process to take advantage of this phenomenon by extracting partially
combusted coal from the furnace, and reinjecting it in the flue gas
after the air preheater. Pilot-scale tests have been very promising.
DOE is also investigating the ability of a specific wavelength of
ultraviolet light to oxidize elemental Hg to a form more easily
captured by conventional air pollution control equipment.
2. Longer-Term Field Tests
In contrast to most of DOE's short-term Hg R&D projects, in
September 2003, DOE initiated a series of eight longer-term, large-
scale field tests that will investigate the potential for improvements
and more wide-spread applicability of Hg control using one or more of
the approaches outlined above. The actual testing varies by project,
but generally will begin in early 2004 and last for several months.
Technologies to be evaluated include both sorbent-based approaches,
like activated carbon injection, as well as oxidation-based approaches
intended to improve Hg collection by more traditional air pollution
control technologies.
[[Page 12403]]
3. Initial Mercury Demonstration Projects
As discussed above, the DOE and ORD R&D programs are complemented
by a demonstration program within the Clean Coal Power Initiative. In
January 2003, DOE announced the first awards under this program,\4\
including the following two projects that would demonstrate Hg
emissions reduction technologies:
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\4\ See http://www.fe.doe.gov/news/techlines/03/tl_ccpi_2003sel.html.
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Wisconsin Electric Power Company's Presque Isle plant will evaluate
the TOXECON process combined with chemical additives as an integrated
Hg, particulate matter, SO2, and NOX emissions
control system. In this project, sorbents, including powdered activated
carbon for Hg control and chemicals for NOX and
SO2 control, will be injected into flue gas for subsequent
reaction with pollutants and collection in a pulse-jet baghouse that is
installed downstream of the existing particulate control device. The
TOXECON configuration allows for separate treatment or disposal of the
ash collected in the primary particulate control device. The duration
of the project is estimated to be 5 years, and its overall cost is $75
million.
The City of Colorado Springs is teaming with Foster Wheeler to
demonstrate an advanced circulating fluidized bed combustor, with
integrated pollution controls expected to reduce Hg emissions by over
90 percent. This 6-year project carries a total cost of just over $300
million.
These projects evidence the commitment of project participants,
including DOE and ORD, to invest the resources needed to bring
promising Hg control concepts to commercial readiness. We believe the
nature of the Hg control challenge is so complex that a number of
additional demonstration projects will be needed, but we are confident
that resources will be made available to pursue those projects and
solutions will be developed that have broad application.
4. The Timing of Technology Development and Commercialization
The normal flow of development of new technologies is R&D at the
bench scale and pilot scale (typically 2 to 4 years), followed by large
scale testing (typically one year under a range of operating conditions
and technology configurations at a facility), followed by one or more
cycles of full-scale demonstrations (typically 6 years each).
In implementing the Clean Coal Technology Program, DOE has gained
extensive experience with the process of demonstrating emerging air
pollution control technologies. Based on SO2 and
NOX retrofit technology demonstrations, the typical project
required a little over 6 years from selection of the project to reports
on its technical performance. This time period excluded the
administrative time needed to solicit and evaluate proposals. In
addition, the actual project duration was truncated for one-half of
these projects to exclude unusually lengthy reporting periods following
completion of the technology testing period.
Although pursuit is continuing on some Hg emissions control
technologies at the bench and pilot scale, much work has already been
completed at these smaller scales. However, some technologies, like
sorbent injection, have entered the large scale field testing stage,
and we have initiated a full-scale demonstration project for sorbent
injection technology. It appears that these technologies, with at least
50-70% Hg emissions reduction, will be ready for broader full-scale
demonstration on bituminous coal in 2005, and on subbituminous coal and
lignite in 2007. If these demonstrations are successful, commercial
deployment could occur on a large scale after 2010, or perhaps later.
Assuming two years to permit and construct such commercial units, large
scale operation of the technology is feasible by 2013 and 2015. It is
important to note that reliable and predictable performance will be
achieved only if such demonstration projects can be completed on a
range of coal types with a range of characteristics (such as Hg,
chlorine, and sulfur content), and at plants with a range of hardware
(ESPs of varying relative sizes; spray dryers on coals with low
chlorine content). Additional technologies, perhaps much lower in
costs, should follow in 2-4 additional years.
Greater Hg emissions reduction performance is an integral part of
DOE's and ORD's Hg emissions control technology development programs. A
second wave of technologies operating at 90% reduction should be ready
for full-scale demonstration by 2010, leading to effective reductions
after 2018. An important caveat to these time projections is that they
could be extended if the same units being retrofit for Hg emissions
must contemporaneously focus on installing separate pollution control
systems for other pollutants. The significance of this potential
problem will vary with the type of control technologies being
installed.
Substantial progress in Hg control technology development has been
achieved through a partnership between government (both ORD and DOE)
and industry. A broad portfolio of technologies is beginning to emerge,
and EPA is confident these technologies will most likely be able to
provide 50 to 70% reduction of Hg emissions in the period after 2015,
with up to 90% reduction of Hg emissions on many applications after
2018. Thus, EPA is proposing a Phase II cap of 15 tons in this
supplemental notice, which will take full advantage of the emerging,
demonstrated technologies that are outlined above. More details and
actual demonstration data are available in the docket related to this
rulemaking effort.
D. Compliance Date for Nickel Controls
In the January 30, 2004 NPR, EPA proposed that the compliance date
for Ni controls under section 111(d) correspond to the 2010 compliance
date for the Phase I Hg controls. EPA concluded that the compliance
dates for the two sets of controls should be synchronized. The oil-
fired unit population is limited (the number of existing units is
approximately 130) and their primary use is in providing peak shaving
power during periods of high electricity demand. Moreover, current
industry guidance indicates that the viability of new oil-fired
generation is extremely limited due to the economic and generation
efficiencies afforded by natural gas-fired simple- and combine-cycle
stationary combustion turbine units.
III. Emission Guidelines and Compliance Times for Coal-Fired Electric
Utility Steam Generating Units
In the January 30, 2004 NPR to reduce national mercury emissions,
EPA stated that it would develop and administer a national Hg trading
program to assist States in the achievement of these goals; today's
notice proposes such a program. This program employs a cap on total
emissions in order to ensure that emissions reductions are achieved,
while providing the flexibility and cost effectiveness of a market-
based system. This Section provides background information and a
description of the Hg Budget Trading Program, as well as an explanation
of how the trading program would interface with other State and Federal
programs. In addition, a model rule for the trading program is
proposed. States can voluntarily choose to participate in the Hg Budget
Trading Program, and they may do so by adopting the model rule, which
is a fully approvable control strategy for achieving emissions
reductions required under the mercury reduction rulemaking. States may
submit rules
[[Page 12404]]
other than the model rule, but EPA will need to review such rules.
States who do not adopt the model trading rule cannot participate in
the inter-state trading program administered by EPA.
More specifically, States that choose to participate in the Hg
Budget Trading Program must adopt all the provisions of the model rule,
except that they have the flexibility with respect to the requirements
for allocating allowances to their sources. The applicability of the
model trading rule is discussed more fully below. EPA must review these
State rules through notice-and-comment rulemaking, but this rulemaking
will be expedited for, at the least, those State rules that mirror the
model rule. If a State does not choose to participate in the Hg Budget
Trading Program (that is, it does not wish to allow its sources to
participate in inter-state trading, and it may or may not wish allow
its sources to participate in intra-state trading), then the State may
submit rules other than the model rule, and EPA will evaluate these
rules in the regular course of notice-and-comment rulemaking.
A. Program Summary
As discussed in the January 30, 2004 NPR, the trading program
establishes, for affected utility units, a first phase Hg cap at a
level that reflects the Hg reductions expected as co-benefits
accompanying the SO2 and NOX caps in the IAQR in
2010 and 2015 and a Phase II cap of 15 tons starting in 2018. The new
trading program for Hg would require sources to hold allowances
covering emissions beginning January 1, 2010. EPA is also 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
the January 30, 2004 NPR, EPA proposed a methodology for unit
allocations for existing units (see 69 FR 4651). New units will also be
covered under the Hg cap of the trading program and will be required to
hold allowances.
B. Hg Budget Trading Program
1. General Provisions
Today's proposed Hg Budget Trading Rule will be incorporated into
the 40 CFR part 60 as a new subpart HHHH. The new sections in subpart
HHHH of 40 CFR part 60 are described below. The provisions of 40 CFR
part 60 subpart HHHH will become effective and apply to sources only if
a State incorporates 40 CFR part 60 subpart HHHH by reference into the
State's regulation or adopts regulations that are in accordance with 40
CFR part 60 subpart HHHH.
a. Overview and Purpose. Section 60.4100 through 60.4106 of today's
proposed Hg Budget Trading Rule includes Sections describing: to whom
the Hg trading program would apply; the standard requirements for
participants in the program (permitting, Hg allowances, monitoring,
excess emissions, and liability provisions); exemptions for retired
units from the program requirements; definitions, measurements, and
abbreviations; and computation of deadlines stated within the proposal.
b. Definitions, Measurements, Abbreviations, and Acronyms. Many of
the definitions, measurements, abbreviations, and acronyms are the same
as those used in 40 CFR part 60, in order to maintain consistency among
programs. However, certain terms specific to the Hg Budget Trading
Program, including Hg Budget unit (a unit subject to the emissions
limitation under the Hg Budget Trading Program) and several others are
added. Key definitions are discussed in relevant Sections below
describing the rule.
c. Applicability. The EPA proposes that the Hg Budget Trading Rule
be applicable 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.
i. Monitoring. In general, sources that participate in a cap-and-
trade program must have the ability to accurately and consistently
account for their emissions. Accuracy is an important design parameter
because it ensures that emissions for all sources covered by the
trading program are within the cap. In addition, because each Hg
allowance will have economic value, it is important to ensure that
emissions (and thus allowances used) are accurately quantified.
Consistency is an important feature because it ensures that accuracy is
maintained from source to source and year to year. It also ensures that
the sources in the trading program are treated equitably. Finally,
consistency facilitates administration of the program for both the
regulated community and State and Federal agencies.
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.
As discussed further below, EPA is proposing revisions to 40 CFR
part 75 to establish requirements for mercury emission monitoring,
quality assurance, substitute data, record keeping, and reporting and
to include a requirement for States to require year-round part 75
monitoring and reporting for all sources. EPA believes that emissions
will then be consistently and accurately monitored and reported from
unit to unit and from State to State.
ii. Responsible Party. Another critical element of a trading
program is to be able to identify a responsible party for each
regulated source. The responsible party for a source covered by the
trading program would be required to demonstrate compliance with the
provisions of the Hg Budget Trading Program. In general, the coal-fired
electric Utility Units included in the proposed trading program have
readily identifiable owners and operators that would serve as the
responsible party.
d. Retired Unit Exemption. Section 60.4105 of today's proposal
provides an exemption from Hg Budget Trading Program requirements for
retired units. The purpose of this provision is to free retired Hg
Budget units from unnecessary requirements (e.g., emissions monitoring
and reporting). The EPA proposes an exemption beginning on the day the
unit permanently retires, requiring no notice and comment period
regarding the retirement. This provision proposes that the mercury
authorized account representative (Hg AAR) (i.e., the person authorized
by the owners and operators to make submissions and handle other
matters) submit notification to the permitting authority of the Hg
Budget unit's retirement within 30 days of the cessation of activity.
In response, the permitting authority would amend the operating permit
in accordance with the exemption and notify EPA of the unit's status as
exempt. Criteria within this provision ensure that all program
requirements prior to the exemption are fulfilled and records are kept
on site to verify the non-emitting status of the retired unit. A
retired unit could continue to hold Hg allowances
[[Page 12405]]
previously allocated or be allocated Hg allowances in the future
depending on the allocation provisions adopted by the State where the
retired unit is located. The number of future year Hg allowances that a
retired unit would be allocated would be dependent on the given State's
allocation system. The Hg allowance allocations are discussed below in
Section II.B.5 of this preamble.
In order to resume operation without violating program requirements
(i.e., an exemption requires that the unit's permit language be changed
to reflect that it would not emit any Hg emissions), the Hg AAR of the
Hg Budget unit must submit a permit application to the permitting
authority no less than 18 months (or less, if so specified by the
applicable State permitting regulations) prior to the date on which the
unit is first to resume operation, to allow the permitting authority
time to review and approve the application for the unit's re-entry into
the program. If a retired unit resumes operation, EPA proposes to
automatically terminate the exemption under this part.
e. Standard Requirements. Today's proposal delineates, in proposed
Sec. 60.4106, the standard requirements that Hg budget units and their
owners, operators, and Hg AARs must meet under the Hg Budget Trading
Program. This provision sets forth and provides references to other
portions of the trading rule for the full range of program
requirements: permits, monitoring, Hg emissions limitations, excess
emissions, recordkeeping and reporting, liability, and effect on other
authorities. For example, the permitting, monitoring, and emissions
limit requirements are discussed in general and the relevant Sections
of the trading rule are cited. The liability provisions state that the
requirements of the trading program must be met, and any knowing
violations or false statements are subject to enforcement under the
applicable State or Federal law. Violations and the associated
liability are established on a facility-wide basis. The provision
addressing the effect on other authorities establishes that no
provision of the trading program can be construed to exempt the owners
or operators of a Hg Budget source from compliance with any other
provision of the applicable SIP, any federally enforceable permit, or
the CAA. This provision ensures, for example, that a State may set a
binding source-specific Hg limitation and, regardless of how many
allowances a Hg Budget source holds under the trading program, the
emissions limit established in the SIP cannot be violated.
f. Computation of Time. Proposed Sec. 60.4107 clarifies how to
determine the deadlines referenced in the proposal. For example,
deadlines falling on a weekend or holiday are extended to the next
business day. These are the same computation-of-time provisions as are
in the regulation for the other emissions trading programs.
2. Hg Authorized Account Representative (AAR)
Sections 60.4110 through 60.4114 of today's proposed Hg Budget
Trading Rule establishes the process for certifying the Hg AAR and
describes his or her duties. A Hg AAR is the individual who is
authorized to represent the owners and operators of each Hg Budget unit
at a Hg Budget source in matters pertaining to the Hg Budget Trading
Program. Because the Hg AAR is representing the owners and operators of
all the Hg Budget units at a Hg Budget source, the Hg AAR must certify
that he or she was selected by an agreement binding on all such owners
and operators and is authorized to act on their behalf. The Hg AAR's
responsibilities include: the submission of permit applications to the
permitting authority, submission of monitoring plans and certification
applications, holding and transferring Hg allowances, and submission of
emissions data and compliance reports.
The Agency recognizes that the Hg AAR cannot always be available to
perform his or her duties. Therefore, the rule proposes to allow for
the appointment of one alternate Hg AAR (alternate Hg AAR) for a Hg
Budget source. The alternate Hg AAR would have the same authority and
responsibilities as the Hg AAR. Therefore, unless expressly provided to
the contrary, whenever the term ``Hg authorized account
representative'' is used in the rule, it should be read to apply to the
alternate Hg AAR as well. While the alternate Hg AAR would have full
authority to act on behalf of the Hg AAR, all correspondence from EPA,
including reports, would be sent only to the Hg AAR.
Today's proposal requires the completion and submission of the
account certificate of representation form in order to certify a Hg AAR
for a Hg Budget source and all Hg Budget units at the source. There
would be one standard form which would be submitted by sources to EPA.
The EPA would establish a compliance account for each source in the
mercury allownce tracking system (MATS). The form would include: the
plant name, State, and identifying number (ORIS or facility code); the
identifying number of each Hg budget unit at the source; the Hg AAR
name, the Hg AAR identification number (if already assigned), address,
phone, fax, and e-mail (as well as similar information for the
alternate Hg AAR, if applicable); the name of every owner and operator
of the source and each Hg Budget unit at the source; and certification
language and signature of the Hg AAR and alternate, if applicable.
In order to change the Hg AAR, alternate Hg AAR, or list of owners
and operators, EPA is proposing that a new complete account certificate
of representation be submitted. The EPA believes the Hg AAR
requirements afford the regulated community with flexibility, while
ensuring source accountability and simplifying the administration of
the trading program. These submissions can be made electronically to
EPA.
3. Permits
a. General Requirements. The EPA has attempted to minimize the
number of new procedural requirements for Hg Budget permitting and to
defer, whenever possible, to the permitting programs already
established by the permitting authority. The proposed Hg Budget Trading
Program regulations assume that the Hg Budget permit would be a portion
of a federally enforceable permit issued to the Hg Budget source and
administered through permitting vehicles such as operating permits
programs established under title V of the CAA and 40 CFR part 70. The
term ``Hg Budget permit'' throughout this preamble and the Hg Budget
Trading Program regulations therefore refers to the Hg Budget Trading
Program portion of the permit issued by the permitting authority to a
Hg Budget source.
b. Hg Budget Permit Application Deadlines. The proposed rule sets
the initial Hg Budget permit application deadlines for units in
operation before January 1, 2007 so that the permits will be issued by
January 1, 2010. January 1, 2010 is the beginning of the first control
period for the Hg Budget Trading Program, and therefore also the date
by which initial Hg Budget permits for existing units must be
effective. Application submission deadlines are based on the permitting
authority's title V permitting regulations. For instance, if a
permitting authority's permitting regulations allowed 12 months for
final action by the permitting authority on a permit application, the
application deadline for units in operation before 2007 governed by the
permitting rule would be January 1, 2009 (12 months prior to January 1,
2010). The same principle applies to Hg Budget units
[[Page 12406]]
commencing operation on or after January 1, 2007, except that the
application submission deadline is the later of the date the Hg Budget
unit commences operation or January 1, 2010. The Hg Budget permit
renewal application deadlines are the same as those that apply to
permit renewal applications in general for sources under title V. For
instance, if a permitting authority requires submission of a title V
permit renewal application by a date which is 12 months in advance of a
title V permit's expiration, the same date would also apply to the Hg
Budget permit application.
c. Hg Budget Trading Program Permit Application. The Hg Budget
Trading Program requires that a Hg Budget permit application properly
identify the source and include the standard requirements under
proposed Sec. 60.4121. The Hg Budget Trading Program permit
application should include all elements of the program (including the
standard requirements). Such an approach allows the permitting
authority to incorporate virtually all of the applicable Hg Budget
Trading Program requirements into a Hg Budget permit by including as
part of such permit the Hg Budget permit application submitted by the
source. Directly incorporating the Hg Budget permit application into
the Hg Budget permit and, thus, into the source's operating permit or
the overarching permit minimizes the administrative burden on the
permitting authority of including the Hg Budget Trading Program
applicable requirements.
d. Hg Budget Permit Issuance. As stated earlier, most of the
procedures needed by a permitting authority to issue Hg Budget permits
have already been established by the permitting authority through
permitting vehicles such as operating permits programs under title V
and 40 CFR part 70 or 71. Generally, the permits regulations
promulgated by the permitting authority cover: permit application,
permit application shield, permit duration, permit shield, permit
issuance, permit revision and reopening, public participation, and
State and EPA review. The proposed Hg Budget Trading Program permit
regulations generally require use of the procedures under these other
regulations and add some requirements such as Hg Budget permit
application submission and renewal deadlines, Hg Budget permit
application information requirements and permit content, and initial Hg
Budget permit effective dates.
e. Hg Budget Permit Revisions. For revisions to the Hg Budget
permit, the Hg Budget Trading Program again defers to the regulations
addressing permits revisions promulgated by the permitting authority
under title V and 40 CFR part 70 or 71. The proposal also provides that
the allocation, transfer, or deduction of Hg allowances is
automatically incorporated in the Hg Budget permit, and does not
require a permit revision or reopening by the permitting authority. The
Hg Budget permit must, however, expressly state that each source must
hold enough Hg allowances to account for Hg emissions by the allowance
transfer deadline for each control period. The EPA believes that
requiring the permitting authority to revise or reopen a Hg Budget
permit each time a Hg allowance allocation, transfer, or deduction is
made would be burdensome and unnecessary.
4. Compliance Certification
Sections 60.4130 through 60.4131 of today's proposed Hg Budget
Trading Rule sets forth the requirements concerning certification by
the Hg AAR at the end of each control period that the Hg Budget units
at the facility were in compliance with the emissions limitation and
other requirements of the Hg Budget Trading Program. The Hg AAR must
submit a compliance certification report for the Hg Budget units at
each facility by March 1 following the control period, to both the
permitting authority and the Administrator. This report must identify
the Hg Budget units and the Hg Budget source, and include a compliance
certification statement. The compliance certification statement must
indicate whether all of the applicable requirements of the Hg Budget
Trading Program, including the requirement to hold allowances greater
than or equal to emissions and the requirement to monitor and report
according to the provisions in Sec. 60.4106 of today's proposal, were
met by the unit for the most recent control period. The report also
allows the Hg AAR to specify which allowances (by serial number) should
be deducted from the Hg Budget facility's compliance account.
5. Hg Allowance Allocations
Sections 60.4140 through 60.4142 of today's proposed model rule
addresses the allocation of Hg allowances to Hg Budget units. Within
each participating State, the Hg Budget Trading Program would establish
a State trading program budget (i.e., a cap of annual Hg emissions for
all units included in the program), which is the total number of Hg
allowances that each State may allocate to its Hg Budget units for each
control period. Section 60.4141 of today's proposed rule sets timing
requirements for when the allocations should be completed by each State
and submitted to EPA for inclusion into the MATS and provides an option
for how States may allocate Hg allowances to the Hg Budget units.
States have the flexibility to allocate their state budget to
individual units however they choose.
a. State Trading Program Budget. The January 30, 2004 NPR proposed
a formula for determining the total amount of emissions for the Budget
Trading Program within a specific Sate for 2010, and, using that same
mechanism, proposed the amount of emissions for the Program within each
State for 2018. That formula is, in essence, the sum of the
hypothetical allocations to each affected Utility Unit in the State,
and that allocation, in turn, is based on the proportionate share of
their baseline heat input to total heat input of all affected units.
For purposes of this hypothetical allocation of the allowances, each
unit's baseline heat input is adjusted to reflect the ranks of coal
combusted by the unit during the baseline period. Adjustment factors of
1 for bituminous, 1.25 for subbituminous, and 3 for lignite coals were
proposed in the NPR. These adjustment factors and the methodology for
determining the State budgets are described in the memorandum entitled
``Allocation Adjustment Factors for the Proposed Mercury Trading
Rulemaking'' in the docket. Alternatively, for purposes of this
hypothetical allocation of allowances to Utility Units which where used
to calculate the State budgets, EPA could have used the proposed MACT
emission rate proposed in the NPR and the proportionate share of their
baseline heat input to total heat input of all affected units. EPA
solicits comment on this alternative to calculate State budgets. As
noted above, the sum of the unit emission allowances in a State would
comprise the State's emissions budget.
EPA proposes today that each State be required to submit a state
plan under section 111(d) that assures that the State budget is met by
capping emissions, through the allocation of allowances, from each
affected Utility Unit. The State may allocate allowances to Utility
Units in any manner it wishes, as long as the total number of
allowances does not exceed the State budget. The State is not required
to allocate allowances to each affected Utility Unit in accordance with
the allocation option proposed in Section III.B.4.c below or the
formula used to determine the State budget. Those unit-specific
allocations are hypothetical and determined solely for accounting
purposes.
[[Page 12407]]
EPA does, however, solicit comment on whether to require the State
to allocate allowances to each affected Utility Unit in accordance with
this hypothetical allocation. EPA recognizes that statements in the NPR
may be read to propose a requirement that the State must allocate
allowances to each affected Utility Unit in accordance with this
hypothetical allocation. Today's SNPR is proposing that the State may
allocate allowances in accordance with its own methodology. EPA
solicits comment on whether to authorize the State to have flexibility
in the allowance allocation methodology, or whether to mandate that the
State allocate allowances in accordance with the hypothetical
allocation, depending on whether the State (i) authorizes its sources
to participate in the interstate trading program, (ii) authorizes its
sources to participate in only intra-state trading, or (iii) does not
authorize its sources to trade allowances. Allocating allowances to
sources using the hypothetical allocation methodology satisfies the
requirements for States to meet the Standard of Performance required by
section 111(d) because the hypothetical allocation is consistent with
the State budgets and would ensure that the State budget and therefore
the Standard of Performance is met. The docket for today's action
includes a memorandum that describes in more detail the basis for EPA's
proposed allocation methods.
Finally, it should be noted that the State may decide to allocate
fewer total allowances to its sources than the amount of its budget.
b. Timing Requirements. Today's proposed rule sets minimum
requirements for when a State would finalize Hg allowance allocations
for each control period in the Hg Budget Trading Program and submit
them to EPA for inclusion into the MATS. The proposed timing
requirements ensure that all Hg Budget units would have sufficient time
and the same minimum amount of time to plan for compliance for each
control period and to trade Hg allowances. Finalizing allowances for
less than three years in advance may restrict a Hg Budget unit's
ability to plan for compliance by creating uncertainty year to year
about the amount of future allocations that the Hg Budget unit would
receive. It would also prevent a Hg Budget unit from officially
transferring future year allowances because the MATS only contains the
very near term years' allowances.
The timing requirements would also contribute to the efficient
administration of the Hg Budget Trading Program. By establishing this
schedule at the outset of the trading program, both the States and EPA
would be able to develop internal procedures for effectively
implementing the Hg allowance provisions of the trading program. This
is particularly important for EPA with its role as administrator of the
MATS for all participating States. The timing requirements would ensure
that EPA would be able to record in the MATS the time sensitive Hg
allowance allocations for the Hg Budget units in all participating
States at the same time for each control period.
States may choose any of a number of options for the timing of
issuing allowances, beyond the three year requirement, and that choice
will interact to a great extent with the state's choice of method for
allocating allowances. The timing options generally range from: (1)
Year-by-year allocations, in which the Hg allowance allocations would
be placed into the MATS on an annual basis for future control periods;
(2) 5 to 10 year allocations where Hg allowance allocations would be
periodically placed into the MATS for 5 to 10 consecutive control
periods; and (3) a single, permanent allocation where the Hg allowance
allocations would be set only once at the beginning of the trading
program and recorded in the MATS for an extended, rolling block of time
(e.g., a rolling 30-year period). These timing options can apply to
both an auctioning and a permanent allocation mechanism.
Timing options which provide an opportunity to periodically update
the allocation of Hg allowances to Hg budget units might have certain
advantages. These advantages include that an allocation regime which is
periodically updated would provide an opportunity to reallocate
allowances based on changes in the electricity industry that may
significantly affect the mix of electricity generators that produce
electricity in the future. Depending on the formula that is used to
allocate the allowances, trading programs that periodically update the
allocations may provide an opportunity to reward energy efficiency
improvements at specific Hg Budget units. They could also facilitate
the introduction of more efficient, new generation.
Permanent allocations provide a long planning horizon for the Hg
Budget units that receive an allocation. Permanent allocations would
not create incentives for the owners or operators of high emitting
units to continue operating only for the sake of continuing to receive
allowances, but would result in retired units receiving allowances in
perpetuity. Additionally, permanent allocations provide an incentive to
improve a Hg Budget unit's energy efficiency and require fewer
resources to administer as compared to updating allocation systems.
Nonetheless, these incentives would not affect the total emissions over
time because the emissions are restricted by the cap, regardless of the
allocation system. In a permanent allocation system, all allowances are
allocated to Hg Budget units at the beginning of the trading program.
New Hg Budget units that begin operations after the allocation of
allowances would be required to obtain allowances from the market in
order to comply with the trading program requirements (which may impede
competition by hindering the entry of new units into the market), or
there would need to be a new source set-aside that increased from year
to year, coupled with a declining allocation to existing sources.
EPA is leaving the choice of timing of allocations largely up to
the states, requiring only that they be finalized in the Hg Budget
Trading Program and submitted to EPA for inclusion into the MATS three
years in advance. This would ensure that all Hg Budget units would have
sufficient time and the same minimum amount of time to plan for
compliance for each control period and to trade Hg allowances. EPA is
soliciting comments on this timing requirement.
A rolling annual updating system, determining allocations for a
single control period six years in advance, has been developed in
coordination with the example allocation approach provided in the
subsequent section. The full example allocation approach is presented
in the regulatory text. This example is offered as guidance and not as
an implied requirement for the States to take part in the model trading
program. At the start of the program, initial allocations would be made
for the first five control periods of the program. Afterwards, annual
updating would determine the allocations for the control period six
years in advance. Consequently, units would always have in their
accounts five years of allowances going forward, which would facilitate
the operation of an efficient liquid allowance market and provide
greater certainty to unit's compliance planning decisions, but might
leave limited allowances in the near term for new units.
c. Options for Hg Allowance Allocation Methodology Recommendation.
Allowance allocations decisions in a cap-and-trade program largely
reflect distributional issues, as economic forces would be expected to
result in economically
[[Page 12408]]
efficient and environmentally similar outcomes (except in cases of
market failure). Consequently, the EPA is proposing to give states the
flexibility to choose an allocations method most appropriate for their
particular circumstances.
States have many different possible options and combinations in the
development of an allocations methodology. The key design differences
are: (1) Auction or free distribution of allowances; (2) permanent or
updated allowances; and (3) allowances based on input-basis, output
basis, or based on emission reductions. These options would differ in
terms of the amount of allowances different sources receive, whether
states generate revenue from the allowances, in their treatment of new
coal-fired generation, in their difficulty of administration, and in
their coordination with a safety valve mechanism.
Today's proposal allows the state to decide whether it will
allocate allowances to sources for free, or hold an auction to sell
them to bidders. Auctions, at which allowances would be offered for
sale, would ensure all parties access to allowances, and would be
efficient since sources would bid their perceived value for allowances.
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, or auctioning all available allowances. For
example, in the current Acid Rain Program, one percent of available
allowances could be used for auctions. The auctions would be open to
any person (including sources or third-party entities), who 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. Auctions could
be held regularly for single compliance periods, or less frequently for
a block of years at a time. An auctioning method of allocations would
work well with a safety valve mechanism, where allocations would be
reduced from future budgets to reflect allowances purchases via the
safety-valve. Auctions would also eliminate any potential disadvantage
to new units in the market for allowances. Responsibility for managing
auctions would fall to the individual states, which would also have
full discretion as to the use of auction revenues. EPA solicits comment
on whether it would have authority to charge purchasers for allowances,
in the case of Federal plans promulgated under 111(d)(2)(A) (if the
State fails to submit a State plan under section 111(d)(1)) or
112(n)(1)(A) (if EPA concludes that this provision provides regulatory
authority). Any amounts collected by EPA would be deposited in the
general revenues under the Miscellaneous Receipts Act.
However, requiring controlled sources to both reduce emissions and
pay for allowances for their remaining emissions could impose
significant costs on the emitting sources. Allocating allowances for
free could provide assistance to the entities incurring most of the
costs of complying with the necessary mercury reductions, lessening the
financial impact of the program on these sources. It would also give
states the ability to determine who would be the initial allowance
recipients.
If a state decided to allocate allowances for free, the state would
need to decide between permanent and updating allocations. As mentioned
above, permanent allocations provide a long planning horizon and would
not create incentives for the owners or operators of high emitting
units to continue operating. However, since they are based on a
historic baseline period, permanent allocations would not reflect
changes in the industry going forward and sources would continue to
receive allowances even after they retire. Permanent allocations do not
provide for allowances to new Hg Budget units that begin operations
after the allocation of allowances and these units would be required to
obtain allowances from the market in order to comply with the trading
program requirements. This could inhibit the entry of new units into
the market.
A new source set-aside (taking away allowances from existing
sources) could be created if there is a desire to encourage new
generation and concern about the availability of allowances on the
market. Alternately, a portion of allowances could be set aside and
sold through an auction to make these allowances accessible. A drawback
of these approaches is that it can be difficult to forecast the amount
of the new sources over time and thus the appropriate size of the set-
aside. Allowance requests resulting from the entry of numerous new
sources could, in time, exceed the amount of allowances set aside.
Updating allocations provide an opportunity to reallocate
allowances based on changes in the industry that may significantly
affect the mix of generators that produce electricity in the future. By
updating allocations, states would periodically review their basis for
allocations and reallocate allowances to sources. Updating would
include new generating units as they enter service and develop baseline
data (input or output) for calculation of allocations. However,
updating might also provide a subsidy to all generation, rewarding
units for generating by providing them allocations based on generation
(either input or output). Slightly different incentives would be
provided depending on whether the updating is input or output-based.
This may result in a slight distortion in the price of electricity, and
might also encourage older units not to retire, although the total
number of allowances (and thus emissions) are capped either way. Any
such effects would be less pronounced with the lengthening of the
period of time between the base-line and the actual receipt of the
allocations.
Updating may be done annually for a period in advance, or
periodically, with updates for several years at a time. The less
frequent the updating, the more this program becomes like a permanent
allocation. Updating also works well with a safety valve mechanism, as
it provides the opportunity to reduce allocations from a future budget
before they are allocated to reflect allowances purchases via the
safety-valve mechanism.
This SNPR proposes to allow states to decide the basis for their
allocation decisions, whether allocating through a permanent or
updating method. Generally, allocations have considered using a
baseline heat input (mmBtu of coal burned) or baseline generating
output (kWh). In a permanent allocation, this decision has consequences
that are purely distributional, with the output method favoring more
efficient existing plants. If states want to have allocations reflect
the difficulty of controlling for mercury, they might consider
multiplying baseline data by ratios based on coal type (1.0 for
bituminous, 1.25 for subbituminous, 3.0 for lignite for a heat input
basis), similar to the methodology proposed in the NPR for determining
state budgets.
Finally, states may consider hybrid systems, combining various
aspects of the general approaches outlined above, in their choice of
plan. In summary, the EPA is providing states with the flexibility to
develop a plan which is best suited to their circumstances.
Included below is an example (offered for informational guidance)
of an allocations methodology that includes allowances for new
generation, addresses the safety-valve mechanism, and is
administratively straightforward. The method involves input-based
[[Page 12409]]
allocations for existing coal units (with different ratios based on
coal-type), with updating to take into account new coal generation on a
modified output basis (without coal-type ratios). The method described
for allocating to existing sources is also consistent with the
hypothetical allocations relied on for determining the state budgets
and described in the January 30, 2004 NPR and the memorandum entitled
``Allocation Adjustment Factors for the Proposed Mercury Trading
Rulemaking'' in the docket.
Initial allocations for existing sources could be made for the
first five control periods at the start of the program, on the basis of
heat input and with different ratios based on coal-type. After the
first 5 years, the budget will be distributed on an annual basis,
taking into account data from new units.
As new units enter into service and establish a baseline, they
begin to pick up allowances in relation to their generation. Allowances
allocated to existing plants slowly decline as their share of total
heat input decreases with the entry of new plants. In this EPA example
methodology, existing units as a group would not update their heat
input numbers. This would eliminate the potential generation subsidy
(and efficiency loss) as well as an incentive for less efficient (and
higher ratio) units to generate more. This methodology would also be
easier to implement since it would not require the updating of existing
units' baseline data. However, retiring units would continue to receive
allowances indefinitely.
Through this EPA example methodology, new units as a group would
only update their heat input numbers once--in the initial baseline
period when they start operating. This would eliminate any potential
generation subsidy and be easier to implement, since it would not
require the collection and processing of data needed for regular
updating.
EPA believes that allocating based on heat input data (rather than
output data) for existing units 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.
However, allocating on the basis of input for new sources would serve
to subsidize less-efficient new generation. For a given generation
capacity, the most efficient unit would have the lowest fuel input or
heat input. Allocating to new units based on heat input may encourage
the building of less efficient units since they would get more
allowances than an efficient, lower heat input unit. The modified
output approach, as described below, would encourage new clean
generation and would not reward inefficient or high-emission new units.
Allowances would be allocated to new units on a modified output
basis. Once new units have an adequate operating baseline (in the EPA
example methodology, EPA proposes taking the average of the highest
three years out of five years of operations), the total annual heat
input of the affected units would be updated by adding the calculated
new unit modified-output to the original existing coal-type-adjusted
unit heat input. For purposes of including data from new units in the
updated allocation calculation, new units would calculate their heat
input by multiplying their gross output by a heat rate conversion
factor of 8,000 btu/kWh. The 8,000 btu/kWh conversion factor was chosen
as a mid-point between expected heat-rates for new pulverized coal
plants and new IGCC coal plants as assumed in EPA's economic modeling
analysis (IPM documentation at http://www.epa.gov/airmarkets/epa-ipm/attachment-h.pdf). This would create level benefits for new coal units
based on their output and provide incentives for efficiency (rather
than favoring higher heat-rate new units). A higher heat-rate
conversion number would provide more incentive for new generation, and
we are asking for comment as to the appropriate number. To calculate
their modified output number, new coal-fired cogeneration units would
add together their electric output and half of their equivalent
electrical output energy in the unit's process steam and multiply this
total by 8,000 btu/kWh. Allocations would be allocated to all units in
proportion to their share of the updated, adjusted total heat input.
New units that have entered service, but have not yet established a
baseline output and have not yet started receiving allowances through
the update, could receive allowances each year from a new source set-
aside. In the example methodology described in the model rule, EPA has
proposed a new source set-aside representing two percent of the State's
mercury trading program budget.
Allowances in the new source set-aside could be distributed in a
number of different ways. For example, as described in today's model
rule, the new source allowances could be distributed based on a unit's
utilization/output and the unit's mercury emission NSPS rate limitation
presented in the January 30, 2004 NPR. Because the proposed NSPS rates
vary across coal types, this allocation method could provide new coal
plant investors with varying incentives depending upon the coal type.
While this set-aside would help new sources relative to no set-aside,
because the demand for allowances for future sources is unknown, it is
difficult to know beforehand what should be the appropriate size of the
set-aside pool.
EPA is taking comment on a number of alternatives for distributing
the new source set-aside in the example methodology. For example, a
single emissions rate for all new coal plants may be used together with
utilization/output levels to calculate allowance allocations for new
coal units before they begin receiving allowances through the update.
Alternatively, the lower of the NSPS rates for the respective coal
types and a rate representing the proposed mercury cap in 2018 divided
by projected 2018 total affected unit generation may be used to
calculate allowance allocations for new coal units before they begin
receiving allowances through the update. This alternative would ensure
that new sources should receive allowances at the same rate as that
applied to existing sources and no greater than their proposed NSPS. We
ask for comment on these various proposals, and for any other
alternatives commenters may wish to raise.
In today's proposed example allocation methodology, these new units
would be granted allowances from the set-aside for the control period,
initially based on the unit's full utilization rates. At the end of the
year, the actual allowance allocation will be adjusted to account for
actual unit utilization/output, and excess allowances will be returned
and redistributed, first taking into account new unit requests that
were not able to be addressed. Any subsequent unused set-aside
allowances would be redistributed to existing units based on their
existing allocations. An alternate method for allocating these
allowances would provide new sources with allowances at the end of the
relevant control period, based on their actual utilization. This would
eliminate the need for returning and redistributing allowances, but
would also deprive sources of the ability to trade those allowances
during the course of the year. EPA is soliciting comment on the timing
and method of allocating allowances from the set aside in the example
methodology.
While EPA recognizes States' flexibility in choosing their
allocations method and is proposing that States be allowed to determine
their own method for allocating allowances to sources in their state,
EPA is also asking for
[[Page 12410]]
comment on all aspects of this example allocations proposal.
6. Safety Valve Provision
In the January 30, 2004 NPR, EPA is proposing a safety valve
provision that sets the maximum cost purchasers must pay for Hg
emissions allowances. This provision addresses some of the uncertainty
associated with the cost of Hg control.
Under the safety valve mechanism, the price of allowances is
effectively (although not legally) capped. Sources may purchase
allowances from subsequent year budgets at the safety-valve price at
any time. However, it is unlikely they would do so unless the market
allowance price exceeded the safety valve price. EPA proposes a price
of $2,187.50 for a Hg allowance (covering one ounce) and this price
will be annually adjusted for inflation. The permitting authority will
deduct corresponding allowances from future allowance budgets. EPA
solicits comment on whether it would have authority to charge
purchasers this amount for allowances, in the case of Federal plans
promulgated under 111(d)(2)(A) (if the State fails to submit a State
plan under section 111(d)(1)) or 112(n)(1)(A) (if EPA concludes that
this provision provides regulatory authority). Any amounts collected by
EPA would be deposited in the general revenues under the Miscellaneous
Receipts Act.
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, ensuring the integrity of the caps.
The safety valve mechanism would need to be incorporated into a
state's chosen allocations methodology to ensure the availability of
un-distributed allowances from which purchasers could borrow. Making
allowances available through the safety valve without taking them away
from future budgets would undermine the integrity of the cap. The
safety valve mechanism would be easiest to incorporate into a system
where allowances are periodically auctioned or updated because at least
some portion of the State budgets would not have been previously
allocated to individual units (which might not be the case in a
permanent, historically based allocation method). Within EPA's example
allocations methodology, the safety valve allowances borrowed from
future budgets would be taken out of the pool of allowances available
for units that have been generating for at least five years (not from
the new source set aside) in the subsequent updating calculation of
allocations. Under this allocation methodology, the future budget for
the State would be lowered by the amount borrowed through the safety
valve mechanism for the control period six years in advance.
We ask for comment on the need for a safety valve and the viability
of our example approach, and solicit suggestions for other viable
approaches.
7. Hg Allowance Tracking System
Sections 60.4150 through 60.4157 of today's proposed trading rule
covers the mercury allowance tracking system (MATS). The proposed rule
is intended to be reasonably consistent with the allowance tracking
systems developed for the NOX SIP Call and Acid Rain
Program. Such consistency would help to allow the integration of the a
mercury trading program with the existing trading programs under the
NOX SIP Call and Acid Rain Program and possible other
NOX and SO2 trading programs (under the IAQR) in
the future. It would also save industry and government the time and
resources necessary to develop new tracking systems.
The MATS would be an automated system used to track Hg allowances
held by Hg Budget units under the Hg Budget Trading Program, as well as
those allowances held by other organizations or individuals.
Specifically, the 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 is to provide an efficient, automated means of monitoring
compliance with the Hg Budget Trading Program. The MATS would 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. Although today's proposal
assigns each allowance a unique serial number, EPA requests comments on
the necessity of serial numbers and on whether the administrative
burden to allowance holders and EPA of tracking and reporting serial
numbers outweighs the benefits of serial numbers for tax and accounting
purposes.
The EPA is proposing that MATS contain two primary types of
accounts: Compliance accounts and general accounts. Compliance accounts
are created for each Hg Budget source with one or more Hg Budget units,
upon receipt of the account certificate of representation form. General
accounts are created for any organization or individual upon receipt of
a general account information form.
a. Compliance Accounts. As part of the implementation of the Hg
Budget Trading Program, EPA is proposing to establish compliance
accounts for each Hg Budget source upon receipt of the account
certificate of representation form. These accounts would be identified
by a 12-digit account number incorporating the plant's Office of
Regulatory Information System's (ORIS) code or facility identification
number. Allocations for the first six years (2010-2015), as prescribed
by each State, would be transferred into these compliance accounts
prior to the first control period in 2010. Prior to the second control
period, in 2011, and each year thereafter, allocations for the new
sixth year, as prescribed by each State, would be transferred into each
compliance account (e.g., in 2011, year 2016 Hg allowances would be
allocated). As for the deadline for transferring Hg allowances to cover
emissions in the control period (i.e., the Hg allowance transfer
deadline of midnight on March 1 following the control period), each
compliance account must hold sufficient Hg allowances to cover the Hg
Budget source's Hg emissions for the prior year's control period.
Utility companies may use general accounts to hold surplus allowances
(as has been done in the Acid Rain Program) for trading and banking.
Brokers and other entities use general accounts to hold allowances that
are intended to be traded.
b. Compliance. Once a control period has ended, Hg Budget source
would have a window of opportunity (i.e., until the Hg allowance
transfer deadline of midnight on March 1 following the control period)
to evaluate their reported emissions and obtain any additional Hg
allowances (including safety valve allowances) they may need to cover
the emissions during the year. On March 1 following each control
period, the Hg AAR must also submit a compliance certification report
for each Hg Budget source. Should the Hg Budget source not obtain
sufficient Hg allowances to offset emissions for the season, three Hg
allowances for each ounce of excess emissions would be deducted from
the source's compliance account for the following control period. EPA
believes that it is important to set up this automatic offset deduction
because it ensures that non-compliance with the Hg emission limitations
of this
[[Page 12411]]
part is a more expensive option than controlling emissions. EPA
required the same offset deduction of three to one in the
NOX SIP call, and is taking comment on the use of the same
ratio is today's proposed rule. The automatic offset provisions do not
limit the ability of the permitting authority or EPA to take
enforcement action under State law or the CAA.
c. General Accounts. Today's proposal allows any person or group to
open a general account in MATS. These accounts would be identified by
the ``9999'' that would compose the first four digits of the MATS
account number. Unlike compliance accounts, general accounts cannot be
used for compliance but can be used for holding or trading Hg
allowances (e.g., by Hg allowance brokers or owners of multiple Hg
Budget units or sources). General accounts are currently used for both
SO2 allowances in the Acid Rain Program and NOX
allowances in the NOX Budget Trading Program.
To open a general account, a person or group must complete the
standard general account information form, which is similar to the
account certificate of representation that precedes the opening of a
compliance account and any overdraft account. The form would include:
the Hg AAR name, phone, fax, and e-mail (as well as similar information
for the Alternate Hg AAR, if applicable); Hg AAR mailing address; the
names of all parties with an ownership interest with the respect to the
Hg allowances in the account; and certification language and signatures
of the Hg AAR and alternate, if applicable.
Revisions to information regarding an existing general account are
made by submitting a new general account information form which would
be sent to EPA in all cases, whether the form is used to open a new
account, or revise information on an existing one. The EPA would notify
the Hg AAR cited on the application of the establishment of his or her
account in the MATS or of the registration of requested changes.
8. Banking
Banking is the retention of unused allowances from one control
period for use in a later control period. 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 (e.g.,
by allowing for periodic increased generation activity that may occur
in response to interruptions of power supply from non-Hg emitting
sources). In addition, a banked allowance is one less ounce of
pollutant emitted in a given year. On the other hand, banking may
result in banked allowances being used to allow emissions in a given
year to exceed a State's trading program budget.
EPA is proposing that banking of allowances after the start of the
Hg trading program be allowed with no restriction. Banking after a
program starts and the budget is imposed allows sources to retain any
allowances not surrendered for compliance at the end of each control
period. Once the trading program budget is in place, sources may over-
control for one or more seasons and withdraw from the bank in a later
season. This type of banking provides the general advantages as
described above (encourages early reductions, stimulates the market,
and provides flexibility to sources), while also potentially causing Hg
emissions in some control periods to be greater than the allowances
allocated for those seasons.
9. Allowance Transfers
The EPA is proposing that once a Hg AAR is appointed and an account
is established in the MATS, Hg allowances can be transferred to or from
the accounts with the submission of an allowance transfer form to EPA.
Transfers can occur between any accounts at any time of year with one
exception: transfers of current and past year allowances into and out
of compliance accounts are prohibited after the Hg allowance transfer
deadline (March 1 following each control period) until EPA completes
the annual reconciliation process by deducting the necessary
allowances.
There would be one standard Hg allowance transfer form. This form
would be submitted to the EPA in all cases. This form can be submitted
electronically. The form would include: the transferror and transferee
MATS account numbers; the transferror's printed name, phone number,
signature, and date of signature; and a list of allowances to be
transferred, by serial number.
10. Emissions Monitoring and Reporting
Monitoring and reporting of an affected source's emissions are
integral parts of any cap-and-trade program. Consistent and accurate
measurement of emissions ensures that 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 each
allowance 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 proposed Hg cap-and-trade program, EPA believes that
emissions must be monitored continuously in order to ensure the
precision, reliability, accuracy, and timeliness of emissions data that
support the cap-and-trade program. The EPA is proposing to allow two
methodologies for continuously monitoring mercury emissions: (1)
Mercury continuous emission monitoring systems (CEMS); and (2) sorbent
trap monitoring systems. Based on preliminary evaluations, EPA believes
it is reasonable to expect that both technologies will be well-
developed by the time a mercury emissions trading program is
implemented.
The EPA is proposing, and solicits comment on, two alternative
approaches for the continuous monitoring of Hg emissions, as described
below and discussed in more detail in section II.B of the Appendix A to
this preamble.
In the first alternative, most sources would be required to use
CEMS, with low-emitting sources having Hg emissions at or below a
specified threshold value being allowed to use sorbent trap monitoring
systems. The proposed threshold value is 9 lb (144 ounces) of Hg
emissions per year (based on a 3-year average), although EPA is taking
comment on three alternative thresholds of 29, 46, and 76 lb/yr.
Alternative 1 represents EPA's traditional approach to implementing
an emissions trading program. The Acid Rain Program, as established by
Congress in the 1990 Amendments to the Act, required the use of CEMS or
an alternative monitoring system that is demonstrated to provide
information with the same precision, reliability, accuracy, and
timeliness as a CEMS. In implementing that program, as well as the
NOX Budget Trading Program, EPA has allowed alternatives to
CEMS only where the emissions contributed by a particular category of
affected sources are at a low level in comparison to the emissions cap
for the program, or where an alternative monitoring system has been
demonstrated, according to specified criteria, to meet the standard
Congress set.
In the second alternative, all sources would be allowed to use
either CEMS or sorbent trap monitoring systems. Those sources whose Hg
emissions are above the specified emission threshold would
[[Page 12412]]
choose between CEMS and sorbent trap monitoring with quality assurance
(QA) procedures comparable to a CEMS, to ensure the accuracy of
measurements made for program compliance.
The QA requirements for the Acid Rain Program mandated by Congress
under the Act have been codified in Appendices A and B of the Acid Rain
Continuous Monitoring Regulation (40 CFR part 75). Part 75 specifies
that each CEMS must undergo rigorous initial certification testing and
periodic quality assurance testing thereafter, including the use of
relative accuracy test audits (RATAs). A standard set of data
validation rules and substitute data procedures apply to all of the
CEMS. These stringent requirements provide an accurate accounting of
the mass emissions from each affected source, and provide prompt
feedback if the monitoring system is not operating properly. This
ensures a level playing field among the regulated sources with accurate
accounting for every ton of emissions, which inspires confidence in the
trading of allowances.
For the purposes of a Hg emissions trading program, EPA believes
that the same high level of QA should be required for both CEMS and
sorbent trap monitoring systems, particularly for the higher-emitting
sources that are responsible for the bulk of the Hg emissions. To
achieve this, proposed Alternative 2 would require that for the sources
with Hg emissions above the specified threshold value, a minimum of one
substantive QA test of each monitoring system would be performed each
quarter. A quarterly linearity check of each CEMS would be required, as
well as an annual RATA. For the sorbent trap systems, which cannot
accept calibration gas and, therefore, cannot be tested for linearity,
an annual RATA and three quarterly 3-run relative accuracy audits
(RAAs) would be required. This general approach to quality-assurance of
continuous monitoring systems is consistent with both Part 75, Appendix
B, and with Appendix F to 40 CFR part 60. However, the EPA is willing
to consider replacing the RAA requirement with another type of
substantive quarterly QA test, if commenters who favor the use of
sorbent trap systems are aware of, and can provide details of, any such
test or procedure.
For affected sources with Hg emissions at or below the specified
threshold value, Alternative 2 would still require quarterly linearity
checks and annual RATA for Hg CEMS, but for the sorbent trap monitoring
systems, only an annual RATA would be required--the quarterly RAA
requirement would be dropped.
The use of sorbent trap monitoring systems as an alternative to
CEMS for monitoring Hg emissions has been proposed by EPA for
determining compliance under either of the alternative non-trading
approaches in the NPR for regulating Hg emissions from coal-fired
utility units. The proposed QA requirements for CEMS and sorbent trap
systems in Alternative 2 above are more stringent than the proposed QA
requirements for monitoring compliance with the non-trading compliance
alternatives in the NPR. This difference in the level of required QA
reflects a fundamental difference in the purposes of monitoring for an
emissions trading program compared to monitoring for an emissions
limitation program. Monitoring for the trading program requires
frequent assessments of the accuracy of the measurement method, because
each unit of emissions measured is tied to an allowance which is
tradeable at any time throughout the year. It is important for source
owners to know how much ``money is in the bank'' at any given time.
This need was recognized by Congress when it required the use of CEMS
in the Acid Rain Program, which serves as the model for both the
NOX Budget Trading program and the proposed Hg trading
program. Monitoring for a non-trading standard may not require such
frequent assessment of monitoring system performance, because the
compliance determination is done on an annual or semi-annual basis,
using data that has been collected over a long period of time, and is
designed only to determine if the emission limit has been met. The
amount that a unit is below or above a non-trading standard does not
translate into a tradeable commodity which can be bought or sold
throughout the year.
Consistent with the current requirements in Part 75 for the Acid
Rain and the NOX SIP Call programs, the proposed rule would
allow sources, under Section 60.4175 of Subpart HHHH of Part 60 and
under Section 75.80(h) of Subpart I of Part 75, to petition for an
alternative to any of the specified monitoring requirements in the
rule. This provision provides sources with the flexibility to petition
to use an alternative monitoring system under Subpart E of Part 75 or
variations of the proposed ones as long as the requirements of existing
Section 75.66 are met. Proposed amendments to 40 CFR part 75 (Part 75),
as summarized in Appendix A to this preamble, set forth the specific
monitoring and reporting requirements for Hg mass emissions and include
the additional provisions necessary for a cap and trade program. Part
75 is used in both the Acid Rain and the NOX Budget Trading
programs, and most sources affected by this rulemaking are already
meeting the requirements of Part 75 for one or both of those programs.
In order to ensure program integrity, EPA proposes to require
states to include year round Part 75 monitoring and reporting for Hg
for all sources. Proposed deadlines for monitor certification and other
details are specified in the model trading rule. EPA believes that
emissions will then be accurately and consistently monitored and
reported from unit to unit and from State to State.
Part 75 also specifies reporting requirements. As is currently
required for sources subject to both the Acid Rain program and the
NOX Budget Trading program, EPA proposes to require year
round reporting of emissions and monitoring data from each unit at each
affected facility. As required for the Acid Rain program and the
NOX Budget Trading program, this data would be provided to
EPA on a quarterly basis in a format specified by the Agency and
submitted to EPA electronically using EPA provided software. We have
found this centralized reporting requirement necessary to ensure
consistent review, checking, and posting of the emissions and
monitoring data at all affected sources, which contributes to the
integrity and efficiency of the trading program.
11. Program Audits
The EPA would publish a report annually, commencing after the first
year of compliance, that would contain, for each Hg budget unit, the
control period Hg emissions and the number of Hg allowances deducted
for all reasons. This would be done in order for States to track
emissions and Hg allowance transaction activity in neighboring States.
12. Administration of Program
The administration of this program would be somewhat different from
the administration of a typical State program. This is both because of
the trading aspects of the program and because of the national nature
of the trading program. In order for the market forces underlying the
trading program to work, the sources that participate in the trading
program must have confidence in the market. This confidence stems from
a number of factors including: a belief that all of the sources
included in the program are following the same set of rules, and a
belief that trades can be
[[Page 12413]]
made easily, quickly, and with a great deal of confidence that they
will not be altered or denied. Several things can help to foster these
beliefs and thus a confidence in the market. The first is to start with
a consistent set of rules. This can be done by developing a model rule
and having all States and sources that participate in the trading
program abide by the ground rules set forth in the model rule. The
second is to implement those rules in a consistent and efficient
manner. Because of the multi-state nature of the program, it would be
difficult for any individual State to do that by itself. Therefore, EPA
is proposing that this program be implemented jointly by EPA and the
States that choose to participate in the program. As part of this joint
implementation, States would have specific roles, EPA would have
specific roles, and there would be roles that States and EPA would
perform jointly.
States would be responsible for developing and promulgating rules
consistent with the model rule and for submitting those rules as part
of the State plan States would also be responsible for identifying
sources subject to the rule, issuing new or revised permits as
appropriate, and determining Hg allowance allocations. In addition,
they would be responsible for receiving, reviewing and, where
appropriate, approving most monitoring plans and monitoring
certification applications, observing monitor certification and ongoing
quality assurance testing and performing audits. The final primary area
of State responsibility would be enforcement of the trading program. If
violations occur, the State would take the lead in pursuing enforcement
action. However, once the rules are approved as part of the State plan,
they would also become federally enforceable, and EPA could also take
enforcement action.
The EPA would have two primary roles in administration of the
program. The first role would be EPA's traditional role in the approval
and oversight of the State plan . The second would be a more unique
role for EPA, in which EPA would administer significant portions of the
program.
In EPA's traditional role in the State plan process, EPA would be
responsible for taking action to approve or disapprove the State plan
revision once it was submitted to EPA. Once the State plan revision was
approved, EPA would play an oversight role in ensuring that the State
plan was properly implemented. This oversight role might include audits
of the State program, or taking enforcement action, if EPA believed
that sources were violating the State plan .
In EPA's more unique role as administrator of portions of the
program, EPA would run both the system to receive, store program
related data, and verify total emissions for the control period, and
the MATS. The EPA would use the same system that it is currently using
to track emissions data from the Acid Rain Program and the
NOX SIP Call. There are a number of advantages to the
sources, States, and EPA to using this existing system. Since many
units are already reporting to the system for purposes of the Acid Rain
Program and NOX Budget Trading Program, using this existing
system will represent little change for many units and EPA. This will
help to reduce administrative costs for both units and EPA and will
help to minimize startup problems associated with a new program. It
also means that each State will not need to develop, maintain and
operate such a system.
In addition to receiving the emissions data, quality assuring it,
and providing reports to both States and units about the emissions
data, EPA would have several other responsibilities as the
administrator of the data system. The EPA would be involved in approval
of any petitions for alternatives to the allowable monitoring methods.
The EPA would also be involved in providing units and States assistance
in using the data system. This assistance may include: Answering
individual questions from units and States, providing guidance
documents and training for units and States, and providing software to
assist in the submittal of program related data.
As the administrator of MATS, EPA would be responsible for
receiving applications for Hg AARs, tracking all official transfers of
Hg allowances, and using the end of control season emissions data and
Hg allowance data to determine compliance for the control season. In
order for EPA to play this role, each State would have to provide EPA
with its Hg allowance allocations consistent with a prescribed schedule
and format. The Hg AARs for individual sources would have to provide
EPA with information about all official Hg allowance transfers in a
prescribed format. The Hg AAR's would also have to provide EPA with an
end of control period compliance certification. At the end of the
control period, EPA would use all of this data to determine how many Hg
allowances should be deducted from each source's compliance account. In
the event that there were not enough Hg allowances to cover a source's
emissions for a control period, EPA would notify the State and would
automatically deduct Hg allowances for the next control period
according to the emissions offset provisions set forth in the proposed
trading rule.
The main joint role that EPA and States would have is for the
approval of alternatives to the allowable monitoring methods. This role
is more fully discussed in Section V.C.9 of the preamble on monitoring.
C. Approvability of Trading Rule Within a State Plan
1. Necessary Common Components of Trading Rule
The EPA intends to approve the portion of any State's plan
submission that adopts the model rule, provided: (1) The State has the
legal authority to adopt the model rule and implement its
responsibilities under the model rule, and (2) the state plan
submission accurately reflects the Hg reductions to be expected from
the State's adoption of the model rule. Provided a State meets these
two criteria, then EPA intends to approve the model rule portion of the
State's plan submission.
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 is
necessary to ensure a viable and efficient trading program with low
transaction costs and minimum administrative costs for sources, States,
and EPA. Consistency in areas such as allowance management, compliance,
penalties, banking, emissions monitoring and reporting and
accountability are essential.
The EPA's intent in issuing a model rule for the Hg Budget Trading
Program is to provide States with a model program that serves as an
approvable strategy for achieving the required reductions. States
choosing to participate in the program will be responsible for adopting
State regulations to support the Hg Budget Trading Program, and
submitting those rules as part of the state plan. There are two
alternatives for a State to use in joining the Hg Budget Trading
Program: incorporate 40 CFR part 60, subpart HHHH by reference into the
State's regulations or adopt State regulations that mirror 40 CFR part
60, subpart HHHH, but for the potential variations described below.
Some variations and omissions from the model rule are acceptable in
a State rule. This approach provides States
[[Page 12414]]
flexibility while still ensuring the environmental results and
administrative feasibility of the program. EPA proposes that in order
for a state plan to be approved for State participation in the Hg
Budget Trading Program, the State rule should not deviate from the
model rule except in the area of allowance allocation methodology.
Allowances allocation methodology includes any updating system and any
methodology for allocating to new units.
State plans incorporating a trading program that is not approved
for inclusion in the Hg Budget Trading Program may still be acceptable
for purposes of achieving some or all of a State's obligations provided
the general criteria. However, only States participating in the Hg
Budget Trading Program would be included in EPA's tracking systems for
Hg emissions and allowances used to administer the multi-state trading
program.
In terms of allocations, States must include an allocation section
in their rule, conform to the timing requirements for submission of
allocations to EPA that are described in this preamble, and allocate an
amount of allowances that does not exceed their State trading program
budget. However, States may allocate allowances to budget sources
according to whatever methodology they choose. The EPA has included an
optional allocation methodology but States are free to allocate as they
see fit within the bounds specified above, and still receive state plan
approval for purposes of the Hg Budget Trading Program.
2. Revisions to Regulations
Today's action proposes revisions to the regulatory provisions in
40 CFR 60.21 and 60.24 to make clear that a standard of performance for
existing sources under section 111(d) may include an allowance program
of the type described today.
D. Co-Proposal of Cap- and Trade Program under CAA Section 112(n)
In the January 30, 2004 NPR, EPA has taken comment on a proposal to
promulgate, under section 112(n)(1)(A), a cap-and-trade program for Hg
from coal-fired Utility Units. The model rule proposed here for Section
111 would serve as the Federal trading rule if the EPA decides to
promulgate a cap-and-trade program under CAA Section 112. In general, a
trading program under Section 112(n)(1)(A) would be federally
implemented with the EPA serving as the permitting authority, unlike
Section 111 which has the States serving as the permitting authority.
Today's proposed model trading rule would be implemented the same for
each state with no opportunity for flexibility for certain operational
aspects of the trading program (i.e., allocation methodologies) among
different States.
In implementing this program under section 112(n), EPA would adopt
caps and establish deadlines similar to those published on January 30,
2004 under the section 111 cap and trade proposal. EPA would allocate
these cap levels of annual emissions across coal-fired units using the
proposed MACT emission limits presented in the NPR and the
proportionate share of their baseline heat input to total heat input of
all affected units. Alternatively, EPA could allocate these cap levels
of annual emissions across all coal-fired Utility Units in accordance
with the allocation methodology identified in today's section 111 cap-
and-trade proposal. EPA is soliciting comment on this alternative
proposal.
For new units under a section 112 trading program, EPA is proposing
they would be covered under the cap and would use a similar new unit
set-aside in combination with an updating allocation system discussed
under today's section 111 proposal and provided in today's regulatory
text. Since no NSPS would be required under section 112, EPA would also
make adjustments to its new unit allocation methodology proposed under
section 111. EPA is proposing that initially the new unit would receive
allocation based on their utilization/output and MACT rate limitations
proposed in the NPR, until the new unit establishes a baseline output
and receives allowances through the updating mechanism.
EPA is also proposing the use of a safety valve of $2,187.50 per Hg
allowance (covering one ounce) under a section 112 trading program. The
safety valve would be implemented similarly to today's section 111
trading program, except that the funds would be collected to the U.S.
Treasury and not the State. EPA is taking comment on the implementation
of a safety valve under section 112 and EPA is taking comment on
whether it has authority under a 112(n)(1)(A) to collect payment from
the purchaser.
EPA would also require part 75 monitoring requirements identified
in today's section 111 proposal. In addition, a trading program under
section 112 would provide for administrative appeals at EPA of final
agency actions under the program.
IV. Statutory and Executive Order Reviews
In the NPR, EPA provided its review of the statutory and executive
order requirements under this rulemaking. These orders include: (1)
Executive Order 12866: Regulatory Planning and Review, (2) Paperwork
Reduction Act, (3) Regulatory Flexibility Act, (4) Unfunded Mandates
Reform Act of 1995, (5) Executive Order 13132: Federalism, (6)
Executive Order 13175: Consultation and Coordination with Indian Tribal
Governments, (7) Executive Order 13045: Protection of Children from
Environmental Health and Safety Risks, (8) Executive Order 13211:
Actions Concerning Regulations that Significantly Affect Energy Supply,
Distribution, or Use, and (9) National Technology Transfer and
Advancement Act.
The following provides a summary of EPA's conclusions. For
Executive Order 12866: Regulatory Planning and Review, EPA concluded
the proposed rule was an economically ``significant regulatory action''
because the annual cost may exceed $100 million dollars. For the
Paperwork Reduction Act, EPA provided an analysis of the information
collection requirements required by the proposed rule. For the
Regulatory Flexibility Act, EPA determined that the proposed rule will
not have a significant impact on a substantial number of small
entities. For the Unfunded Mandates Reform Act of 1995, EPA 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 aggregate, or the private sector in any one year; and
accordingly, EPA prepared a written statement under section 202 of the
UMRA which is summarized in the NPR. For Executive Order 13132 and
Executive Order 13175, EPA concluded that the proposed rule did not
have federalism or tribal implications. For Executive Order 1304, EPA
concluded the strategies proposed in the NPR will further improve air
quality and will further improve children's health. For Executive Order
13211, EPA concluded that the proposed rule was significant because the
proposal had a greater than a 1% impact on the cost of electricity
production and because it results in the retirement of greater than 500
MW of coal-fired generation. In this SNPR, EPA is not making changes to
these statutory and executive order conclusions.
Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (NTTAA), Pub. L. No. 104-113, section 12(d) (15 U.S.C. 272
note)
[[Page 12415]]
directs EPA to use voluntary consensus standards in its regulatory
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, and business practices) that are developed or adopted by
voluntary consensus standards bodies. The NTTAA directs EPA to provide
Congress, through OMB, explanations when the Agency decides not to use
available and applicable voluntary consensus standards.
This action proposes a model cap-and-trade program including
environmental monitoring and measurement provisions that States are
encouraged to adopt as part of their SIPs. If States adopt those
provisions, sources that participate in the cap-and-trade program would
be required to meet the applicable monitoring requirements of part 75.
Part 75 incorporates a number of voluntary consensus standards.
Further discussion of how EPA intends to adhere to the requirements
of the NTTAA in this rulemaking is containing in a technical support
document that will be placed in the e-docket by the date of publication
of this document.
Dated: February 24, 2004.
Michael O. Leavitt,
Administrator.
Appendix A to the Preamble--Proposed Changes to Parts 72 and 75
I. Summary of Proposed Changes
As required by Title IV of the Act, Part 75 contains
requirements for continuously monitoring and reporting
SO2 mass emissions, CO2 mass emissions,
NOX emission rate and heat input rate under the Acid Rain
Program. Subpart H of Part 75 also provides NOX mass
emission monitoring guidelines that may be adopted for use under a
State or Federal NOX mass emission reduction program.
(Subpart H has in fact been adopted under the NOX Budget
Trading Program established in response to the 1998 State
Implementation Plan (SIP) Call by the Administrator.) However, Part
75 does not currently contain requirements for monitoring or
reporting mercury mass emissions.
Today's proposed rule would add Subpart I (Sec. Sec. 75.80
through 75.84) to Part 75. For mercury mass emissions monitoring,
Subpart I would serve the same purpose as Subpart H does for
NOX mass emissions monitoring, in that it would provide
the monitoring guidelines for a multi-state trading program. Subpart
I would provide standard procedures for obtaining precise, reliable,
accessible, and timely mercury mass emissions data under such a
program.
If the proposed Subpart I monitoring provisions were to be
adopted as part of a mercury mass emission reduction program, States
would not have to develop their own mercury emission reduction
strategies and industry would not have to become familiar with and
implement multiple approaches to achieving the required emission
reductions.
Today's proposed rule would add specific mercury monitoring
provisions to Parts 72 and 75, in support of Subpart I. One
definition in Sec. 72.2 would be revised and one new definition
would be added. The proposal would add two new sections to Part 75
(Sec. Sec. 75.38 and 75.39), and would revise Sec. Sec. 75.2,
75.10, 75.15, 75.20, 75.21, 75.22, 75.24, 75.31, 75.32, 75.33,
75.37, 75.38, 75.39, 75.53, 75.57, 75.58, and 75.59. Revisions to
Appendices A, B, and F of 40 CFR part 75 are also proposed. The
proposed amendments to Parts 72 and 75 would only apply to sources
in a State or Federal mercury mass emissions reduction program that
adopts the monitoring provisions of Subpart I.
Today's proposed rule therefore encourages States to consider
implementing a cap-and-trade program for mercury mass emissions
reduction, using Part 75 monitoring. Having a standardized approach
to emissions monitoring would greatly facilitate the administration
of such a program. It would also establish a ``level playing field''
among the regulated sources, thereby ensuring the integrity of the
commodity being traded (i.e., the emission allowances). These
concepts have been convincingly demonstrated by the success of the
EPA's Acid Rain Program.
II. Detailed Discussion of the Proposed Revisions
A. Monitoring Requirements for a Mercury Trading Program
Today's proposed rule would add emission monitoring requirements
to Part 75 for a mercury mass emission reduction program. To achieve
this, Subpart I, containing five new sections (Sec. Sec. 75.80
through 75.84), would be added to the rule. Compliance with Subpart
I would be required only if the mercury monitoring provisions of
Subpart I were adopted as an element of a State or Federal mercury
mass emissions reduction program.
Under proposed Sec. 75.80(a), the term ``affected unit'' would
mean any coal-fired unit subject to such a program. The ``permitting
authority'' would be the State or Federal authority under which the
program is implemented, and the ``designated representative'' would
be the party responsible to ensure that the affected unit compliance
with the program requirements.
If an affected unit in the mercury mass emission reduction
program were also subject to the Acid Rain Program or to other
programs requiring the use of Part 75 monitoring (e.g., the
NOX Budget Trading Program), the owner or operator would
have to comply with the mercury monitoring provisions in addition to
the monitoring requirements of the other program(s). Compliance with
the monitoring and reporting provisions of Subpart I would be
required by the applicable deadline specified in the State or
Federal regulations establishing the trading program.
Regarding the monitoring of mercury emissions, proposed Sec.
75.80(c) sets forth prohibitions similar to those outlined in the
Acid Rain Program. Specifically, the use of any other alternative
monitoring system, reference method, or continuous emission
monitoring system without obtaining prior written approval from the
permitting authority would be prohibited. In addition, the owner or
operator of an affected unit would be prohibited from: (1) Operating
the unit so as to discharge mercury to the atmosphere without
accounting for such emissions; (2) disrupting the continuous
emission monitoring system or any other approved emission monitoring
method to thereby avoid monitoring and recording mercury mass
emissions; or (3) retiring or permanently discontinuing the use of
the required continuous emission monitoring systems, or any other
approved emission monitoring system(s) except in a few precisely
defined circumstances.
Proposed Sec. 75.80(d) describes the initial certification,
recertification, and quality-assurance (QA) requirements for the
monitoring systems needed to quantify mercury mass emissions. In
general, these requirements would be the same as or similar to the
ones established for Acid Rain Program monitoring systems in
Sec. Sec. 75.20 and 75.21 and in Appendix B of 40 CFR part 75.
Since most coal-fired electric generating units are subject to the
Acid Rain Program and are familiar with the basic Part 75 monitor
certification and QA procedures, EPA believes that this would
facilitate compliance with the mercury monitoring requirements.
Section 75.80(f) of the proposed rule would require the owner or
operator to report substitute data values for every unit operating
hour in which a valid, quality-assured hour of mercury emissions
data is not obtained with a certified monitoring system or a
reference method. For uncertified monitoring systems, maximum
potential concentrations or emission rates would be reported until
all of the certification tests have been passed. After
certification, special missing data algorithms would be used to
provide the substitute data values. These missing data routines are
discussed in greater detail below, in section II.C.6 of this
appendix.
Proposed Sec. 75.80(h) would allow sources to petition for an
alternative to any requirement of Subpart I. The petition would have
to meet the requirements of Sec. 75.66 and any additional
requirements established by the State or Federal mercury mass
emission reduction program.
Proposed Sec. 75.81 sets forth the general requirements for
monitoring mercury emissions and heat input for affected units with
simple exhaust configurations (i.e., one unit, one stack). Note that
although mercury compliance would be determined on a facility-wide
basis, the emissions from each individual unit at the facility would
be monitored, in the same manner as is done under the Acid Rain and
NOX Budget Programs. The owner or operator would be
required to determine hourly mercury mass emissions in one of two
ways: (1) by monitoring the mercury emission rate (lbs/10\12\ Btu),
the unit heat input rate (mmBtu/
[[Page 12416]]
hr), and the unit operating time (hr); or (2) measuring mercury
concentration ([mu]g/dscm), the stack gas flow rate (scfh), and the
unit operating time (hr). In both cases, the hourly mercury mass
emissions (in ounces) would be determined by multiplying the
measured parameters together and using a conversion constant to
obtain the desired units of measure.
To use the first mercury mass monitoring option (i.e., mercury
emission rate times heat input rate), the owner or operator would be
required to install a mercury-diluent CEMS (consisting of a mercury
concentration monitor and an O2 or CO2 diluent
gas monitor), a flow rate monitoring system, and a continuous
moisture monitoring system (or to use an appropriate default
moisture value, either from Sec. 75.11 or Sec. 75.12, or a site-
specific value approved by petition under Sec. 75.66).
If the source elected to use the second mercury mass monitoring
option (i.e., mercury concentration multiplied by flow rate), a
mercury concentration monitor or a sorbent trap monitoring system
would be required, along with a flow rate monitoring system, a
continuous moisture monitoring system (or approved default moisture
value), and, if heat input monitoring is required under the trading
program, the owner or operator would also have to certify an
O2 or CO2 monitoring system. Regarding the use
of sorbent trap monitoring systems, two versions of Sec.
75.81(b)(1) are being proposed, corresponding to two alternative
approaches discussed in detail below, in section II.B.3 of this
appendix. Under Alternative 1, the use of sorbent trap
systems would be restricted to affected units that emit less than 9
lbs (144 ounces) of mercury per year (i.e., on a 3-year average
basis, for the same calendar years used to allocate the Hg
allowances). Under Alternative 2, this restriction does
not appear in proposed Sec. 75.81(b)(1). Finally, note that under
proposed Sec. 75.81(c), new units that commence commercial
operation more than 6 months after the date of publication of the
final rule implementing the trading program would be required to use
mercury CEMS. For new coal-fired electric generating units, this is
consistent with the monitoring requirements for other pollutants
(e.g., SO2 , NOX) under NSPS and the Acid Rain
Program.
Section 75.82 of the proposed Subpart I sets forth requirements
for monitoring emissions from units with common stack or multiple
stack exhaust configurations. While many power plants have simple
one unit-one stack exhaust configurations with CEMS installed on the
stack, other plants have more than one unit discharging through a
common stack or have a unit that discharges through multiple stacks.
The emission calculations for a single unit with a single stack are
relatively simple, but complications can arise with the calculations
for common or multiple stacks. These configurations sometimes
require special monitoring and apportioning methodologies, as
described in proposed Sec. 75.82. The provisions in Sec. 75.82
mirror, when appropriate, existing Part 75 provisions for monitoring
SO2 and NOX mass emissions from similar units
and groups of units.
Proposed Sec. 75.83 of Subpart I would establish the
requirement to calculate mercury mass emissions and heat input rate
in accordance with Appendix F of Part 75. For a detailed discussion
of these calculations, see section II.C.12 of this appendix.
Finally, proposed Sec. 75.84 of Subpart I sets forth the
general recordkeeping and reporting requirements associated with
mercury mass emission monitoring. For the most part, proposed Sec.
75.84 refers to other sections of Part 75, where the specific
recordkeeping and reporting requirements are found, although note
that a few provisions in Sec. 75.84 are unique and appear only in
that section.
B. Types of Mercury Monitoring Systems
1. Mercury CEMS
Today's proposed rule would expand the definition of
``continuous emission monitoring system or CEMS'' to include a ``Hg
concentration monitoring system'' and a ``Hg-diluent monitoring
system''. A mercury concentration monitoring system would consist of
a mercury pollutant concentration monitor and an automated data
acquisition and handling system (DAHS), and would provide a
permanent, continuous record of mercury emissions in units of
micrograms per dry standard cubic meter ([mu]g/dscm).
A mercury-diluent monitoring system would consist of a mercury
pollutant concentration monitor, a diluent gas (CO2 or
O2) monitor, and an automated DAHS. The monitoring system
would provide a permanent, continuous record of: Mercury
concentration in units of micrograms per dry standard cubic meter
([mu]g/dscm); diluent gas concentration (in percent O2 or
CO2); and mercury emission rate in units of pounds per
trillion British thermal units (lb/10\12\ Btu).
2. Sorbent Trap Systems
Today's proposed rule would also add a new definition to Sec.
72.2, i.e., the definition of a ``sorbent trap monitoring system''.
As set forth in the proposed definition in Sec. 72.2, a sorbent
trap monitoring system would consist of a probe, a pair of sorbent
traps (each containing a reagent such as iodinized carbon (IC)), a
heated umbilical line, moisture removal components, an air-tight
sample pump, a dry gas meter, and an automated data acquisition and
handling system (DAHS). The monitoring system would sample the stack
gas at a rate proportional to the stack gas volumetric flow rate.
The sampling would be done as a batch process, with the sorbent
traps being used for a data collection period ranging from hours to
weeks, depending upon the mercury concentration in the stack. Using
the sample volume measured by the dry gas meter during the data
collection period and the results of laboratory analysis of the
mercury captured in the sorbent traps, the mercury concentration in
the stack gas would be determined in units of micrograms per dry
standard cubic meter ([mu]g/dscm). Mercury mass emissions for each
hour in the sampling period would then be calculated using the
higher of the two average mercury concentrations obtained with the
paired sorbent traps for that period in conjunction with
contemporaneous measurements of the stack gas flow rate.
3. Use of Mercury CEMS and Sorbent Trap Systems
In today's proposed rule, EPA solicits comment on two
alternative approaches concerning the use of Hg CEMS and sorbent
trap monitoring systems in a Hg mass emissions trading program.
Proposed rule language for both alternatives is provided. The two
alternatives are as follows:
Alternative 1: Under this approach, EPA would allow the use of
sorbent trap systems for a subset of the affected units. The use of
sorbent traps would be limited to low-emitting units, having
estimated 3-year average Hg emissions of 144 ounces (9 lb) or less,
for the same three calendar years used to allocate the Hg
allowances. The threshold value of 9 lb per year is based on 1999
data gathered by EPA under an information collection request (ICR)
that appeared in the Federal Register on April 9, 1998. Based solely
on the 1999 ICR data, 228 of the 1120 coal-fired electrical
generating units in the database (i.e., 20 percent of the units),
representing 1 percent of the 48 tons of estimated nationwide
emissions, would qualify to use sorbent trap monitoring systems.
This approach is consistent with the way that EPA has
implemented the Acid Rain and NOX Budget Programs. In
both of these trading programs, the use of CEMS has been required
with few exceptions. Alternatives to CEMS have only been allowed
where either: (1) The emissions contributed by a particular category
of affected sources are at a very low level in comparison to the
emissions ``cap'' for the program (for example, oil and gas-fired
units may use the procedures in Appendix D of Part 75 for
SO2 mass emissions accounting, and oil and gas-fired
peaking units may use Appendix E for NOX emissions
accounting); or (2) an alternative monitoring system has been
demonstrated, according to the criteria in Subpart E of Part 75, to
be capable of generating data that has the same precision,
reliability, accuracy, and timeliness as a CEMS.
This general approach to emissions monitoring has worked well in
the Acid Rain and NOX Budget Trading Programs. All
required CEMS must undergo rigorous initial certification testing
and periodic quality-assurance testing, and must conform to Part 75
performance specifications. Emissions data from the monitoring
systems are reduced in a consistent manner that represent real-time
conditions. A standard set of data validation rules and substitute
data procedures apply to all of the CEMS. These stringent
requirements provide an accurate accounting of the mass emissions
from each affected unit and ensure a ``level playing field'' among
the regulated sources. This in turn inspires confidence among the
trading program participants in the integrity of the commodity being
traded (i.e., the emission allowances).
Alternative 1 restricts the use of sorbent trap monitoring
systems for the same reason that Part 75 restricts the use of
Appendices D and E for SO2 and NOX emissions
accounting, i.e., because the methodology represents a departure
from traditional CEMS technology. Nevertheless, in light of recent
field studies which have indicated that
[[Page 12417]]
sorbent traps are capable of providing accurate measurements of
mercury concentration that compare favorably to measurements made
with mercury CEMS (Docket 2002-0056, Items 0023 through 0027), EPA
is taking comment on the following alternative Hg emission
thresholds, below which the sorbent trap systems could be used: 29
lb/year, 46 lb/year, and 76 lb/year. Based on the 1999 ICR data,
these thresholds would represent, respectively, 5, 10, and 20
percent, respectively, of the estimated nationwide emissions, and
would allow 39, 50, and 65 percent, respectively, of the affected
units to use the sorbent trap systems.
Alternative 2: The EPA is also proposing a second continuous Hg
monitoring alternative whereby any source could use either CEMS or
sorbent traps, on the condition that quarterly relative accuracy
testing of each sorbent trap system is performed. A full 9-run RATA
would be required annually and a 3-run relative accuracy audit (RAA)
would be required in each of the other quarters of the year in which
the unit operates for at least 168 hours. For sources with annual Hg
emissions below the specified threshold value, the QA requirements
for sorbent trap monitoring systems would be less, with only an
annual RATA being required.
The EPA believes that in order to extend the use of sorbent trap
systems to the units that potentially account for 80 percent (or
more) of the Hg emissions in the budget for an emissions trading
program, an additional, substantive quarterly QA test should be
required. This is consistent with the QA requirements of Parts 60
and 75, for monitors that are used for compliance determination.
Both Part 60 and Part 75 require at least one such QA test to be
performed each quarter. Appendix F of Part 60 requires affected
facilities to perform a RATA in one calendar quarter of the year and
to perform either a cylinder gas audit (CGA) or a RAA in the other
three quarters. Under Appendix B of Part 75, quarterly linearity
checks are required, in addition to semiannual or annual RATA.
Because sorbent trap systems cannot be calibrated with cylinder
gases, linearity checks and CGA are not feasible. Therefore, a RATA
would be required in one quarter and an RAA in the other three
quarters. However, note that the Agency is willing to consider
replacing the RAA requirement with another type of substantive
quarterly QA test, if commenters who favor the use of sorbent trap
systems are aware of, and can provide details of, any such test or
procedure.
C. Adapting Part 75 Monitoring to a Mercury Trading Program
Today's proposed rule would amend the text and appendices of
Part 75 to set forth requirements for the continuous monitoring and
reporting of mercury mass emissions under a trading program that
adopts Subpart I.
The proposed revisions include a number of changes that EPA
believes would facilitate the implementation of such a program.
These include, but are not limited to, special provisions for
measuring mercury mass emissions with sorbent trap monitoring
systems, quality assurance and quality control requirements for
mercury CEMS and sorbent traps, missing data procedures for both
mercury CEMS and sorbent trap systems, determination of monitor
availability, recordkeeping and reporting provisions, and
mathematical equations for quantifying mercury mass emissions.
The majority of the proposed changes are substantive, and are
patterned after requirements already established for SO2
and NOX monitors. EPA believes that this would greatly
assist the affected sources in becoming familiar with the new
requirements and would maintain a consistency between the new rule
requirements and those already established by Part 75. The proposed
revisions would require mercury emissions data to be reported to EPA
in electronic quarterly reports, in a format similar to the one
currently used for SO2 and NOX emissions
reporting.
1. Applicability
Today's proposed rule would add paragraph (d) to Sec. 75.2,
indicating that the mercury monitoring provisions of Part 75 would
apply to sources subject to a State or Federal mercury mass emission
reduction program only to the extent that Part 75 monitoring is
adopted by such a program.
2. General Operating Requirements for Mercury Monitoring Systems
EPA proposes to amend Sec. 75.10 to include general operating
requirements for mercury CEMS (i.e., mercury concentration
monitoring systems and mercury-diluent monitoring systems). These
revisions would require all data collected by the mercury CEMS to be
reduced to hourly averages, in the same manner as is done for
SO2, NOX, CO2 and flow rate
monitors. Mercury CEMS would also have the same minimum data capture
requirements as other Part 75 CEMS to validate the hourly averages.
3. Special Operating Procedures for Sorbent Trap Monitoring Systems
EPA proposes to add text to Sec. 75.15 (previously reserved),
to set forth special provisions for measuring mercury mass emissions
with sorbent traps. For each monitoring system, the use of paired
sorbent traps would be required. The use of redundant backup systems
would be allowed, provided that each backup system uses paired
sorbent traps. A stack flow monitor and a moisture monitoring system
(or approved moisture constant) would be used in conjunction with
the sorbent trap system to quantify mercury mass emissions.
Each sorbent trap monitoring system would be installed and
operated in accordance with EPA Method 324. This method specifies
the minimum quality assurance and quality control procedures
necessary to ensure proper operation of the system. Mercury sampling
would be proportional to the stack gas volumetric flow rate. In
section 6.5.2.1 of Appendix A to Part 75, there is a standardized
procedure for dividing the operating range of the affected unit into
three load levels, i.e., low, mid, and high, and for identifying
which of these load levels is normal. For the purposes of applying
Method 324, an intermediate sampling rate of 0.3 to 0.5 liters per
minute through each sorbent trap would be used when the unit is
operating at the normal load level, whether low, mid, or high. The
sampling rate would then be increased or decreased, as appropriate,
by 0.1 liters/min when the unit operates at the other two load
levels. EPA solicits comment on the appropriateness of this sample
rate adjustment procedure.
After each sample collection period (the length of which would
depend upon the expected mercury concentration in the stack gas),
the mass of mercury adsorbed in the sorbent trap would be determined
using Method 324. For each sorbent trap, the average mercury
concentration ([mu]g/dscm) for the collection period would be
calculated by dividing the total mercury mass by the total volume of
dry gas metered. For each pair of sorbent traps, the higher of the
two average Hg concentrations would be used for reporting purposes.
Finally, the mercury mass emissions for each hour of the collection
period would be determined using the average mercury concentration
in conjunction with the hourly flow rates recorded by the stack flow
monitor.
All valid data from the primary sorbent trap monitoring system
would be required to be reported in the electronic quarterly report
under Sec. 75.84(f). When the primary monitoring system is non-
operational or for hours in which data from that system are invalid
(as determined using the quality control procedures in section 9.0
of Method 324), the owner or operator would have the option of
reporting valid mercury concentration data from a certified
redundant backup monitoring system or from the Ontario Hydro
reference method. However, if for a particular hour no quality-
assured mercury concentration data are available, the owner or
operator would report the appropriate substitute data values, in
accordance with proposed Sec. 75.39.
4. Certification and Recertification of Mercury Monitoring Systems
Proposed revisions to Sec. 75.20 would specify the required
initial certification tests for mercury CEMS and sorbent trap
monitoring systems. The mercury concentration and mercury-diluent
CEMS would be required to undergo the same full battery of
certification tests that is required for SO2 and
NOX monitoring systems (i.e., 7-day calibration error
tests, linearity checks, cycle time tests, and relative accuracy
test audits (RATAs)). In addition, a 3-point check of the converter,
using HgCl2 standards, as described in sections 8.3 and
13.1 of proposed Performance Specification 12A, would be required.
For sorbent trap monitoring systems, only a RATA would be required
for initial certification, since the 7-day calibration error test,
linearity check and cycle time test, all of which require
calibration gas injection, cannot be performed on a sorbent trap
system. Proposed revisions to Sec. Sec. 75.21 and 75.22 would
require the Ontario Hydro method to be used as the mercury
concentration reference method for relative accuracy testing. Under
the proposed revisions to Sec. 75.20(b), all three types of mercury
monitoring systems would be subject to the
[[Page 12418]]
same recertification requirements as the other Part 75 monitoring
systems.
5. Bias Adjustment of Mercury Emissions Data
Today's proposed rule would amend Sec. 75.24 to require mercury
emissions data to be adjusted for bias in the same manner as is done
for SO2, NOX, and flow rate data. If the bias
test performed on the relative accuracy data indicates that a
mercury-diluent monitoring system, a mercury concentration
monitoring system, or a sorbent trap monitoring system is biased low
with respect to the reference method, the owner or operator would be
required to either: (1) Adjust the monitoring system to eliminate
the cause of the bias and perform another RATA to verify that the
bias has been eliminated; or (2) calculate a bias adjustment factor
(BAF) and apply it to the subsequent mercury emissions data recorded
by the monitoring system.
6. Missing Data Procedures for Mercury Monitoring Systems
For mercury concentration and mercury-diluent CEMS, proposed
revisions to Sec. 75.31 would require the same initial missing data
procedures that are used for SO2 monitors to be applied
until 720 hours of quality-assured mercury concentration or mercury
emission rate data have been collected, following initial
certification of the CEMS. That is, the hourly values of mercury
concentration or mercury emission rate recorded immediately before
and after the missing data event would be averaged and applied to
each hour of the missing data period.
EPA proposes to amend Sec. 75.32 to require the percent monitor
data availability (PMA) to be calculated and reported after 720
hours of quality-assured mercury concentration or mercury emission
rate data have been collected following initial certification. At
that point, the owner or operator would switch from using the
initial missing data procedures to the proposed standard missing
data procedures in Sec. 75.38. The proposed standard missing data
procedures for mercury CEMS are modeled after the familiar
SO2 missing data algorithms in Sec. 75.33(b). EPA
considered using the load-based NOX missing data routines
in Sec. 75.33(c) as the model for mercury, but this approach is not
being proposed, in the absence of any data indicating that vapor
phase mercury emissions are load-dependent. The Agency solicits
comments on the proposed missing data approach.
For a unit equipped with a flue gas desulfurization (FGD) system
that meaningfully reduces the concentration of mercury emitted to
the atmosphere, or for a unit equipped with add-on mercury emission
controls, the initial and standard mercury missing data procedures
would apply only when the FGD or add-on controls are documented to
be operating properly, in accordance with Sec. 75.58(b)(3). A
certification statement from the designated representative verifying
proper operation of the emission controls during the missing data
periods would be required in each electronic quarterly report. For
any hour in which the FGD or add-on controls are not operating
properly, the maximum potential mercury concentration (MPC) or the
maximum potential mercury emission rate (MER) would be the required
substitute data value.
Also for units equipped with FGD systems or add-on mercury
emission controls, proposed Sec. 75.38 would allow the owner or
operator to petition to use the maximum controlled mercury
concentration or emission rate in the 720-hour missing data lookback
(in lieu of the maximum recorded value) when the PMA is less than
90.0 percent.
In proposed Sec. 75.39, EPA would add initial and standard
missing data procedures for sorbent trap monitoring systems. Once a
sorbent trap monitoring system has been certified, missing data
would be substituted whenever a gas sample is not extracted from the
stack, or when the results of the mercury analyses representing a
particular period of unit operation are missing or invalid. In the
latter case, the missing data period would begin when the sorbent
traps for which the mercury analyses are missing or invalid were put
into service and would end when valid mercury concentration data are
first obtained with another pair of sorbent traps.
The initial missing data procedures would be applied from the
hour of certification until 720 quality-assured hours of data have
been collected with the sorbent traps. The initial missing data
algorithm would require the owner or operator to average the mercury
concentrations from all valid sorbent trap analyses to date,
including data from the initial certification test runs, and to fill
in this average concentration for each hour of the missing data
period.
Once 720 quality-assured hours of mercury concentration data are
collected, the owner or operator would begin reporting the percent
monitor data availability (PMA) and would begin using the standard
missing data algorithms. The standard missing data procedures for
sorbent trap systems would follow a ``tiered'' approach, based on
the PMA. For example, at high PMA (= 95.0%), the
substitute data value would be the average mercury concentration
obtained from all valid sorbent trap analyses in the previous 12
months. At lower PMA values, the substitute data values would become
increasingly conservative, until finally, if the PMA drops below
80.0%, the maximum potential mercury concentration (MPC) would be
reported.
Similar to the proposed provision for mercury CEMS, if a unit
that uses sorbent traps is equipped with an FGD system or add-on
mercury emission controls, the initial and standard missing data
procedures could only be applied for hours in which proper operation
of the emission controls was documented. In the absence of such
documentation, the mercury MPC would be reported.
7. Monitoring Plan Information for Mercury Monitoring Systems
EPA is proposing to amend Sec. 75.53 to require the owner or
operator to provide essential information for each mercury
monitoring system in the monitoring plan for the affected unit. The
information to be provided would include the identification and
description of each monitoring system component (e.g., the analyzer,
DAHS, etc.). For each mercury CEMS, the maximum potential mercury
concentration, the maximum expected concentration (if applicable),
the maximum potential mercury emission rate (if applicable), span
value(s), full-scale range(s), daily calibration units of measure,
and other specified parameters would be defined in the monitoring
plan. Appropriate formulas for calculating mercury emission rate (if
applicable) and mercury mass emissions would also be included in the
plan.
8. Recordkeeping and Reporting
Today's proposed rule would amend Sec. 75.57 to add general
recordkeeping provisions for mercury monitoring systems and the
auxiliary monitors (flow, moisture, and O2 or
CO2) needed to quantify mercury mass emissions and heat
input. The owner or operator would be required to record data from
these monitoring systems on an hourly average basis, and to report
it electronically on a quarterly basis.
For mercury concentration CEMS, the owner or operator would
record, for each operating hour, information such as the component-
system identification codes, the date and hour, the average mercury
concentration, the bias-adjusted mercury concentration (if a bias
adjustment factor (BAF) is required), the method of determination
codes for the mercury concentration, flow rate and moisture data,
and the percent monitor data availability for each monitored
parameter.
For mercury-diluent systems, the owner or operator would record
hourly information such as the monitoring system and component
identification codes, the date and hour, the average mercury and
diluent gas concentrations, the average stack gas flow rate and
moisture content, the average mercury emission rate, the bias-
adjusted mercury emission rate (if a BAF is required), the percent
monitor data availability for mercury emission rate, flow rate and
moisture, the method of determination codes for the mercury emission
rate, flow rate, percent moisture and diluent gas concentration, the
identification codes for emissions formulas used to calculate the
mercury emission rate and mercury mass emissions, and the F-factor
used to convert mercury concentrations into emission rates.
For sorbent trap monitoring systems, the owner or operator would
record hourly information such as component-system identification
codes, date and hour, average mercury concentration, bias-adjusted
mercury concentration (if a BAF is required), the method of
determination codes and percent monitor data availability for
mercury concentration, flow rate and moisture, the average flow rate
of the stack gas sample through each sorbent trap, and the unit or
stack operating load level.
Today's proposed rule would also amend Sec. 75.59, the quality-
assurance and quality-control (QA/QC) recordkeeping section, to
require that records be kept of all QA tests of mercury monitoring
systems (e.g., calibrations, linearity checks, and RATAs). The
proposed revisions to Sec. 75.59(a)(7) would further require the
following data elements to be recorded for each RATA run using the
Ontario Hydro reference method:
[[Page 12419]]
the percentage of CO2 and O2 in the stack gas,
the moisture content of the stack gas, the average stack
temperature, the dry gas volume metered, the percent isokinetic, the
particle-bound mercury collected by the filter, blank, and probe
rinse, the oxidized mercury collected by the KCl impingers, the
elemental mercury collected in the HNO3 /
H2O2 impinger and in the KMnO4 /
H2SO4 impingers, the total mercury including
particle-bound mercury, and the total mercury excluding particle-
bound mercury.
Finally, for each sorbent trap monitoring system, the owner or
operator would be required to record information such as the ID
number of the monitoring system in which the paired sorbent traps
are used to collect mercury, the unique ID number of each sorbent
trap, the beginning and ending dates and hours of the data
collection period, the two average mercury concentrations for the
data collection period, and information documenting the results of
the required Method 324 leak checks, quality control procedures, and
laboratory analyses of the mercury collected by the sorbent traps.
9. Span and Range Values for Mercury Monitors
EPA proposes to amend section 2 of Appendix A to Part 75, by
adding a new sub-section, 2.1.7, to address span and range issues
for mercury CEMS.
Since the mercury content of different types of coal is
variable, the maximum potential mercury concentration (MPC) depends
upon which type of coal is combusted in the unit. For the initial
MPC determination, today's proposed rule would provide the owner or
operator with three options: (1) To use a fuel-specific default
value of 9 [mu]g/dscm for bituminous coal, 10 [mu]g/dscm for sub-
bituminous coal, 16 [mu]g/dscm for lignite, and 1 [mu]g/dscm for
waste coal (if different coals are blended, the highest MPC value
for any fuel in the blend would be used); (2) to determine the MPC
based on the results of site-specific emission testing using the
Ontario Hydro method (at least three 2-hour runs at normal load).
This option would be allowed only if the unit does not have add-on
mercury emission controls or a flue gas desulfurization system, or
if the testing is done upstream of these control devices; or (3) to
base the MPC on 720 or more hours of historical CEMS data, if the
unit has a mercury CEMS that has been tested for relative accuracy
against the Ontario Hydro method and has met a relative accuracy
specification of 20.0% or less.
The terms ``span'' and ``range'' do not apply to sorbent trap
monitoring systems; however, note that an MPC determination would be
required for these monitoring systems for the purposes of missing
data substitution. Also, for units using mercury-diluent monitoring
systems, calculation of the maximum potential mercury emission rate
(MER), in units of lb/1012 Btu, would be required for
purposes of missing data substitution. To determine the MER, the
owner or operator would use the appropriate emission rate equation
from section 9 of appendix F, substituting into the equation the MPC
value, the minimum expected CO2 concentration or maximum
expected O2 concentration during normal operation
(excluding unit startup, shutdown, and process upsets), the expected
stack gas moisture content (if applicable), and the appropriate F-
factor.
For units with FGD systems (including fluidized bed units that
use limestone injection) and for units equipped with add-on mercury
emission controls (e.g., carbon injection), a determination of the
maximum expected mercury concentration (MEC) during normal, stable
operation of the unit and emission controls would be required. To
calculate the MEC, the previously-determined MPC value would be
substituted into Equation A-2 in section 2.1.1.2 of Part 75,
Appendix A. In applying Equation A-2, units using add-on mercury
emission controls such as carbon injection would use a mercury
removal efficiency obtained from design engineering calculations.
For units with FGD systems, the owner or operator would use the best
available estimate of the mercury removal efficiency of the FGD.
The span and range value(s) for each mercury monitor would be
calculated as follows. A ``high'' span value would be determined by
rounding the MPC value upward to the next highest multiple of 10
[mu]g/dscm. If the affected unit is equipped with an FGD system or
add-on mercury emission controls, and if the MEC value is less than
20 percent of the high span value and the high span value is 20
[mu]g/dscm or greater, the owner or operator would be required to
define a second, low span value of 10 [mu]g/dscm.
If the owner or operator determines that only a high span value
is required, the full-scale range of the mercury analyzer would be
set greater than or equal to the span value. If two span values are
required, the owner or operator could either use two separate (high
and low) measurement scales, or quality-assure two segments of a
single measurement scale.
The owner or operator would be required to make a periodic
evaluation (at least annually of the MPC, MEC, span, and range
values for each mercury monitor, to make any necessary span and
range adjustments and corresponding monitoring plan updates, and to
keep the results of the most recent span and range evaluation on-
site, in a format suitable for inspection. Span and range
adjustments might be required, for example, as a result of changes
in the fuel supply, changes in the manner of operation of the unit,
or with installation or removal of emission controls. Each required
span or range adjustment would have to be made no later than 45 days
after the end of the quarter in which the need to adjust the span or
range is identified, except that up to 90 days after the end of that
quarter would be allowed if the calibration gases currently being
used for daily calibration error tests and linearity checks are
unsuitable for use with the new span value.
If a full-scale range exceedance occurs during a quarter and is
not caused by a monitor out-of-control period, for monitors with a
single measurement scale, the owner or operator would report 200
percent of the full-scale range as the hourly mercury concentration
until the readings come back on-scale. If over-scaling occurs,
appropriate adjustments to the MPC, span, and range would be
required to prevent future full-scale exceedances. For units with
two separate measurement scales, no further action would be required
if the low range is exceeded and the high range is available.
However, if the high range is not able to provide quality assured
data at any time during the continuation of a low-scale exceedance,
then the MPC would be reported until the readings return to the low
range or until the high range is able to provide quality-assured
data.
Whenever changes are made to the MPC, MEC, full-scale range, or
span value of the mercury monitor, the new settings, MPC or MEC, and
calculations of the adjusted span value(s) would be represented in
an updated monitoring plan. The monitoring plan update would be made
in the quarter in which the changes become effective. Whenever a
span adjustment is made, the owner or operator would be required to
ensure that the new span value is reflected in the records for the
daily calibration error tests and quarterly linearity checks. For
mercury monitors, a diagnostic linearity check would be required
when a span value is changed, using calibration gases consistent
with the new span value.
10. Performance Specifications for Mercury Monitoring Systems
Today's proposed rule would amend section 3 of Appendix A to
Part 75 by setting forth performance specifications for the initial
certification of mercury monitoring systems. In particular,
specifications for 7-day calibration error tests, linearity checks,
cycle time tests, converter checks, and RATAs are proposed. A bias
test of each mercury monitoring system would also be required and a
bias adjustment factor would have to be applied to the subsequent
data generated by any monitoring system found to have a low bias.
For the 7-day calibration error tests, linearity checks and cycle
time tests, proposed section 5.1.9 of Appendix A would require the
use of elemental mercury calibration gas standards. For converter
checks, the use of HgCl2 standards would be required.
For each day of the 7-day calibration error test, the monitor
would not be permitted to deviate from the zero or upscale reference
calibration gas by more than 5.0 percent of the span value. As an
alternative, if the span value is 10 [mu]g/dscm (i.e., the lowest
allowable span for a mercury monitor), the calibration error test
results would also be acceptable if the absolute value of the
difference between the monitor response value and the reference
value (i.e., [bond] R-A [bond] in Equation A-5 of Appendix A), is
less than or equal to 1.0 [mu]g/dscm.
Linearity checks would be required for all mercury CEMS. For
dual-span units, the test would be required on both measurement
scales (or at two distinct segments of a single measurement scale).
The maximum allowable linearity error at any gas injection level
(low, mid, or high) would be 10.0% of the reference gas tag value.
Alternatively, the results would be acceptable if the absolute
difference between the reference gas value and the average analyzer
response (i.e., [bond] R-
[[Page 12420]]
A [bond] in Equation A-4 of Appendix A) does not exceed 1.0 [mu]g/
dscm.
A cycle time test of each mercury CEMS would be required. For
this test, however, EPA is not proposing any new performance
specification. The pass/fail criterion for the cycle time test of a
mercury concentration or mercury-diluent monitoring system would be
the same as for a Part 75 gas monitoring system (i.e., 15 minutes).
A 3-point check of the converter would be required for each
mercury monitor, using HgCl2 standards. The test would be
performed as described in section 8.3 of proposed Performance
Specification 12A (PS-12A) and at each gas level, the monitor would
have to meet the 5.0% of span specification in section 13.1 of
proposed PS-12A.
Relative accuracy testing of all three types of mercury
monitoring systems, i.e., mercury concentration CEMS, mercury-
diluent CEMS, and sorbent trap monitoring systems, would be
required. The proposed relative accuracy specification for these
monitoring systems is 20.0 percent. Alternatively, for low-emitting
sources, where the average of the reference method measurements of
mercury concentration during the relative accuracy test audit is
less than 5.0 [mu]g/dscm, or where the average mercury emission rate
measured by the reference method is less than 5.5 lb/10
12 Btu during the RATA, the test results would be
acceptable if the difference between the mean value of the monitor
measurements and the reference method mean value does not exceed 1.0
[mu]g/dscm or 1.1 lb/1012 Btu (as applicable), in cases
where the relative accuracy specification of 20.0 percent is not
achieved. Also, for low-emitting sources that pass the RATA but fail
the bias test, proposed revisions to section 7.6.5(b) of Appendix A
would allow the use of a default BAF ``cap'' value of 1.250, if the
calculated BAF exceeds 1.250.
Finally, EPA proposes to revise sections 6.5(a) and 6.5.7 of
Appendix A to require that the RATAs of mercury monitoring systems
be performed while the unit is combusting coal. The minimum
acceptable time for each test run using the Ontario Hydro reference
method would be 2 hours. For sorbent trap monitoring systems, a new
pair of sorbent traps would be required to be used for each RATA
run.
11. On-Going Quality-Assurance of Mercury Monitoring Systems
Today's proposed rule would revise sections 1 and 2 of Appendix
B to Part 75 to add specific quality-assurance and quality control
requirements for mercury monitoring systems.
First, for sorbent trap monitoring systems, EPA proposes to add
a new section 1.5 to Appendix B to set forth the minimum acceptable
elements of a QA/QC program for these monitoring systems. As
previously noted, sorbent traps differ from traditional CEMS, in
that daily calibration checks and quarterly linearity checks cannot
be performed on these systems. Thus, the on-going quality of the
data from a sorbent trap system depends vitally on the manner of
operation of the system and the care with which the sorbent traps
are handled. In view of this, EPA is proposing that the QA plan for
sorbent trap systems include the following elements: (1) An
explanation of the procedures for inscribing and tracking a unique
identification number on each sorbent trap; (2) an explanation of
the leak check procedures used and other QA procedures used to
ensure system integrity and data quality (e.g., dry gas meter
calibrations, verification of moisture removal, verifying air-tight
pump operation; (3) the data acceptance and quality-control criteria
in section 9.0 of Method 324; (4) documentation of the procedures
used to transport and analyze the sorbent traps; (5) documentation
that the laboratory performing the sorbent trap analyses is
certified by the International Organization for Standardization
(ISO) to have a proficiency that meets the requirements of ISO 9000;
and (6) the rationale used to justify the minimum acceptable data
collection time for each sorbent trap. Proposed section 1.5 also
requires records to be kept of the procedures and details associated
with the RATA testing of the sorbent trap monitoring systems.
For mercury CEMS, revised section 2.1.1 of Appendix B would
require the same daily calibration error tests to be performed on
mercury monitors as are done on other Part 75 monitors. Each mercury
monitor would be required to meet a daily calibration error
specification of either 7.5 percent of the span value or an absolute
difference of <1.5 [mu]g/dscm between the reference gas and the
analyzer response (whichever is less restrictive).
A monthly 3-point check of the converter would be required for
each mercury monitor, using HgCl2 standards (see proposed
section 2.6 and proposed revisions to Figure 1 in Appendix B). This
test would be done according to section 8.3 of proposed Performance
Specification 12A and the monitor would be required to meet an error
specification of 5.0% of span at each gas level. The test would only
be required for months in which the unit operates for 168 hours or
more.
Revised section 2.2.1 of Appendix A would require quarterly
linearity checks to be performed on each mercury monitor. Elemental
mercury standards would be used for these tests. Revised sections
2.3.1.2 and 2.3.1.3 of Appendix B would require an annual RATA and
bias test of each mercury concentration monitoring system, each
mercury-diluent monitoring system, and each sorbent trap monitoring
system. The RATAs would be performed at the normal load level. If
any monitoring system fails the bias test, the owner or operator
would calculate a bias adjustment factor and apply it to the
subsequent hourly data recorded by that system.
Regarding sorbent trap monitoring systems, note that two
versions of the amended regulatory language and Figures in section 2
of Part 75, Appendix B are presented, corresponding to Alternatives
1 and 2, previously discussed in section II.B.3
of this appendix. Under Alternative 1, only an annual RATA
would be required in addition to the Method 324 QA/QC procedures.
Under Alternative 2, the annual RATA would be required for
all sorbent trap monitoring systems, and additional quarterly 3-run
relative accuracy audits (RAAs) would be required if the unit's
average Hg emissions exceed 9 lbs/yr for the same calendar years
used to allocate the Hg allowances. The RAAs would be required in
every QA operating quarter (i.e., quarters with at least 168 unit or
stack operating hours) following initial certification, except for
quarters in which a full RATA is performed.
EPA believes that the proposed performance specifications for
the initial certification tests and on-going quality-assurance tests
are reasonable and achievable, in view of the results of recent
field evaluations of mercury CEMS and sorbent traps (Docket 2002-
0056, Items 0023 through 0027). The Agency solicits
comment on the appropriateness of the proposed specifications.
12. Calculation of Mercury Mass Emissions
Today's proposed rule would add section 9 to Appendix F of Part
75. Proposed section 9 would provide the necessary equations for
calculating the hourly, quarterly, and year-to-date mercury mass
emissions. Three new equations, F-28, F-29, and F-30, would be added
to Appendix F.
Equation F-28 would be used to determine the hourly mercury mass
emissions (in ounces, rounded to one decimal place), when the
mercury concentration (in [mu]g/dscm)is measured with a mercury
concentration CEMS or with a sorbent trap system. For units using
mercury-diluent CEMS, proposed section 9.1.2 of Appendix F would
require the measured hourly emission rate (in lb/1012
Btu) to be determined using a modified version of Equation F-5 or F-
6 in Appendix F of Part 75 (when the diluent gas is measured on a
dry basis) or a modified version of Equation 19-5 or 19-9 from EPA
Method 19 in Appendix B of Part 60 (when the diluent gas is measured
on a wet basis). Then, the mercury emission rate would be
substituted into proposed Equation F-29 to determine the hourly
mercury mass emissions (in ounces, rounded to one decimal place).
The quarterly and year-to-date mercury mass emissions (in ounces)
would be calculated using proposed Equation F-30.
Finally, where heat input monitoring is required, proposed
section 9.3 of Appendix F would instruct the owner or operator to
follow the heat input rate apportionment and summation procedures in
sections 5.3, 5.6 and 5.7 of Appendix F.
Appendix B to the Preamble--Units Allocations
Unit level allocations used to develop the phase II state
emissions budgets are presented below. For further discussion of the
methodology used to develop these units level allocations see the
memorandum entitled ``Allocation Adjustment Factors for the Proposed
Mercury Trading Rulemaking'' in the docket. The same methodology
described in the docket memo and used below would be used to develop
the 2010 unit level allocations and state budgets.
[[Page 12421]]
----------------------------------------------------------------------------------------------------------------
Phase II Hg
State Facility name Plant ID Unit ID allocation
(ounces)
----------------------------------------------------------------------------------------------------------------
AK...................... Healy...................... 6288 2 65
AL...................... Gadsden.................... 7 2 60
AL...................... Gadsden.................... 7 1 73
AL...................... Charles R Lowman........... 56 1 112
AL...................... Widows Creek............... 50 1 132
AL...................... Widows Creek............... 50 4 135
AL...................... Widows Creek............... 50 5 144
AL...................... Gorgas..................... 8 7 145
AL...................... Widows Creek............... 50 3 151
AL...................... Widows Creek............... 50 2 156
AL...................... Widows Creek............... 50 6 162
AL...................... Gorgas..................... 8 6 166
AL...................... Barry...................... 3 1 185
AL...................... Barry...................... 3 2 193
AL...................... Colbert.................... 47 3 229
AL...................... Colbert.................... 47 4 231
AL...................... Colbert.................... 47 1 237
AL...................... Colbert.................... 47 2 239
AL...................... Gorgas..................... 8 9 241
AL...................... Gorgas..................... 8 8 244
AL...................... Charles R Lowman........... 56 3 316
AL...................... E C Gaston................. 26 4 321
AL...................... Charles R Lowman........... 56 2 327
AL...................... Barry...................... 3 3 331
AL...................... E C Gaston................. 26 1 349
AL...................... E C Gaston................. 26 2 356
AL...................... Greene County.............. 10 1 358
AL...................... Greene County.............. 10 2 363
AL...................... E C Gaston................. 26 3 369
AL...................... Barry...................... 3 4 508
AL...................... Colbert.................... 47 5 508
AL...................... Widows Creek............... 50 7 580
AL...................... Widows Creek............... 50 8 607
AL...................... Gorgas..................... 8 10 884
AL...................... Barry...................... 3 5 972
AL...................... E C Gaston................. 26 5 1022
AL...................... James H Miller Jr.......... 6002 1 1152
AL...................... James H Miller Jr.......... 6002 2 1155
AL...................... James H Miller Jr.......... 6002 3 1218
AL...................... James H Miller Jr.......... 6002 4 1249
AR...................... Flint Creek Power Plant.... 6138 1 925
AR...................... White Bluff................ 6009 2 1325
AR...................... Independence............... 6641 1 1342
AR...................... White Bluff................ 6009 1 1383
AR...................... Independence............... 6641 2 1485
AZ...................... Irvington.................. 126 4 150
AZ...................... Cholla..................... 113 1 213
AZ...................... Apache Station............. 160 2 350
AZ...................... Apache Station............. 160 3 355
AZ...................... Cholla..................... 113 3 505
AZ...................... Cholla..................... 113 2 521
AZ...................... Cholla..................... 113 4 680
AZ...................... Springerville.............. 8223 2 707
AZ...................... Springerville.............. 8223 1 720
AZ...................... Coronado Generating Station 6177 U2B 732
AZ...................... Coronado Generating Station 6177 U1B 741
AZ...................... Navajo Generating Station.. 4941 1 1145
AZ...................... Navajo Generating Station.. 4941 2 1220
AZ...................... Navajo Generating Station.. 4941 3 1223
CA...................... Rio Bravo Jasmin........... 10768 GEN1 59
CA...................... Port Of Stockton District 54238 STG 60
Energy Facility (Posdef).
CA...................... Rio Bravo Poso............. 10769 GEN1 60
CA...................... Mt. Poso Cogeneration Plant 54626 27805-89 64
CA...................... Stockton Cogen Company..... 10640 GEN1 108
CA...................... Ace Cogeneration Plant..... 10002 10002 161
CO...................... Arapahoe................... 465 2 61
CO...................... Cameo...................... 468 2 80
CO...................... Martin Drake............... 492 5 86
CO...................... Arapahoe................... 465 1 91
CO...................... Arapahoe................... 465 3 106
CO...................... Martin Drake............... 492 6 156
CO...................... Cherokee................... 469 1 160
[[Page 12422]]
CO...................... Nucla...................... 527 1 163
CO...................... Cherokee................... 469 2 176
CO...................... Arapahoe................... 465 4 202
CO...................... Cherokee................... 469 3 217
CO...................... Martin Drake............... 492 7 252
CO...................... Valmont.................... 477 5 257
CO...................... Hayden..................... 525 H1 336
CO...................... Ray D Nixon................ 8219 1 393
CO...................... Cherokee................... 469 4 431
CO...................... Hayden..................... 525 H2 454
CO...................... Rawhide Energy Station..... 6761 101 571
CO...................... Comanche (470)............. 470 1 586
CO...................... Comanche (470)............. 470 2 621
CO...................... Craig...................... 6021 C3 732
CO...................... Craig...................... 6021 C2 831
CO...................... Craig...................... 6021 C1 845
CO...................... Pawnee..................... 6248 1 1071
CT...................... AES Thames................. 10675 UNITA 131
CT...................... AES Thames................. 10675 UNITB 142
CT...................... Bridgeport Harbor Station.. 568 BHB3 454
DE...................... Indian River............... 594 1 87
DE...................... Indian River............... 594 2 94
DE...................... Edge Moor.................. 593 3 116
DE...................... Indian River............... 594 3 161
DE...................... Edge Moor.................. 593 4 188
DE...................... Indian River............... 594 4 290
FL...................... Scholz Electric Generating 642 1 39
Plant.
FL...................... Scholz Electric Generating 642 2 45
Plant.
FL...................... Crist Electric Generating 641 4 81
Plant.
FL...................... Crist Electric Generating 641 5 103
Plant.
FL...................... F J Gannon................. 646 GB01 127
FL...................... Cedar Bay Generating 10672 GEN 1B 129
Company L.P..
FL...................... Cedar Bay Generating 10672 GEN 1C 131
Company L.P..
FL...................... Cedar Bay Generating 10672 GEN 1A 132
Company L.P..
FL...................... F J Gannon................. 646 GB02 136
FL...................... Central Power And Lime, 10333 GEN 1 177
Inc..
FL...................... F J Gannon................. 646 GB03 186
FL...................... Northside.................. 667 1A 187
FL...................... F J Gannon................. 646 GB04 210
FL...................... F J Gannon................. 646 GB05 228
FL...................... Northside.................. 667 2A 231
FL...................... Lansing Smith.............. 643 1 231
FL...................... Polk....................... 7242 **1 237
FL...................... Lansing Smith.............. 643 2 282
FL...................... Deerhaven.................. 663 B2 287
FL...................... Indiantown Cogeneration 50976 GEN 1 292
Facility.
FL...................... Crist Electric Generating 641 6 320
Plant.
FL...................... F J Gannon................. 646 GB06 416
FL...................... Crystal River.............. 628 1 457
FL...................... Big Bend................... 645 BB03 477
FL...................... Big Bend................... 645 BB01 489
FL...................... C D McIntosh............... 676 3 534
FL...................... Big Bend................... 645 BB02 534
FL...................... Stanton Energy............. 564 1 583
FL...................... Stanton Energy............. 564 2 593
FL...................... Crystal River.............. 628 2 619
FL...................... Crist Electric Generating 641 7 638
Plant.
FL...................... Big Bend................... 645 BB04 651
FL...................... Seminole (136)............. 136 2 954
FL...................... Crystal River.............. 628 4 957
FL...................... St. Johns River Power...... 207 2 962
FL...................... Seminole (136)............. 136 1 968
FL...................... St. Johns River Power...... 207 1 1004
FL...................... Crystal River.............. 628 5 1076
GA...................... Arkwright.................. 699 1 17
GA...................... Arkwright.................. 699 2 18
GA...................... Mitchell................... 727 2 24
GA...................... Arkwright.................. 699 4 24
GA...................... Arkwright.................. 699 3 26
GA...................... Mitchell................... 727 1 29
GA...................... Kraft...................... 733 2 51
GA...................... Kraft...................... 733 1 55
[[Page 12423]]
GA...................... Yates...................... 728 Y3BR 75
GA...................... Yates...................... 728 Y1BR 87
GA...................... Yates...................... 728 Y2BR 94
GA...................... Mitchell................... 727 3 104
GA...................... Yates...................... 728 Y4BR 108
GA...................... Hammond.................... 708 1 110
GA...................... Yates...................... 728 Y5BR 117
GA...................... Kraft...................... 733 3 118
GA...................... Hammond.................... 708 2 118
GA...................... Hammond.................... 708 3 119
GA...................... McIntosh (6124)............ 6124 1 200
GA...................... Harllee Branch............. 709 1 254
GA...................... Jack McDonough............. 710 MB1 301
GA...................... Harllee Branch............. 709 2 309
GA...................... Yates...................... 728 Y7BR 322
GA...................... Yates...................... 728 Y6BR 333
GA...................... Jack McDonough............. 710 MB2 336
GA...................... Harllee Branch............. 709 3 499
GA...................... Harllee Branch............. 709 4 508
GA...................... Hammond.................... 708 4 511
GA...................... Bowen...................... 703 2BLR 859
GA...................... Bowen...................... 703 1BLR 879
GA...................... Wansley (6052)............. 6052 2 903
GA...................... Scherer.................... 6257 1 952
GA...................... Wansley (6052)............. 6052 1 965
GA...................... Scherer.................... 6257 2 1052
GA...................... Bowen...................... 703 3BLR 1073
GA...................... Bowen...................... 703 4BLR 1079
GA...................... Scherer.................... 6257 3 1284
GA...................... Scherer.................... 6257 4 1549
HI...................... Aes Hawaii, Inc............ 10673 B 147
HI...................... Aes Hawaii, Inc............ 10673 A 149
IA...................... Lansing.................... 1047 1 1
IA...................... Lansing.................... 1047 2 2
IA...................... Dubuque.................... 1046 6 2
IA...................... Earl F Wisdom.............. 1217 1 11
IA...................... Streeter Station........... 1131 7 14
IA...................... Pella...................... 1175 6 14
IA...................... Pella...................... 1175 7 15
IA...................... Sixth Street............... 1058 4 23
IA...................... Sixth Street............... 1058 3 29
IA...................... Ames....................... 1122 7 29
IA...................... Sixth Street............... 1058 2 32
IA...................... Lansing.................... 1047 3 35
I....................... Dubuque.................... 1046 5 38
IA...................... Sixth Street............... 1058 5 50
IA...................... Fair Station............... 1218 2 50
IA...................... Dubuque.................... 1046 1 55
IA...................... Sutherland................. 1077 1 64
IA...................... Sutherland................. 1077 2 64
IA...................... Council Bluffs............. 1082 1 81
IA...................... Prairie Creek.............. 1073 3 83
IA...................... Ames....................... 1122 8 101
IA...................... Council Bluffs............. 1082 2 128
IA...................... Muscatine.................. 1167 8 138
IA...................... Sutherland................. 1077 3 156
IA...................... Riverside (1081)........... 1081 9 169
IA...................... George Neal North.......... 1091 1 226
IA...................... Prairie Creek.............. 1073 4 229
IA...................... Milton L Kapp.............. 1048 2 274
IA...................... Muscatine.................. 1167 9 296
IA...................... Burlington (IA)............ 1104 1 333
IA...................... Lansing.................... 1047 4 376
IA...................... George Neal North.......... 1091 2 435
IA...................... George Neal North.......... 1091 3 847
IA...................... George Neal South.......... 7343 4 1076
IA...................... Louisa..................... 6664 101 1143
IA...................... Council Bluffs............. 1082 3 1236
IA...................... Ottumwa.................... 6254 1 1243
IL...................... Meredosia.................. 864 03 20
IL...................... Meredosia.................. 864 01 22
IL...................... Grand Tower................ 862 07 25
[[Page 12424]]
IL...................... Grand Tower................ 862 08 26
IL...................... Meredosia.................. 864 02 26
IL...................... Meredosia.................. 864 04 27
IL...................... Lakeside................... 964 7 31
IL...................... Marion..................... 976 2 32
IL...................... Lakeside................... 964 8 32
IL...................... Marion..................... 976 1 33
IL...................... Marion..................... 976 3 35
IL...................... Hutsonville................ 863 05 63
IL...................... Hutsonville................ 863 06 71
IL...................... Vermilion.................. 897 1 82
IL...................... Grand Tower................ 862 09 90
IL...................... Dallman.................... 963 32 96
IL...................... Dallman.................... 963 31 98
IL...................... Hennepin................... 892 1 101
IL...................... Wood River................. 898 4 106
IL...................... Vermilion.................. 897 2 112
IL...................... E D Edwards................ 856 1 130
IL...................... Waukegan................... 883 17 167
IL...................... Meredosia.................. 864 05 191
IL...................... Will County................ 884 2 210
IL...................... Will County................ 884 1 222
IL...................... Dallman.................... 963 33 259
IL...................... Crawford................... 867 7 268
IL...................... Marion..................... 976 4 270
IL...................... E D Edwards................ 856 2 299
IL...................... Hennepin................... 892 2 314
IL...................... Joliet 29.................. 384 71 324
IL...................... Coffeen.................... 861 01 332
IL...................... Wood River................. 898 5 334
IL...................... Joliet 29.................. 384 81 335
IL...................... Joppa Steam................ 887 4 354
IL...................... Joppa Steam................ 887 3 358
IL...................... Joppa Steam................ 887 6 362
IL...................... Joppa Steam................ 887 5 364
IL...................... Joppa Steam................ 887 1 366
IL...................... E D Edwards................ 856 3 366
IL...................... Joppa Steam................ 887 2 370
IL...................... Will County................ 884 3 378
IL...................... Crawford................... 867 8 382
IL...................... Joliet 29.................. 384 82 409
IL...................... Fisk....................... 886 19 410
IL...................... Joliet 29.................. 384 72 422
IL...................... Duck Creek................. 6016 1 440
IL...................... Joliet 9................... 874 5 441
IL...................... Havana..................... 891 9 479
IL...................... Waukegan................... 883 7 482
IL...................... Waukegan................... 883 8 529
IL...................... Powerton................... 879 61 530
IL...................... Powerton................... 879 52 535
IL...................... Powerton................... 879 51 536
IL...................... Powerton................... 879 62 545
IL...................... Will County................ 884 4 584
IL...................... Coffeen.................... 861 02 589
IL...................... Kincaid.................... 876 1 670
IL...................... Baldwin.................... 889 2 705
IL...................... Baldwin.................... 889 1 713
IL...................... Kincaid.................... 876 2 714
IL...................... Newton..................... 6017 2 772
IL...................... Baldwin.................... 889 3 819
IL...................... Newton..................... 6017 1 898
IN...................... Noblesville................ 1007 3 26
IN...................... Noblesville................ 1007 2 26
IN...................... Noblesville................ 1007 1 28
IN...................... Edwardsport................ 1004 8-1 40
IN...................... F B Culley Generating 1012 1 44
Station.
IN...................... Whitewater Valley.......... 1040 1 45
IN...................... Edwardsport................ 1004 7-2 45
IN...................... Edwardsport................ 1004 7-1 50
IN...................... Eagle Valley (H T 991 3 59
Pritchard).
IN...................... Eagle Valley (H T 991 5 61
Pritchard).
IN...................... Eagle Valley (H T 991 4 65
Pritchard).
[[Page 12425]]
IN...................... Dean H Mitchell............ 996 4 84
IN...................... Whitewater Valley.......... 1040 2 97
IN...................... Wabash River............... 1010 2 99
IN...................... Wabash River............... 1010 3 102
IN...................... Eagle Valley (H T 991 6 120
Pritchard).
IN...................... Wabash River............... 1010 5 122
IN...................... Harding Street Station (EW 990 60 125
Stout).
IN...................... Dean H Mitchell............ 996 5 133
IN...................... Wabash River............... 1010 4 134
IN...................... F B Culley Generating 1012 2 136
Station.
IN...................... Harding Street Station (EW 990 50 139
Stout).
IN...................... Dean H Mitchell............ 996 11 143
IN...................... R Gallagher................ 1008 1 146
IN...................... R Gallagher................ 1008 2 148
IN...................... R Gallagher................ 1008 4 153
IN...................... Tanners Creek.............. 988 U1 158
IN...................... Dean H Mitchell............ 996 6 159
IN...................... R Gallagher................ 1008 3 159
IN...................... Tanners Creek.............. 988 U2 164
IN...................... Frank E Ratts.............. 1043 1SG1 166
IN...................... Frank E Ratts.............. 1043 2SG1 169
IN...................... Wabash River............... 1010 1 174
IN...................... Tanners Creek.............. 988 U3 218
IN...................... Bailly..................... 995 7 224
IN...................... State Line Generating 981 3 288
Station (IN).
IN...................... A B Brown Generating 6137 1 302
Station.
IN...................... Clifty Creek............... 983 6 308
IN...................... Clifty Creek............... 983 4 309
IN...................... Clifty Creek............... 983 1 313
IN...................... Clifty Creek............... 983 2 315
IN...................... Clifty Creek............... 983 5 316
IN...................... Clifty Creek............... 983 3 322
IN...................... A B Brown Generating 6137 2 334
Station.
IN...................... Petersburg................. 994 1 341
IN...................... Wabash River............... 1010 6 372
IN...................... Bailly..................... 995 8 394
IN...................... State Line Generating 981 4 410
Station (IN).
IN...................... F B Culley Generating 1012 3 419
Station.
IN...................... Warrick.................... 6705 4 436
IN...................... R M Schahfer............... 6085 17 459
IN...................... Harding Street Station (EW 990 70 471
Stout).
IN...................... R M Schahfer............... 6085 18 476
IN...................... Tanners Creek.............. 988 U4 556
IN...................... R M Schahfer............... 6085 14 599
IN...................... Petersburg................. 994 2 601
IN...................... Michigan City.............. 997 12 604
IN...................... Cayuga..................... 1001 2 606
IN...................... Cayuga..................... 1001 1 650
IN...................... Gibson..................... 6113 3 717
IN...................... Petersburg................. 994 4 734
IN...................... Gibson..................... 6113 2 742
IN...................... Merom...................... 6213 1SG1 757
IN...................... Petersburg................. 994 3 764
IN...................... R M Schahfer............... 6085 15 787
IN...................... Merom...................... 6213 2SG1 790
IN...................... Gibson..................... 6113 1 815
IN...................... Gibson..................... 6113 4 866
IN...................... Gibson..................... 6113 5 871
IN...................... Rockport................... 6166 MB1 2321
IN...................... Rockport................... 6166 MB2 2327
KS...................... Riverton................... 1239 39 54
KS...................... Riverton................... 1239 40 79
KS...................... Quindaro................... 1295 1 105
KS...................... Lawrence Energy Center..... 1250 3 120
KS...................... Tecumseh Energy Center..... 1252 9 142
KS...................... Quindaro................... 1295 2 170
KS...................... Lawrence Energy Center..... 1250 4 225
KS...................... Tecumseh Energy Center..... 1252 10 245
KS...................... Nearman Creek.............. 6064 N1 471
KS...................... Lawrence Energy Center..... 1250 5 535
KS...................... Holcomb.................... 108 SGU1 643
KS...................... La Cygne................... 1241 1 1092
[[Page 12426]]
KS...................... Jeffrey Energy Center...... 6068 1 1182
KS...................... Jeffrey Energy Center...... 6068 2 1284
KS...................... La Cygne................... 1241 2 1304
KS...................... Jeffrey Energy Center...... 6068 3 1352
KY...................... Green River................ 1357 3 10
KY...................... Henderson I................ 1372 6 10
KY...................... Green River................ 1357 2 11
KY...................... Green River................ 1357 1 11
KY...................... Pineville.................. 1360 3 35
KY...................... Tyrone..................... 1361 5 70
KY...................... Robert Reid................ 1383 R1 80
KY...................... William C. Dale............ 1385 3 92
KY...................... Green River................ 1357 4 92
KY...................... William C. Dale............ 1385 4 99
KY...................... Green River................ 1357 5 118
KY...................... John S. Cooper............. 1384 1 126
KY...................... E W Brown.................. 1355 1 128
KY...................... Shawnee.................... 1379 10 156
KY...................... E W Brown.................. 1355 2 186
KY...................... Shawnee.................... 1379 6 190
KY...................... Shawnee.................... 1379 1 195
KY...................... Shawnee.................... 1379 4 196
KY...................... Shawnee.................... 1379 2 197
KY...................... Shawnee.................... 1379 5 200
KY...................... Shawnee.................... 1379 9 206
KY...................... Coleman.................... 1381 C3 208
KY...................... Cane Run................... 1363 5 210
KY...................... Coleman.................... 1381 C1 211
KY...................... Shawnee.................... 1379 3 211
KY...................... Coleman.................... 1381 C2 215
KY...................... Shawnee.................... 1379 7 215
KY...................... Shawnee.................... 1379 8 216
KY...................... Cane Run................... 1363 4 217
KY...................... Elmer Smith................ 1374 1 224
KY...................... HMP&L Station 2............ 1382 H1 224
KY...................... HMP&L Station 2............ 1382 H2 234
KY...................... Cane Run................... 1363 6 251
KY...................... John S. Cooper............. 1384 2 251
KY...................... R D Green.................. 6639 G2 338
KY...................... R D Green.................. 6639 G1 343
KY...................... Big Sandy.................. 1353 BSU1 347
KY...................... Elmer Smith................ 1374 2 393
KY...................... Mill Creek................. 1364 2 402
KY...................... Mill Creek................. 1364 1 408
KY...................... H L Spurlock............... 6041 1 411
KY...................... E W Brown.................. 1355 3 481
KY...................... Mill Creek................. 1364 3 541
KY...................... Mill Creek................. 1364 4 568
KY...................... Ghent...................... 1356 2 593
KY...................... Ghent...................... 1356 4 622
KY...................... Ghent...................... 1356 3 628
KY...................... Trimble County............. 6071 1 709
KY...................... Ghent...................... 1356 1 710
KY...................... D B Wilson................. 6823 W1 722
KY...................... East Bend.................. 6018 2 864
KY...................... Paradise................... 1378 1 869
KY...................... H L Spurlock............... 6041 2 903
KY...................... Paradise................... 1378 2 931
KY...................... Big Sandy.................. 1353 BSU2 1087
KY...................... Paradise................... 1378 3 1187
LA...................... Rodemacher................. 6190 2 856
LA...................... R S Nelson................. 1393 6 942
LA...................... Big Cajun 2................ 6055 2B3 1035
LA...................... Big Cajun 2................ 6055 2B2 1035
LA...................... Big Cajun 2................ 6055 2B1 1053
LA...................... Dolet Hills................ 51 1 2621
MA...................... Salem Harbor............... 1626 1 118
MA...................... Salem Harbor............... 1626 2 132
MA...................... Somerset................... 1613 8 163
MA...................... Salem Harbor............... 1626 3 206
MA...................... Mount Tom.................. 1606 1 222
MA...................... Brayton Point.............. 1619 1 329
[[Page 12427]]
MA...................... Brayton Point.............. 1619 2 331
MA...................... Brayton Point.............. 1619 3 729
MD...................... R P Smith.................. 1570 9 15
MD...................... AES Warrior Run............ 10678 001 20
MD...................... R P Smith.................. 1570 11 94
MD...................... Herbert a Wagner........... 1554 2 190
MD...................... Dickerson.................. 1572 1 212
MD...................... Dickerson.................. 1572 2 219
MD...................... Dickerson.................. 1572 3 223
MD...................... C P Crane.................. 1552 1 223
MD...................... C P Crane.................. 1552 2 259
MD...................... Herbert a Wagner........... 1554 3 415
MD...................... Chalk Point................ 1571 2 420
MD...................... Chalk Point................ 1571 1 424
MD...................... Morgantown................. 1573 1 690
MD...................... Morgantown................. 1573 2 706
MD...................... Brandon Shores............. 602 2 919
MD...................... Brandon Shores............. 602 1 928
ME...................... S.D. Warren Company 21 17
i>2.
MI...................... Marysville................. 1732 9 10
MI...................... Marysville................. 1732 11 11
MI...................... Marysville................. 1732 12 12
MI...................... Marysville................. 1732 10 13
MI...................... Presque Isle............... 1769 2 16
MI...................... Wyandotte.................. 1866 8 25
MI...................... James De Young............. 1830 5 39
MI...................... Eckert Station............. 1831 3 41
MI...................... Eckert Station............. 1831 1 43
MI...................... Eckert Station............. 1831 2 46
MI...................... Wyandotte.................. 1866 7 46
MI...................... Harbor Beach............... 1731 1 55
MI...................... J B Sims................... 1825 3 75
MI...................... Presque Isle............... 1769 3 76
MI...................... Presque Isle............... 1769 4 77
MI...................... Endicott Generating........ 4259 1 85
MI...................... Trenton Channel............ 1745 18 86
MI...................... Shiras..................... 1843 3 89
MI...................... Trenton Channel............ 1745 19 89
MI...................... Trenton Channel............ 1745 17 90
MI...................... Trenton Channel............ 1745 16 94
MI...................... Tes Filer City Station..... 50835 GEN 1 104
MI...................... Eckert Station............. 1831 5 113
MI...................... Eckert Station............. 1831 4 119
MI...................... Presque Isle............... 1769 6 128
MI...................... Presque Isle............... 1769 5 131
MI...................... Eckert Station............. 1831 6 145
MI...................... Presque Isle............... 1769 7 147
MI...................... Presque Isle............... 1769 9 153
MI...................... Presque Isle............... 1769 8 153
MI...................... J R Whiting................ 1723 1 154
MI...................... J R Whiting................ 1723 2 156
MI...................... Erickson................... 1832 1 177
MI...................... J R Whiting................ 1723 3 186
MI...................... St. Clair.................. 1743 2 206
MI...................... St. Clair.................. 1743 4 231
MI...................... St. Clair.................. 1743 1 232
MI...................... St. Clair.................. 1743 3 239
MI...................... J C Weadock................ 1720 7 245
MI...................... B C Cobb................... 1695 5 259
MI...................... B C Cobb................... 1695 4 265
MI...................... J C Weadock................ 1720 8 268
MI...................... J H Campbell............... 1710 1 359
MI...................... Dan E Karn................. 1702 1 368
MI...................... River Rouge................ 1740 2 372
MI...................... Dan E Karn................. 1702 2 376
MI...................... River Rouge................ 1740 3 376
MI...................... St. Clair.................. 1743 6 416
MI...................... J H Campbell............... 1710 2 452
MI...................... St. Clair.................. 1743 7 584
MI...................... Trenton Channel............ 1745 9A 631
MI...................... Monroe..................... 1733 2 943
MI...................... Monroe..................... 1733 3 970
[[Page 12428]]
MI...................... Monroe..................... 1733 4 1076
MI...................... Monroe..................... 1733 1 1105
MI...................... Belle River................ 6034 2 1152
MI...................... J H Campbell............... 1710 3 1199
MI...................... Belle River................ 6034 1 1223
MN...................... Minnesota Valley........... 1918 4 1
MN...................... Black Dog.................. 1904 2 3
MN...................... Black Dog.................. 1904 1 3
MN...................... High Bridge................ 1912 3 25
MN...................... High Bridge................ 1912 4 32
MN...................... Northeast Station.......... 1961 NEPP 33
MN...................... Taconite Harbor Energy 10075 1 38
Center.
MN...................... Silver Lake................ 2008 4 43
MN...................... Taconite Harbor Energy 10075 3 53
Center.
MN...................... Taconite Harbor Energy 10075 2 55
Center.
MN...................... Syl Laskin................. 1891 2 95
MN...................... Syl Laskin................. 1891 1 97
MN...................... Hoot Lake.................. 1943 2 102
MN...................... Clay Boswell............... 1893 1 112
MN...................... Clay Boswell............... 1893 2 115
MN...................... Riverside (1927)........... 1927 6 126
MN...................... Riverside (1927)........... 1927 7 128
MN...................... Hoot Lake.................. 1943 3 128
MN...................... High Bridge................ 1912 5 146
MN...................... Black Dog.................. 1904 3 146
MN...................... High Bridge................ 1912 6 246
MN...................... Black Dog.................. 1904 4 267
MN...................... Riverside (1927)........... 1927 8 399
MN...................... Clay Boswell............... 1893 3 593
MN...................... Allen S King............... 1915 1 794
MN...................... Clay Boswell............... 1893 4 1010
MN...................... Sherburne County........... 6090 2 1178
MN...................... Sherburne County........... 6090 1 1215
MN...................... Sherburne County........... 6090 3 1586
MO...................... Columbia................... 2123 6 9
MO...................... Columbia................... 2123 7 12
MO...................... Blue Valley................ 2132 3 33
MO...................... Chamois.................... 2169 2 77
MO...................... James River................ 2161 3 84
MO...................... Sibley..................... 2094 2 84
MO...................... Sibley..................... 2094 1 89
MO...................... James River................ 2161 4 94
MO...................... Lake Road.................. 2098 6 156
MO...................... James River................ 2161 5 182
MO...................... Meramec.................... 2104 2 186
MO...................... Meramec.................... 2104 1 187
MO...................... Meramec.................... 2104 3 231
MO...................... Montrose................... 2080 1 271
MO...................... Montrose................... 2080 2 280
MO...................... Montrose................... 2080 3 295
MO...................... Asbury..................... 2076 1 312
MO...................... Thomas Hill................ 2168 MB1 345
MO...................... Meramec.................... 2104 4 384
MO...................... Southwest.................. 6195 1 394
MO...................... Sikeston................... 6768 1 509
MO...................... Thomas Hill................ 2168 MB2 549
MO...................... Sibley..................... 2094 3 585
MO...................... Sioux...................... 2107 1 618
MO...................... Sioux...................... 2107 2 638
MO...................... Hawthorn................... 2079 5A 809
MO...................... Labadie.................... 2103 4 895
MO...................... Rush Island................ 6155 1 904
MO...................... Labadie.................... 2103 1 930
MO...................... Rush Island................ 6155 2 931
MO...................... New Madrid................. 2167 1 948
MO...................... Labadie.................... 2103 2 958
MO...................... Labadie.................... 2103 3 1002
MO...................... New Madrid................. 2167 2 1031
MO...................... Iatan...................... 6065 1 1134
MO...................... Thomas Hill................ 2168 MB3 1303
MS...................... R D Morrow................. 6061 2 259
MS...................... R D Morrow................. 6061 1 263
[[Page 12429]]
MS...................... Watson Electric Generating 2049 4 325
Plant.
MS...................... Red Hills Generation 55076 AA002 329
Facility.
MS...................... Red Hills Generation 55076 AA001 355
Facility.
MS...................... Watson Electric Generating 2049 5 677
Plant.
MS...................... Daniel Electric Generating 6073 2 712
Plant.
MS...................... Daniel Electric Generating 6073 1 738
Plant.
MT...................... Colstrip Energy Limited 10784 GEN 1 96
Partnership.
MT...................... Lewis & Clark.............. 6089 B1 253
MT...................... J E Corette................ 2187 2 288
MT...................... Colstrip................... 6076 1 620
MT...................... Colstrip................... 6076 2 651
MT...................... Colstrip................... 6076 3 1342
MT...................... Colstrip................... 6076 4 1475
NC...................... Elizabethtown Power........ 10380 UNIT2 11
NC...................... Elizabethtown Power........ 10380 UNIT1 11
NC...................... Lumberton Power............ 10382 UNIT1 13
NC...................... Lumberton Power............ 10382 UNIT2 21
NC...................... Buck....................... 2720 6 23
NC...................... Buck....................... 2720 5 24
NC...................... Cliffside.................. 2721 1 25
NC...................... Buck....................... 2720 7 25
NC...................... Cliffside.................. 2721 2 26
NC...................... Cliffside.................. 2721 4 36
NC...................... Cliffside.................. 2721 3 41
NC...................... Dwayne Collier Battle 10384 1B 43
Cogeneration Facility.
NC...................... Dwayne Collier Battle 10384 2A 44
Cogeneration Facility.
NC...................... Dan River.................. 2723 1 44
NC...................... Dwayne Collier Battle 10384 2B 44
Cogeneration Facility.
NC...................... W H Weatherspoon........... 2716 2 46
NC...................... W H Weatherspoon........... 2716 1 46
NC...................... Dan River.................. 2723 2 46
NC...................... Dwayne Collier Battle 10384 1A 47
Cogeneration Facility.
NC...................... Tobaccoville............... 50221 GEN 1 50
NC...................... Tobaccoville............... 50221 GEN 2 50
NC...................... Westmoreland-Lg&E Partners 54755 2 70
Roanoke Valley I.
NC...................... W H Weatherspoon........... 2716 3 73
NC...................... Riverbend.................. 2732 8 75
NC...................... Lee........................ 2709 2 78
NC...................... Lee........................ 2709 1 79
NC...................... Riverbend.................. 2732 7 79
NC...................... L V Sutton................. 2713 1 80
NC...................... L V Sutton................. 2713 2 84
NC...................... Dan River.................. 2723 3 112
NC...................... Buck....................... 2720 8 132
NC...................... Riverbend.................. 2732 10 132
NC...................... Riverbend.................. 2732 9 134
NC...................... Cape Fear.................. 2708 5 142
NC...................... Buck....................... 2720 9 152
NC...................... G DG Allen................. 2718 2 154
NC...................... G G Allen.................. 2718 1 156
NC...................... Cape Fear.................. 2708 6 172
NC...................... Westmoreland-Lg&E Partners 54035 1 201
Roanoke Valley I.
NC...................... Asheville.................. 2706 2 238
NC...................... Lee........................ 2709 3 249
NC...................... Asheville.................. 2706 1 255
NC...................... G G Allen.................. 2718 5 259
NC...................... G G Allen.................. 2718 3 271
NC...................... G G Allen.................. 2718 4 278
NC...................... L V Sutton................. 2713 3 372
NC...................... Roxboro.................... 2712 4B 376
NC...................... Roxboro.................... 2712 4A 405
NC...................... Roxboro.................... 2712 3A 424
NC...................... Roxboro.................... 2712 3B 426
NC...................... Roxboro.................... 2712 1 427
NC...................... Marshall................... 2727 1 448
NC...................... Marshall................... 2727 2 464
NC...................... Mayo....................... 6250 1B 479
NC...................... Mayo....................... 6250 1A 501
NC...................... Cliffside.................. 2721 5 616
NC...................... Marshall................... 2727 3 752
NC...................... Marshall................... 2727 4 753
NC...................... Roxboro.................... 2712 2 793
[[Page 12430]]
NC...................... Belews Creek............... 8042 2 1408
NC...................... Belews Creek............... 8042 1 1430
ND...................... Stanton.................... 2824 10 267
ND...................... R M Heskett................ 2790 B2 327
ND...................... Stanton.................... 2824 1 538
ND...................... Leland Olds................ 2817 1 1003
ND...................... Milton R Young............. 2823 B1 1167
ND...................... Coyote..................... 8222 B1 1974
ND...................... Leland Olds................ 2817 2 1985
ND...................... Antelope Valley............ 6469 B2 2192
ND...................... Antelope Valley............ 6469 B1 2210
ND...................... Milton R Young............. 2823 B2 2317
ND...................... Coal Creek................. 6030 2 2755
ND...................... Coal Creek................. 6030 1 2926
NE...................... Lon D Wright Power Plant... 2240 8 99
NE...................... North Omaha................ 2291 1 120
NE...................... Gerald Whelan Energy Center 60 1 147
NE...................... North Omaha................ 2291 3 158
NE...................... North Omaha................ 2291 2 168
NE...................... Platte..................... 59 1 172
NE...................... Sheldon.................... 2277 1 200
NE...................... Sheldon.................... 2277 2 203
NE...................... North Omaha................ 2291 4 212
NE...................... North Omaha................ 2291 5 283
NE...................... Nebraska City.............. 6096 1 1093
NE...................... Gerald Gentleman Station... 6077 2 1210
NE...................... Gerald Gentleman Station... 6077 1 1216
NH...................... Schiller................... 2367 6 65
NH...................... Schiller................... 2367 5 71
NH...................... Schiller................... 2367 4 74
NH...................... Merrimack.................. 2364 1 182
NH...................... Merrimack.................. 2364 2 418
NJ...................... Carneys Point.............. 10566 1002 89
NJ...................... Deepwater.................. 2384 8 94
NJ...................... Carneys Point.............. 10566 1001 105
NJ...................... B L England................ 2378 1 136
NJ...................... Logan Generating Plant..... 10043 1001 162
NJ...................... B L England................ 2378 2 167
NJ...................... Mercer Generating Station.. 2408 2 277
NJ...................... Mercer Generating Station.. 2408 1 291
NJ...................... Hudson..................... 2403 2 600
NM...................... Four Corners............... 2442 1 362
NM...................... Four Corners............... 2442 2 369
NM...................... Four Corners............... 2442 3 457
NM...................... Prewitt Escalante 87 1 492
Generating Statio.
NM...................... San Juan................... 2451 1 637
NM...................... San Juan................... 2451 2 650
NM...................... San Juan................... 2451 3 990
NM...................... San Juan................... 2451 4 1014
NM...................... Four Corners............... 2442 4 1346
NM...................... Four Corners............... 2442 5 1375
NV...................... Reid Gardner............... 2324 3 185
NV...................... Reid Gardner............... 2324 1 186
NV...................... Reid Gardner............... 2324 2 192
NV...................... North Valmy................ 8224 1 324
NV...................... Reid Gardner............... 2324 4 395
NV...................... North Valmy................ 8224 2 407
NV...................... Mohave..................... 2341 1 910
NV...................... Mohave..................... 2341 2 971
NY...................... AES Hickling............... 2529 2 9
NY...................... AES Hickling............... 2529 1 10
NY...................... AES Jennison............... 2531 2 10
NY...................... AES Jennison............... 2531 1 10
NY...................... S A Carlson................ 2682 11 11
NY...................... S A Carlson................ 2682 10 12
NY...................... S A Carlson................ 2682 9 14
NY...................... AES Jennison............... 2531 3 17
NY...................... AES Jennison............... 2531 4 17
NY...................... S A Carlson................ 2682 12 21
NY...................... Black River Power 10464 E0001 30
Generation.
NY...................... Black River Power 10464 E0002 30
Generation.
NY...................... Black River Power 10464 E0003 30
Generation.
[[Page 12431]]
NY...................... AES Hickling............... 2529 4 32
NY...................... AES Hickling............... 2529 3 32
NY...................... AES Greenidge.............. 2527 5 35
NY...................... AES Greenidge.............. 2527 4 35
NY...................... AES Westover (Goudey)...... 2526 12 35
NY...................... AES Westover (Goudey)...... 2526 11 36
NY...................... Rochester 7--Russell 2642 1 55
Station.
NY...................... WPS Empire State, Inc 50202 1 58
Niagara Falls.
NY...................... Rochester 3--Beebee Station 2640 12 67
NY...................... Rochester 7--Russell 2642 2 72
Station.
NY...................... Rochester 7--Russell 2642 3 72
Station.
NY...................... Huntley Power.............. 2549 63 78
NY...................... Huntley Power.............. 2549 64 90
NY...................... Huntley Power.............. 2549 65 97
NY...................... Rochester 7--Russell 2642 4 99
Station.
NY...................... Huntley Power.............. 2549 66 106
NY...................... AES Westover (Goudey)...... 2526 13 120
NY...................... Dunkirk.................... 2554 1 132
NY...................... Dunkirk.................... 2554 2 142
NY...................... AES Greenidge.............. 2527 6 155
NY...................... Dynegy Danskammer.......... 2480 3 157
NY...................... Dunkirk.................... 2554 3 211
NY...................... Lovett..................... 2629 4 212
NY...................... Lovett..................... 2629 5 219
NY...................... AES Cayuga (Milliken)...... 2535 2 229
NY...................... AES Cayuga (Milliken)...... 2535 1 231
NY...................... Dunkirk.................... 2554 4 233
NY...................... Huntley Power.............. 2549 67 246
NY...................... Huntley Power.............. 2549 68 259
NY...................... Dynegy Danskammer.......... 2480 4 327
NY...................... AES Somerset (Kintigh)..... 6082 1 943
OH...................... R E Burger................. 2864 6 11
OH...................... R E Burger................. 2864 5 11
OH...................... Ashtabula.................. 2835 8 13
OH...................... O H Hutchings.............. 2848 H-1 16
OH...................... Ashtabula.................. 2835 10 16
OH...................... O H Hutchings.............. 2848 H-2 16
OH...................... Ashtabula.................. 2835 11 23
OH...................... Miami Fort................. 2832 5-2 36
OH...................... Miami Fort................. 2832 5-1 36
OH...................... O H Hutchings.............. 2848 H-5 38
OH...................... O H Hutchings.............. 2848 H-4 38
OH...................... O H Hutchings.............. 2848 H-3 38
OH...................... O H Hutchings.............. 2848 H-6 40
OH...................... Hamilton Municipal Power 2917 9 58
Plant.
OH...................... Richard Gorsuch............ 7286 1 85
OH...................... Richard Gorsuch............ 7286 2 86
OH...................... Avon Lake Power Plant...... 2836 10 89
OH...................... Richard Gorsuch............ 7286 4 90
OH...................... Richard Gorsuch............ 7286 3 91
OH...................... Picway..................... 2843 9 93
OH...................... Conesville................. 2840 1 124
OH...................... Conesville................. 2840 2 124
OH...................... Niles...................... 2861 2 125
OH...................... Eastlake................... 2837 1 127
OH...................... Walter C Beckjord.......... 2830 2 129
OH...................... Walter C Beckjord.......... 2830 1 130
OH...................... Eastlake................... 2837 2 131
OH...................... Eastlake................... 2837 3 136
OH...................... Conesville................. 2840 3 136
OH...................... Lake Shore................. 2838 18 137
OH...................... Niles...................... 2861 1 137
OH...................... R E Burger................. 2864 8 172
OH...................... Bay Shore.................. 2878 3 177
OH...................... Muskingum River............ 2872 2 177
OH...................... Bay Shore.................. 2878 1 181
OH...................... Bay Shore.................. 2878 2 183
OH...................... Walter C Beckjord.......... 2830 3 184
OH...................... R E Burger................. 2864 7 198
OH...................... Muskingum River............ 2872 1 201
OH...................... Muskingum River............ 2872 3 206
OH...................... Muskingum River............ 2872 4 207
[[Page 12432]]
OH...................... Walter C Beckjord.......... 2830 4 223
OH...................... Eastlake................... 2837 4 225
OH...................... W H Sammis................. 2866 2 241
OH...................... W H Sammis................. 2866 1 244
OH...................... W H Sammis................. 2866 3 247
OH...................... Ashtabula.................. 2835 7 248
OH...................... Miami Fort................. 2832 6 250
OH...................... W H Sammis................. 2866 4 251
OH...................... Kyger Creek................ 2876 5 269
OH...................... Kyger Creek................ 2876 2 271
OH...................... Kyger Creek................ 2876 4 273
OH...................... Kyger Creek................ 2876 3 273
OH...................... Kyger Creek................ 2876 1 281
OH...................... Bay Shore.................. 2878 4 283
OH...................... Walter C Beckjord.......... 2830 5 288
OH...................... W H Sammis................. 2866 5 374
OH...................... Conesville................. 2840 5 432
OH...................... Conesville................. 2840 6 435
OH...................... Walter C Beckjord.......... 2830 6 532
OH...................... Cardinal................... 2828 1 562
OH...................... Eastlake................... 2837 5 591
OH...................... Cardinal................... 2828 2 630
OH...................... J M Stuart................. 2850 3 646
OH...................... Miami Fort................. 2832 8 646
OH...................... Avon Lake Power Plant...... 2836 12 680
OH...................... Miami Fort................. 2832 7 680
OH...................... Muskingum River............ 2872 5 689
OH...................... Cardinal................... 2828 3 695
OH...................... J M Stuart................. 2850 4 707
OH...................... J M Stuart................. 2850 1 711
OH...................... J M Stuart................. 2850 2 722
OH...................... W H Sammis................. 2866 7 726
OH...................... Conesville................. 2840 4 727
OH...................... W H Sammis................. 2866 6 766
OH...................... Killen Station............. 6031 2 919
OH...................... Gen J M Gavin.............. 8102 1 1573
OH...................... W H Zimmer................. 6019 1 1667
OH...................... Gen J M Gavin.............. 8102 2 1700
OK...................... Aes Shady Point, Inc....... 10671 GEN2 254
OK...................... Aes Shady Point, Inc....... 10671 GEN1 260
OK...................... Hugo....................... 6772 1 732
OK...................... Muskogee................... 2952 4 796
OK...................... Grand River Dam Authority.. 165 1 834
OK...................... Sooner..................... 6095 2 843
OK...................... Muskogee................... 2952 6 861
OK...................... Northeastern............... 2963 3314 878
OK...................... Muskogee................... 2952 5 883
OK...................... Grand River Dam Authority.. 165 2 902
OK...................... Northeastern............... 2963 3313 924
OK...................... Sooner..................... 6095 1 952
OR...................... Boardman................... 6106 1SG 948
PA...................... Seward..................... 3130 12 24
PA...................... Willamette Industries...... 54638 040 28
PA...................... Willamette Industries...... 54638 041 28
PA...................... Seward..................... 3130 14 30
PA...................... AES Beaver Valley Partners. 10676 035 41
PA...................... Piney Creek Power Plant.... 54144 031 55
PA...................... Johnsonburg Mill........... 54638 54638 56
PA...................... Sunbury.................... 3152 2A 59
PA...................... Sunbury.................... 3152 1B 61
PA...................... Sunbury.................... 3152 2B 62
PA...................... Westwood................... 50611 031 62
PA...................... Hunlock Power Station...... 3176 6 67
PA...................... Sunbury.................... 3152 1A 68
PA...................... Panther Creek Energy 50776 1 72
Facility.
PA...................... Panther Creek Energy 50776 2 72
Facility.
PA...................... AES Beaver Valley Partners. 10676 033 72
PA...................... AES Beaver Valley Partners. 10676 034 74
PA...................... Gilberton Power Company.... 10113 031 75
PA...................... Gilberton Power Company.... 10113 032 75
PA...................... Scrubgrass Generating Plant 50974 1 76
PA...................... Scrubgrass Generating Plant 50974 2 76
[[Page 12433]]
PA...................... Cambria Cogen.............. 10641 1 76
PA...................... Cambria Cogen.............. 10641 2 76
PA...................... Titus...................... 3115 2 81
PA...................... Titus...................... 3115 3 84
PA...................... Titus...................... 3115 1 84
PA...................... Foster Wheeler Mt. Carmel.. 10343 SG-101 84
PA...................... AES Beaver Valley Partners. 10676 032 86
PA...................... Wheelabrator--Frackville... 50879 GEN1 91
PA...................... Northeastern Power Company. 50039 031 96
PA...................... Ebensburg Power Company.... 10603 031 98
PA...................... New Castle................. 3138 3 108
PA...................... Elrama..................... 3098 3 110
PA...................... Elrama..................... 3098 1 113
PA...................... New Castle................. 3138 4 116
PA...................... Elrama..................... 3098 2 122
PA...................... Martins Creek.............. 3148 1 139
PA...................... Martins Creek.............. 3148 2 141
PA...................... Sunbury.................... 3152 3 141
PA...................... Sunbury.................... 3152 4 143
PA...................... Colver Power Project....... 10143 AAB01 146
PA...................... Portland................... 3113 1 150
PA...................... Shawville.................. 3131 1 151
PA...................... New Castle................. 3138 5 152
PA...................... Northampton Generating 50888 NGC01 154
Plant.
PA...................... Shawville.................. 3131 2 160
PA...................... Seward..................... 3130 15 172
PA...................... St. Nicholas Cogeneration 54634 1 173
Project.
PA...................... Cromby..................... 3159 1 194
PA...................... Shawville.................. 3131 3 203
PA...................... Armstrong.................. 3178 2 209
PA...................... Portland................... 3113 2 211
PA...................... Shawville.................. 3131 4 212
PA...................... Armstrong.................. 3178 1 213
PA...................... Elrama..................... 3098 4 295
PA...................... Mitchell................... 3181 33 311
PA...................... Brunner Island............. 3140 1 313
PA...................... Eddystone.................. 3161 1 322
PA...................... Eddystone.................. 3161 2 346
PA...................... Brunner Island............. 3140 2 389
PA...................... Hatfields Ferry............ 3179 2 592
PA...................... Hatfields Ferry............ 3179 1 628
PA...................... Hatfields Ferry............ 3179 3 660
PA...................... Cheswick................... 8226 1 665
PA...................... Homer City................. 3122 2 795
PA...................... Brunner Island............. 3140 3 804
PA...................... Homer City................. 3122 3 821
PA...................... Montour.................... 3149 2 825
PA...................... Montour.................... 3149 1 856
PA...................... Homer City................. 3122 1 859
PA...................... Bruce Mansfield............ 6094 2 922
PA...................... Bruce Mansfield............ 6094 1 928
PA...................... Bruce Mansfield............ 6094 3 950
PA...................... Keystone................... 3136 1 1147
PA...................... Keystone................... 3136 2 1168
PA...................... Conemaugh.................. 3118 2 1194
PA...................... Conemaugh.................. 3118 1 1202
SC...................... W S Lee.................... 3264 1 60
SC...................... W S Lee.................... 3264 2 68
SC...................... Urquhart................... 3295 URQ1 76
SC...................... Urquhart................... 3295 URQ2 80
SC...................... Dolphus M Grainger......... 3317 2 84
SC...................... Dolphus M Grainger......... 3317 1 91
SC...................... Urquhart................... 3295 URQ3 116
SC...................... W S Lee.................... 3264 3 117
SC...................... Canadys Steam.............. 3280 CAN1 123
SC...................... Canadys Steam.............. 3280 CAN2 129
SC...................... McMeekin................... 3287 MCM1 161
SC...................... Canadys Steam.............. 3280 CAN3 163
SC...................... McMeekin................... 3287 MCM2 165
SC...................... H B Robinson............... 3251 1 184
SC...................... Jefferies.................. 3319 3 186
SC...................... Jefferies.................. 3319 4 195
[[Page 12434]]
SC...................... Winyah..................... 6249 1 361
SC...................... Winyah..................... 6249 2 371
SC...................... Winyah..................... 6249 4 373
SC...................... Wateree.................... 3297 WAT1 387
SC...................... Wateree.................... 3297 WAT2 389
SC...................... Winyah..................... 6249 3 403
SC...................... Cope Station............... 7210 COP1 575
SC...................... Cross...................... 130 1 729
SC...................... Cross...................... 130 2 810
SC...................... Williams................... 3298 WIL1 841
SD...................... Big Stone.................. 6098 1 899
TN...................... Johnsonville............... 3406 5 149
TN...................... Johnsonville............... 3406 6 151
TN...................... Johnsonville............... 3406 3 161
TN...................... Johnsonville............... 3406 10 162
TN...................... Johnsonville............... 3406 4 163
TN...................... Johnsonville............... 3406 1 164
TN...................... Johnsonville............... 3406 7 166
TN...................... Johnsonville............... 3406 2 168
TN...................... Kingston................... 3407 1 179
TN...................... Johnsonville............... 3406 8 181
TN...................... Johnsonville............... 3406 9 185
TN...................... Kingston................... 3407 3 189
TN...................... Kingston................... 3407 2 190
TN...................... Kingston................... 3407 4 191
TN...................... John Sevier................ 3405 1 239
TN...................... Kingston................... 3407 7 240
TN...................... John Sevier................ 3405 2 242
TN...................... Kingston................... 3407 9 245
TN...................... Kingston................... 3407 6 251
TN...................... Kingston................... 3407 8 253
TN...................... Kingston................... 3407 5 259
TN...................... John Sevier................ 3405 4 263
TN...................... John Sevier................ 3405 3 267
TN...................... Allen...................... 3393 1 299
TN...................... Allen...................... 3393 3 327
TN...................... Allen...................... 3393 2 332
TN...................... Gallatin................... 3403 2 368
TN...................... Gallatin................... 3403 1 371
TN...................... Gallatin................... 3403 3 408
TN...................... Gallatin................... 3403 4 422
TN...................... Bull Run................... 3396 1 1034
TN...................... Cumberland................. 3399 1 1825
TN...................... Cumberland................. 3399 2 2042
TX...................... TNP One.................... 7030 U1 675
TX...................... Harrington Station......... 6193 061B 711
TX...................... Harrington Station......... 6193 062B 716
TX...................... Harrington Station......... 6193 063B 735
TX...................... TNP One.................... 7030 U2 738
TX...................... Gibbons Creek.............. 6136 1 745
TX...................... J T Deely.................. 6181 1 767
TX...................... J T Deely.................. 6181 2 778
TX...................... Sam Seymour................ 6179 3 823
TX...................... Coleto Creek............... 6178 1 903
TX...................... Welsh Power Plant.......... 6139 3 955
TX...................... Tolk Station............... 6194 171B 966
TX...................... Sam Seymour................ 6179 1 970
TX...................... Tolk Station............... 6194 172B 984
TX...................... Welsh Power Plant.......... 6139 1 987
TX...................... Welsh Power Plant.......... 6139 2 990
TX...................... J K Spruce................. 7097 **1 1006
TX...................... Sam Seymour................ 6179 2 1014
TX...................... W A Parish................. 3470 WAP8 1050
TX...................... W A Parish................. 3470 WAP7 1086
TX...................... W A Parish................. 3470 WAP6 1276
TX...................... W A Parish................. 3470 WAP5 1301
TX...................... Oklaunion Power Station.... 127 1 1353
TX...................... San Miguel................. 6183 SM-1 2040
TX...................... Monticello................. 6147 1 2434
TX...................... Big Brown.................. 3497 2 2435
TX...................... Monticello................. 6147 2 2545
TX...................... Big Brown.................. 3497 1 2596
[[Page 12435]]
TX...................... Monticello................. 6147 3 2599
TX...................... H W Pirkey Power Plant..... 7902 1 2694
TX...................... Sandow..................... 6648 4 2871
TX...................... Limestone.................. 298 LIM2 3260
TX...................... Martin Lake................ 6146 1 3337
TX...................... Martin Lake................ 6146 2 3433
TX...................... Martin Lake................ 6146 3 3490
TX...................... Limestone.................. 298 LIM1 3525
UT...................... Sunnyside Cogeneration 50951 GEN1 90
Associates.
UT...................... Carbon..................... 3644 1 119
UT...................... Carbon..................... 3644 2 175
UT...................... Hunter (Emery)............. 6165 3 634
UT...................... Huntington................. 8069 1 642
UT...................... Hunter (Emery)............. 6165 1 646
UT...................... Huntington................. 8069 2 657
UT...................... Hunter (Emery)............. 6165 2 678
UT...................... Bonanza.................... 7790 1-1 746
UT...................... Intermountain.............. 6481 1SGA 1339
UT...................... Intermountain.............. 6481 2SGA 1429
VA...................... Hopewell Power Station..... 10771 1 9
VA...................... Hopewell Power Station..... 10771 2 9
VA...................... Altavista Power Station.... 10773 1 28
VA...................... Altavista Power Station.... 10773 2 28
VA...................... Cogentrix of Richmond...... 54081 BLR04B 31
VA...................... Cogentrix of Richmond...... 54081 BLR03B 31
VA...................... Southampton Power Station.. 10774 1 32
VA...................... Cogentrix of Richmond...... 54081 BLR04A 32
VA...................... Southampton Power Station.. 10774 2 32
VA...................... Cogentrix of Richmond...... 54081 BLR03A 33
VA...................... Cogentrix of Richmond...... 54081 BLR01B 44
VA...................... Cogentrix of Richmond...... 54081 BLR01A 44
VA...................... Cogentrix of Richmond...... 54081 BLR02A 45
VA...................... Cogentrix of Richmond...... 54081 BLR02B 45
VA...................... Mecklenburg Cogeneration 52007 1 55
Facility.
VA...................... Glen Lyn................... 3776 51 57
VA...................... Glen Lyn................... 3776 52 63
VA...................... Mecklenburg Cogeneration 52007 2 69
Facility.
VA...................... Potomac River.............. 3788 1 79
VA...................... Potomac River.............. 3788 2 81
VA...................... Bremo...................... 3796 3 99
VA...................... Potomac River.............. 3788 5 121
VA...................... Potomac River.............. 3788 4 130
VA...................... Possum Point Power Station. 3804 3 131
VA...................... Potomac River.............. 3788 3 133
VA...................... Chesterfield............... 3797 3 133
VA...................... Chesapeake................. 3803 1 170
VA...................... Chesapeake................. 3803 2 175
VA...................... Birchwood Power Facility... 54304 01 182
VA...................... Bremo...................... 3796 4 203
VA...................... Yorktown................... 3809 1 203
VA...................... Chesterfield............... 3797 4 211
VA...................... Chesapeake................. 3803 3 214
VA...................... Yorktown................... 3809 2 219
VA...................... Clinch River............... 3775 2 280
VA...................... Glen Lyn................... 3776 6 281
VA...................... Clinch River............... 3775 1 281
VA...................... Possum Point Power Station. 3804 4 282
VA...................... Clinch River............... 3775 3 307
VA...................... Chesapeake................. 3803 4 310
VA...................... Chesterfield............... 3797 5 406
VA...................... Clover Power Station....... 7213 1 651
VA...................... Clover Power Station....... 7213 2 668
VA...................... Chesterfield............... 3797 6 837
WA...................... Centralia.................. 3845 BW21 1224
WA...................... Centralia.................. 3845 BW22 1243
WI...................... Stoneman................... 4146 B1 5
WI...................... Stoneman................... 4146 B2 5
WI...................... Alma....................... 4140 B2 10
WI...................... Alma....................... 4140 B1 11
WI...................... Alma....................... 4140 B3 12
WI...................... Manitowoc.................. 4125 7 20
WI...................... Blount Street.............. 3992 7 20
[[Page 12436]]
WI...................... Manitowoc.................. 4125 6 20
WI...................... Manitowoc.................. 4125 8 26
WI...................... Bay Front.................. 3982 5 30
WI...................... Pulliam.................... 4072 3 31
WI...................... Blount Street.............. 3992 8 42
WI...................... Pulliam.................... 4072 4 43
WI...................... Blount Street.............. 3992 9 50
WI...................... Alma....................... 4140 B4 57
WI...................... Port Washington............ 4040 1 69
WI...................... Port Washington............ 4040 4 73
WI...................... Port Washington............ 4040 2 76
WI...................... Alma....................... 4140 B5 77
WI...................... Valley (Wepco)............. 4042 1 77
WI...................... Port Washington............ 4040 3 78
WI...................... Valley (Wepco)............. 4042 2 78
WI...................... Rock River................. 4057 1 79
WI...................... Valley (Wepco)............. 4042 3 87
WI...................... Valley (Wepco)............. 4042 4 88
WI...................... Rock River................. 4057 2 88
WI...................... Pulliam.................... 4072 5 88
WI...................... Weston..................... 4078 1 104
WI...................... Edgewater (4050)........... 4050 3 115
WI...................... Pulliam.................... 4072 6 135
WI...................... Weston..................... 4078 2 160
WI...................... Pulliam.................... 4072 7 166
WI...................... Nelson Dewey............... 4054 1 169
WI...................... Nelson Dewey............... 4054 2 172
WI...................... Pulliam.................... 4072 8 246
WI...................... South Oak Creek............ 4041 5 317
WI...................... South Oak Creek............ 4041 6 332
WI...................... Genoa...................... 4143 1 411
WI...................... Edgewater (4050)........... 4050 4 449
WI...................... South Oak Creek............ 4041 8 461
WI...................... South Oak Creek............ 4041 7 466
WI...................... J P Madgett................ 4271 B1 575
WI...................... Weston..................... 4078 3 676
WI...................... Edgewater (4050)........... 4050 5 680
WI...................... Columbia................... 8023 1 963
WI...................... Columbia................... 8023 2 979
WI...................... Pleasant Prairie........... 6170 2 1164
WI...................... Pleasant Prairie........... 6170 1 1206
WV...................... Rivesville................. 3945 7 28
WV...................... North Branch Power Station. 7537 1B 41
WV...................... North Branch Power Station. 7537 1A 42
WV...................... Morgantown Energy Facility. 10743 1 53
WV...................... Morgantown Energy Facility. 10743 2 53
WV...................... Albright................... 3942 2 70
WV...................... Albright................... 3942 1 71
WV...................... Willow Island.............. 3946 1 79
WV...................... Grant Town Power Plant..... 10151 1A 82
WV...................... Grant Town Power Plant..... 10151 1B 82
WV...................... Rivesville................. 3945 8 84
WV...................... Phil Sporn................. 3938 21 160
WV...................... Phil Sporn................. 3938 31 170
WV...................... Phil Sporn................. 3938 11 171
WV...................... Phil Sporn................. 3938 41 178
WV...................... Albright................... 3942 3 183
WV...................... Willow Island.............. 3946 2 211
WV...................... Kanawha River.............. 3936 1 238
WV...................... Kanawha River.............. 3936 2 240
WV...................... Kammer..................... 3947 1 252
WV...................... Kammer..................... 3947 2 258
WV...................... Kammer..................... 3947 3 262
WV...................... Phil Sporn................. 3938 51 443
WV...................... Fort Martin................ 3943 2 680
WV...................... Fort Martin................ 3943 1 698
WV...................... Pleasants.................. 6004 2 742
WV...................... Mount Storm Power Station.. 3954 2 761
WV...................... Pleasants.................. 6004 1 768
WV...................... Mount Storm Power Station.. 3954 3 798
WV...................... Mitchell................... 3948 1 810
WV...................... Mount Storm Power Station.. 3954 1 849
[[Page 12437]]
WV...................... Mitchell................... 3948 2 861
WV...................... John E Amos................ 3935 2 888
WV...................... Harrison................... 3944 2 893
WV...................... John E Amos................ 3935 1 904
WV...................... Harrison................... 3944 1 910
WV...................... Harrison................... 3944 3 942
WV...................... John E Amos................ 3935 3 1313
WV...................... Mountaineer (1301)......... 6264 1 1447
WY...................... Neil Simpson II............ 7504 001 210
WY...................... Dave Johnston.............. 4158 BW42 246
WY...................... Dave Johnston.............. 4158 BW41 247
WY...................... Naughton................... 4162 1 343
WY...................... Naughton................... 4162 2 430
WY...................... Dave Johnston.............. 4158 BW43 503
WY...................... Naughton................... 4162 3 669
WY...................... Dave Johnston.............. 4158 BW44 835
WY...................... Wyodak..................... 6101 BW91 869
WY...................... Jim Bridger................ 8066 BW73 1049
WY...................... Jim Bridger................ 8066 BW74 1057
WY...................... Laramie River.............. 6204 2 1063
WY...................... Jim Bridger................ 8066 BW71 1089
WY...................... Laramie River.............. 6204 1 1095
WY...................... Jim Bridger................ 8066 BW72 1149
WY...................... Laramie River.............. 6204 3 1161
----------------------------------------------------------------------------------------------------------------
List of Subjects
40 CFR Part 60
Administrative practice and procedure, Air pollution control,
Environmental protection, Reporting and recordkeeping requirements.
40 CFR Part 72 and 75
Air pollution control, carbon dioxide, Continuous emissions
monitors, Electric utilities, Environmental protection, Incorporation
by reference, Mercury, Nitrogen oxides, Reporting and recordkeeping
requirements, Sulfur dioxide.
For the reasons set forth in the preamble, parts 60, 72, and 75 of
chapter 1 of title 40 of the Code of Federal Regulations are proposed
to be amended as follows:
1. The authority citation for Part 60 continues to read as follows:
Authority: 42 U.S.C. 7401, 7403, 7426, and 7601.
2. Section 60.21 is amended by revising paragraph (f) and adding
paragraph (k) to read as follows:
Sec. 60.21 Definitions.
* * * * *
(f) Emission standard means a legally enforceable regulation
setting forth an allowable rate of emissions into the atmosphere,
establishing an allowance system or prescribing equipment
specifications for control of air pollution emissions.
* * * * *
(k) Allowance system means a control program under which the owner
or operator of each designated facility is required to hold an
authorization for each specified unit of designated pollutant emitted
from that facility during a specified period.
3-4. Section 60.24(b)(1) is revised to read as follows:
Sec. 60.24 Emission standards and compliance schedules.
* * * * *
(b) * * *
(1) Emission standards shall either be based on an allowance system
or prescribe allowable rates of emissions except when it is clearly
impracticable.
* * * * *
5. Subpart HHHH is added to read as follows:
Subpart HHHH--Emission Guidelines and Compliance Times for Coal-Fired
Elextric Steam Generating Units
Hg Budget Trading Program General Provisions
Sec.
60.4101 Purpose.
60.4102 Definitions.
60.4103 Measurements, abbreviations, and acronyms.
60.4104 Applicability.
60.4105 Retired unit exemption.
60.4106 Standard requirements.
60.4107 Computation of time.
Hg Authorized Account Representative for Hg Budget Sources
60.4110 Authorization and responsibilities of Hg authorized account
representative.
60.4111 Alternate Hg authorized account representative.
60.4112 Changing Hg authorized account representative and alternate
Hg authorized account representative; changes in owners and
operators.
60.4113 Account certificate of representation.
60.4114 Objections concerning Hg authorized account representative.
Permits
60.4120 General Hg Budget Trading Program permit requirements.
60.4121 Submission of Hg Budget permit applications.
60.4122 Information requirements for Hg Budget permit applications.
60.4123 Hg Budget permit contents.
60.4124 Hg Budget permit revisions.
Compliance Certification
60.4130 Compliance certification report.
60.4131 Administrator's action on compliance certifications.
Hg Allowance Allocations
60.4140 State trading program budget.
60.4141 Timing requirements for Hg allowance allocations.
60.4142 Hg allowance allocations.
60.4143 Hg safety valve provisions.
Hg Allowance Tracking System
60.4150 Hg Allowance Tracking System accounts.
60.4151 Establishment of accounts.
60.4152 Hg Allowance Tracking System responsibilities of Hg
authorized account representative.
60.4153 Recordation of Hg allowance allocations.
60.4154 Compliance.
60.4155 Banking.
60.4156 Account error.
60.4157 Closing of general accounts.
Hg Allowance Transfers
60.4160 Submission of Hg allowance transfers.
[[Page 12438]]
60.4161 EPA recordation.
60.4162 Notification.
Monitoring and Reporting
60.4170 General requirements.
60.4171 Initial certification and recertification procedures.
60.4172 Out of control periods.
60.4173 Notifications.
60.4174 Recordkeeping and reporting.
60.4175 Petitions.
60.4176 Additional requirements to provide heat input data.
Subpart HHHH--Emission Guidelines and Compliance Times for Coal-
Fired Electric Steam Generating Units
Hg Budget Trading Program General Provisions
Sec. 60.4101 Purpose.
This subpart establishes the model rule comprising general
provisions and the applicability, permitting, allowance, excess
emissions, and monitoring for the state Hg Budget Trading Program,
under section 111 of the CAA and Sec. 52.34 of this chapter, as a
means of reducing national mercury emissions.
Sec. 60.4102 Definitions.
The terms used in this subpart shall have the meanings set forth in
this section as follows:
Account number means the identification number given by the
Administrator to each Hg Allowance Tracking System account.
Adjusted baseline heat input means, with regard to a unit, the
unit's baseline heat input multiplied by:
(1) 1.0, for the portion of the baseline heat input that is the
unit's average annual combustion of bituminous during the years on
which the unit's baseline heat input is based;
(2) 3.0, for the portion of the baseline heat input that is the
unit's average annual combustion of lignite during the years on which
the unit's baseline heat input is based;
(3) 1.25, for the portion of the baseline heat input that is the
unit's average annual combustion of subbituminous during the years on
which the unit's baseline heat input is based;
(4) 1.0, for the portion of the baseline heat input that is not
covered by paragraphs (1), (2), or (3) of this definition or for the
entire baseline heat input if such baseline heat input is not based on
the unit's heat input in specified years; and
(5) 1.0, for the portion of the baseline heat input that is the new
unit's average annual combustion during the years on which the new
unit's baseline heat input is based.
Administrator means the Administrator of the United States
Environmental Protection Agency or the Administrator's duly authorized
representative.
Allocate or allocation means, with regard to Hg allowances, the
determination by the Administrator of the number of Hg allowances to be
initially credited to a Hg Budget unit or an allocation set-aside.
Automated data acquisition and handling system or DAHS means that
component of the CEMS, or other emissions monitoring system approved
for use under Sec. Sec. 60.4170 through 60.4176, designed to interpret
and convert individual output signals from pollutant concentration
monitors, flow monitors, diluent gas monitors, and other component
parts of the monitoring system to produce a continuous record of the
measured parameters in the measurement units required by Sec. Sec.
60.4170 through 60.4176.
Boiler means an enclosed fossil or other fuel-fired combustion
device used to produce heat and to transfer heat to recirculating
water, steam, or other medium.
Clean Air Act means the Clean Air Act, 42 U.S.C. 7401, et seq., as
amended by Pub. L. 101-549 (November 15, 1990).
Coal means any solid fuel classified as anthracite, bituminous,
subbituminous, or lignite.
Coal-derived fuel means any fuel (whether in a solid, liquid, or
gaseous state) produced by the mechanical, thermal, or chemical
processing of coal.
Coal-fired with regard to a unit means, combusting coal or any
coal-derived fuel alone or in combination with any amount of any other
fuel in any year.
Combustion unit means a coal-fired stationary boiler or combustion
turbine.
Commence commercial operation means, with regard to a unit that
serves a generator, to have begun to produce steam, gas, or other
heated medium used to generate electricity for sale or use, including
test generation. Except as provided in Sec. 60.4105 of, for a unit
that is a Hg Budget unit under Sec. 60.4104(a) on the date the unit
commences commercial operation, such date shall remain the unit's date
of commencement of commercial operation even if the unit is
subsequently modified, reconstructed, or repowered. Except as provided
in Sec. 60.4105, for a unit that is not a Hg Budget unit under Sec.
60.4104(a) on the date the unit commences commercial operation, the
date the unit becomes a Hg Budget unit under Sec. 60.4104(a) shall be
the unit's date of commencement of commercial operation.
Commence operation means to have begun any mechanical, chemical, or
electronic process, including, with regard to a unit, start-up of a
unit's combustion chamber. Except as provided in Sec. 60.4105 for a
unit that is a Hg Budget unit under Sec. 60.4104(a) on the date of
commencement of operation, such date shall remain the unit's date of
commencement of operation even if the unit is subsequently modified,
reconstructed, or repowered. Except as provided in Sec. 60.4105, for a
unit that is not a Hg Budget unit under Sec. 60.4104(a) on the date of
commencement of operation, the date the unit becomes a Hg Budget unit
under Sec. 60.4104(a) shall be the unit's date of commencement of
operation.
Common stack means a single flue through which emissions from two
or more units are exhausted.
Compliance account means a Hg Allowance Tracking System account,
established by the Administrator for a Hg Budget source under
Sec. Sec. 60.4150 through 60.4157, in which the Hg allowance
allocations for the source are initially recorded and in which are held
Hg allowances available for use by the source for a control period for
the purpose of meeting the source's Hg Budget emissions limitation.
Continuous emission monitoring system or CEMS means the equipment
required under Sec. Sec. 60.4170 through 60.4176 to sample, analyze,
measure, and provide, by means of readings recorded at least once every
15 minutes (using an automated data acquisition and handling system
(DAHS)), a permanent record of mercury (Hg) emissions, stack gas
volumetric flow rate or stack gas moisture content, in a manner
consistent with part 75 of this chapter. The following systems are the
principal types of continuous emission monitoring systems required
under Sec. Sec. 60.4170 through 60.4176:
(1) A flow monitoring system, consisting of a stack flow rate
monitor and an automated DAHS. A flow monitoring system provides a
permanent, continuous record of stack gas volumetric flow rate, in
units of standard cubic feet per hour (scfh);
(2) A Hg concentration monitoring system, consisting of a Hg
pollutant concentration monitor and an automated DAHS. A Hg
concentration monitoring system provides a permanent, continuous record
of Hg emissions in units of micrograms per dry standard cubic meter
([mu]g/dscm);
(3) A Hg emission rate (or Hg-diluent) monitoring system,
consisting of a Hg pollutant concentration monitor, a diluent gas
(CO2 or O2) monitor, and an automated DAHS. A Hg-
diluent
[[Page 12439]]
monitoring system provides a permanent, continuous record of: Hg
concentration in units of [mu]g/dscm, diluent gas concentration in
units of percent CO2 or O2 (percent
CO2 or O2), and Hg emission rate in units of
pounds per trillion British thermal units (lbs/10\12\ Btu); and
(4) A moisture monitoring system, as defined in Sec. 75.11(b)(2)
of this chapter. A moisture monitoring system provides a permanent,
continuous record of the stack gas moisture content, in units of
percent H2O (% H2O).
Control period means the period beginning January 1 of a year and
ending on December 31 of the same year, inclusive.
Emissions means air pollutants exhausted from a unit or source into
the atmosphere, as measured, recorded, and reported to the
Administrator by the Hg authorized account representative and as
determined by the Administrator in accordance with Sec. Sec. 60.4170
through 60.4176.
Energy Information Administration means the Energy Information
Administration of the United States Department of Energy.
Excess emissions means any ounces of mercury emitted by the Hg
Budget units at a Hg Budget source during a control period that exceeds
the Hg Budget emissions limitation for the source.
General account means a Hg Allowance Tracking System account,
established under this subpart, that is not a compliance account.
Generator means a device that produces electricity.
Heat input means, with regard to a specified period to time, the
product (in mmBtu/time) of the gross calorific value of the fuel (in
Btu/lb) divided by 1,000,000 Btu/mmBtu and multiplied by the fuel feed
rate into a combustion device (in lb of fuel/time), as measured,
recorded, and reported to the Administrator by the Hg authorized
account representative and as determined by the Administrator in
accordance with this subpart. Heat input does not include the heat
derived from preheated combustion air, recirculated flue gases, or
exhaust from other sources.
Heat input rate means the amount of heat input (in mmBtu) divided
by unit operating time (in hr) or, with regard to a specific fuel, the
amount of heat input attributed to the fuel (in mmBtu) divided by the
unit operating time (in hr) during which the unit combusts the fuel.
Hg allowance means a limited authorization by the Administrator
under the Hg Budget Trading Program to emit up to one ounce of mercury
during the control period of the specified year or of any year
thereafter. No provision of the Hg Budget Trading Program, the Hg
Budget permit application, the Hg Budget permit, or an exemption under
Sec. 60.4105 and no provision of law shall be construed to limit the
authority of the United States to terminate or limit such
authorization, which does not constitute a property right.
Hg allowance deduction or deduct Hg allowances means the permanent
withdrawal of Hg allowances by the Administrator from a Hg Allowance
Tracking System compliance account to account for the number of ounces
of Hg emissions from all Hg Budget units at a Hg Budget source for a
control period, determined in accordance with Sec. Sec. 60.4150
through 60.4157 and Sec. Sec. 60.4170 through 60.4176.
Hg allowances held or hold Hg allowances means the Hg allowances
recorded by the Administrator, or submitted to the Administrator for
recordation, in accordance with Sec. Sec. 60.4150 through 60.4162, in
a Hg Allowance Tracking System account.
Hg Allowance Tracking System (MATS) means the system by which the
Administrator records allocations, deductions, and transfers of Hg
allowances under the Hg Budget Trading Program.
Hg Allowance Tracking System account means an account in the Hg
Allowance Tracking System established by the Administrator for purposes
of recording the allocation, holding, transferring, or deducting of Hg
allowances.
Hg allowance transfer deadline means midnight of March 1 or, if
March 1 is not a business day, midnight of the first business day
thereafter and is the deadline by which Hg allowances must be submitted
for recordation in a Hg Budget source's compliance account, in order to
meet the source's Hg Budget emissions limitation for the control period
immediately preceding such deadline.
Hg authorized account representative means, for a Hg Budget source
or Hg Budget unit at the source, the natural person who is authorized
by the owners and operators of the source and all Hg Budget units at
the source, in accordance with this subpart, to represent and legally
bind each owner and operator in matters pertaining to the Hg Budget
Trading Program or, for a general account, the natural person who is
authorized, in accordance with this subpart, to transfer or otherwise
dispose of Hg allowances held in the general account.
Hg Budget emissions limitation means, for a Hg Budget source, the
ounce equivalent of the Hg allowances available for compliance
deduction for the source under Sec. 60.4154(a) and (b) in a control
period adjusted by deductions of such Hg allowances to account for
actual heat input under Sec. 60.4142(e) for the control period or to
account for excess emissions for a prior control period under Sec.
60.4154(d).
Hg Budget permit means the legally binding and federally
enforceable written document, or portion of such document, issued by
the permitting authority under this part, including any permit
revisions, specifying the Hg Budget Trading Program requirements
applicable to a Hg Budget source, to each Hg Budget unit at the Hg
Budget source, and to the owners and operators and the Hg authorized
account representative of the Hg Budget source and each Hg Budget unit.
Hg Budget source means a source that includes one or more Hg Budget
units.
Hg Budget Trading Program means a multi-state mercury air pollution
control and emission reduction program established by the Administrator
in accordance with this part and pursuant to Sec. 51.XX of this
chapter, as a means of reducing national mercury emissions.
Hg Budget unit means a unit that is subject to the Hg Budget
Trading Program emissions limitation under Sec. 60.4104.
Life-of-the-unit, firm power contractual arrangement means a unit
participation power sales agreement under which a utility or industrial
customer reserves, or is entitled to receive, a specified amount or
percentage of nameplate capacity and associated energy from any
specified unit and pays its proportional amount of such unit's total
costs, pursuant to a contract:
(1) For the life of the unit;
(2) For a cumulative term of no less than 30 years, including
contracts that permit an election for early termination; or
(3) For a period equal to or greater than 25 years or 70 percent of
the economic useful life of the unit determined as of the time the unit
is built, with option rights to purchase or release some portion of the
nameplate capacity and associated energy generated by the unit at the
end of the period.
Maximum design heat input means the ability of a unit to combust a
stated maximum amount of fuel per hour (in mmBtu/hr) on a steady state
basis, as specified by the manufacturer of the unit as of the unit's
initial installation and based on the physical design and physical
characteristics of the unit.
[[Page 12440]]
Maximum potential Hg emission rate means the emission rate of
mercury (in lb /10\12\ Btu) calculated in accordance with section
2.1.7.1(b) of appendix A to part 75 of this chapter, using the maximum
potential concentration of Hg under section 2.1.7.1 of appendix A to
part 75 of this chapter, and either the maximum oxygen concentration
(in percent O2) or the minimum carbon dioxide concentration
(in percent CO2), under all operating conditions of the unit
except for unit start up, shutdown, and upsets.
Maximum potential hourly heat input means an hourly heat input (in
mmBtu/hr) used for reporting purposes when a unit lacks certified
monitors to report heat input. If the unit intends to use appendix D of
part 75 of this chapter to report heat input, this value should be
calculated, in accordance with part 75 of this chapter, using the
maximum fuel flow rate and the maximum gross calorific value. If the
unit intends to use a flow monitor and a diluent gas monitor, this
value should be reported, in accordance with part 75 of this chapter,
using the maximum potential flowrate and either the maximum carbon
dioxide concentration (in percent CO2) or the minimum oxygen
concentration (in percent O2).
Maximum rated hourly heat input means a unit specific maximum
hourly heat input (in mmBtu/hr) which is the higher of the
manufacturer's maximum rated hourly heat input or the highest observed
hourly heat input.
Monitoring system means any monitoring system that meets the
requirements of this subpart, including a continuous emissions
monitoring system or an alternative monitoring system.
Nameplate capacity means the maximum electrical generating output
(in MWe) that a generator can sustain over a specified period of time
when not restricted by seasonal or other deratings as specified by the
manufacturer as of the initial installation of the unit or, if the unit
is subsequently modified, reconstructed, or repowered resulting in an
increase in maximum heat input, as specified by the person conducting
the modification, reconstruction, or repowering.
Operator means any person who operates, controls, or supervises a
Hg Budget unit or a Hg Budget source is submitted and not denied or
withdrawn and shall include, but not be limited to, any holding
company, utility system, or plant manager of such a unit or source.
Ounce means 2.8 x 10\7\ micrograms. For the purpose of determining
compliance with the Hg Budget emissions limitation, total ounces for a
control period shall be calculated as the sum of all recorded hourly
emissions (or the mass equivalent of the recorded hourly emissions
rates) in accordance with this part, with any remaining fraction of an
ounce equal to or greater than 0.50 ounce deemed to equal one ounce and
any fraction of an ounce less than 0.50 ounce deemed to equal zero
ounces.
Owner means any of the following persons:
(1) Any holder of any portion of the legal or equitable title in a
Hg Budget unit; or
(2) Any holder of a leasehold interest in a Hg Budget unit; or
(3) Any purchaser of power from a Hg Budget unit under a life-of-
the-unit, firm power contractual arrangement. However, unless expressly
provided for in a leasehold agreement, owner shall not include a
passive lessor, or a person who has an equitable interest through such
lessor, whose rental payments are not based, either directly or
indirectly, upon the revenues or income from the Hg Budget unit; or
(4) With respect to any general account, any person who has an
ownership interest with respect to the Hg allowances held in the
general account and who is subject to the binding agreement for the Hg
authorized account representative to represent that person's ownership
interest with respect to Hg allowances.
Percent monitor data availability means, for purposes of Sec.
60.4143(a)(1), total unit operating hours for which quality-assured
data were recorded under Sec. Sec. 60.4170 through 60.4176 in a
control period, divided by the total number of unit operating hours in
the control period, and multiplied by 100 percent.
Permitting authority means the State air pollution control agency,
local agency, other State agency, or other agency authorized by the
Administrator to issue or revise permits to meet the requirements of
the Hg Budget Trading Program in accordance with Sec. Sec. 60.4120
through 60.4124.
Potential electrical output capacity means 33 percent of a unit's
maximum design heat input.
Receive or receipt of means, when referring to the permitting
authority or the Administrator, to come into possession of a document,
information, or correspondence (whether sent in writing or by
authorized electronic transmission), as indicated in an official
correspondence log, or by a notation made on the document, information,
or correspondence, by the permitting authority or the Administrator in
the regular course of business.
Recordation, record, or recorded means, with regard to Hg
allowances, the movement of Hg allowances by the Administrator from one
Hg Allowance Tracking System account to another, for purposes of
allocation, transfer, or deduction.
Reference method means any direct test method of sampling and
analyzing for an air pollutant as specified in Sec. 75.22 of this
chapter.
Serial number means, when referring to Hg allowances, the unique
identification number assigned to each Hg allowance by the
Administrator, under Sec. 60.4153(f).
Source means all buildings, structures, or installations located in
one or more contiguous or adjacent properties under common control of
the same person or persons. For purposes of section 502(c) of the Clean
Air Act, a ``source,'' including a ``source'' with multiple units,
shall be considered a single ``facility.''
State means one of the 50 States or the District of Columbia that
is specified in this part.
Submit or serve means to send or transmit a document, information,
or correspondence to the person specified in accordance with the
applicable regulation:
(1) In person;
(2) By United States Postal Service; or
(3) By other means of dispatch or transmission and delivery.
Compliance with any ``submission,'' ``service,'' or ``mailing''
deadline shall be determined by the date of dispatch, transmission, or
mailing and not the date of receipt.
Title V operating permit means a permit issued under title V of the
Clean Air Act and part 70 or part 71 of this chapter.
Title V operating permit regulations means the regulations that the
Administrator has approved or issued as meeting the requirements of
title V of the Clean Air Act and part 70 or 71 of this chapter.
Unit operating day means a calendar day in which a unit combusts
any fuel.
Unit operating hour or hour of unit operation means any hour (or
fraction of an hour) during which a unit combusts any fuel.
Sec. 60.4103 Measurements, abbreviations, and acronyms.
Measurements, abbreviations, and acronyms used in this part are
defined as follows:
Btu--British thermal unit.
CO2--carbon dioxide.
Hg--mercury.
hr--hour.
kW--kilowatt electrical.
kWh--kilowatt hour.
[[Page 12441]]
mmBtu--million Btu.
MWe--megawatt electrical.
O2--oxygen.
Sec. 60.4104 Applicability.
The following units in a State shall be Hg Budget units, and any
source that includes one or more such units shall be a Hg Budget
source, subject to the requirements of this part:
(a) A coal-fired combustion unit that serves a generator of more
than 25 MW that produces electricity for sale.
(b) A coal-fired combustion 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.
Sec. 60.4105 Retired unit exemption.
(a) This section applies to any Hg Budget unit that is permanently
retired.
(b)(1) Any Hg Budget unit, that is permanently retired shall be
exempt from the Hg Budget Trading Program, except for the provisions of
this section, Sec. 60.4102, Sec. 60.4103, Sec. 60.4104, Sec.
60.4107, and Sec. Sec. 60.4130 through 60.4162.
(2) The exemption under paragraph (b)(1) of this section shall
become effective the day on which the unit is permanently retired.
Within 30 days of permanent retirement, the Hg authorized account
representative shall submit a statement to the permitting authority
otherwise responsible for administering any Hg Budget permit for the
unit. The Hg authorized account representative shall submit a copy of
the statement to the Administrator. The statement shall state, in a
format prescribed by the permitting authority, that the unit is
permanently retired and will comply with the requirements of paragraph
(c) of this section.
(3) After receipt of the notice under paragraph (b)(2) of this
section, the permitting authority will amend any permit covering the
source at which the unit is located to add the provisions and
requirements of the exemption under paragraphs (b)(1) and (c) of this
section.
(c) Special provisions. (1) A unit exempt under this section shall
not emit any mercury, starting on the date that the exemption takes
effect.
(2) The Permitting Authority will allocate Hg allowances under
Sec. Sec. 60.4140 through 60.4142 to a unit exempt under this section.
(3) For a period of 5 years from the date the records are created,
the owners and operators of a unit exempt under this section shall
retain at the source that includes the unit, records demonstrating that
the unit is permanently retired. The 5-year period for keeping records
may be extended for cause, at any time prior to the end of the period,
in writing by the permitting authority or the Administrator. The owners
and operators bear the burden of proof that the unit is permanently
retired.
(4) The owners and operators and, to the extent applicable, the Hg
authorized account representative of a unit exempt under this section
shall comply with the requirements of the Hg Budget Trading Program
concerning all periods for which the exemption is not in effect, even
if such requirements arise, or must be complied with, after the
exemption takes effect.
(5) A unit exempt under this section and located at a source that
is required, or but for this exemption would be required, to have a
title V operating permit shall not resume operation unless the Hg
authorized account representative of the source submits a complete Hg
Budget permit application under Sec. 60.4122 for the unit not less
than 18 months (or such lesser time provided by the permitting
authority) before the later of January 1, 2010 or the date on which the
unit resumes operation.
(6) On the earlier of the following dates, a unit exempt under
paragraph (b) of this section shall lose its exemption:
(i) The date on which the Hg authorized account representative
submits a Hg Budget permit application under paragraph (c)(5) of this
section;
(ii) The date on which the Hg authorized account representative is
required under paragraph (c)(5) of this section to submit a Hg Budget
permit application; or
(iii) The date on which the unit resumes operation, if the Hg
authorized account representative is not required to submit a Hg Budget
permit application for the unit.
(7) For the purpose of applying monitoring requirements under
Sec. Sec. 60.4170 through 60.4176 of this part, a unit that loses its
exemption under this section shall be treated as a unit that commences
operation or commercial operation on the first date on which the unit
resumes operation.
Sec. 60.4106 Standard requirements.
(a) Permit requirements. (1) The Hg authorized account
representative of each Hg Budget source required to have a title V
operating permit and each Hg Budget unit required to have a title V
operating permit at the source shall:
(i) Submit to the permitting authority a complete Hg Budget permit
application under Sec. 60.4122 in accordance with the deadlines
specified in Sec. 60.4121(b) and (c);
(ii) Submit in a timely manner any supplemental information that
the permitting authority determines is necessary in order to review a
Hg Budget permit application and issue or deny a Hg Budget permit.
(2) The owners and operators of each Hg Budget source required to
have a title V operating permit and each Hg Budget unit required to
have a title V operating permit at the source shall have a Hg Budget
permit issued by the permitting authority and operate the unit in
compliance with such Hg Budget permit.
(3) The owners and operators of a Hg Budget source that is not
otherwise required to have a title V operating permit are not required
to submit a Hg Budget permit application, and to have a Hg Budget
permit, under Sec. Sec. 60.4120 through 60.4124 for such Hg Budget
source.
(b) Monitoring requirements. (1) The owners and operators and, to
the extent applicable, the Hg authorized account representative of each
Hg Budget source and each Hg Budget unit at the source shall comply
with the monitoring requirements of Sec. Sec. 60.4170 through 60.4176.
(2) The emissions measurements recorded and reported in accordance
with Sec. Sec. 60.4170 through 60.4176 shall be used to determine
compliance by the unit with the Hg Budget emissions limitation under
paragraph (c) of this section.
(c) Mercury emission requirements. (1) As of the Hg allowance
transfer deadline for a control period, the owners and operators of
each Hg Budget source and each Hg Budget unit at the source shall hold
Hg allowances available for compliance deductions under Sec.
60.4154(a) and(b) as of the Hg allowance transfer deadline, in the
source's compliance account in an amount not less than the total Hg
emissions for the control period from all Hg Budget units at the
source, as determined in accordance with this subpart, plus any amount
necessary to account for actual heat input under Sec. 60.4142(e) for
the control period or to account for excess emissions for a prior
control period under Sec. 60.4154(d).
(2) Each ounce of mercury emitted in excess of the Hg Budget
emissions limitation shall constitute a separate violation of this
part, the Clean Air Act, and applicable State law.
(3) A Hg Budget unit shall be subject to the requirements under
paragraph (c)(1) of this section starting on the later of January 1,
2010 or the date on which the unit commences operation.
[[Page 12442]]
(4) Hg allowances shall be held in, deducted from, or transferred
among Hg Allowance Tracking System accounts in accordance with
Sec. Sec. 60.4140 through 60.4162.
(5) A Hg allowance shall not be deducted, in order to comply with
the requirements under paragraph (c)(1) of this section, for a control
period in a year prior to the year for which the Hg allowance was
allocated.
(6) A Hg allowance allocated by the Administrator under the Hg
Budget Trading Program is a limited authorization to emit one ounce of
mercury in accordance with the Hg Budget Trading Program. No provision
of the Hg Budget Trading Program, the Hg Budget permit application, the
Hg Budget permit and no provision of law shall be construed to limit
the authority of the United States to terminate or limit such
authorization.
(7) A Hg allowance allocated by the Administrator under the Hg
Budget Trading Program does not constitute a property right.
(8) Upon recordation by the Administrator under Sec. Sec. 60.4150
through 60.4162, every allocation, transfer, or deduction of a Hg
allowance to or from a Hg Budget unit's compliance account is
incorporated automatically in any Hg Budget permit of the Hg Budget
unit.
(d) Excess emissions requirements. (1) The owners and operators of
a Hg Budget unit that has excess emissions in any control period shall:
(i) Surrender the Hg allowances required for deduction under Sec.
60.4154(d)(1); and
(ii) Pay any fine, penalty, or assessment or comply with any other
remedy imposed under Sec. 60.4154(d)(3).
(e) Recordkeeping and reporting requirements. (1) Unless otherwise
provided, the owners and operators of the Hg Budget source and each Hg
Budget unit at the source shall keep on site at the source each of the
following documents for a period of 5 years from the date the document
is created. This period may be extended for cause, at any time prior to
the end of 5 years, in writing by the permitting authority or the
Administrator.
(i) The account certificate of representation under Sec. 60.4113
for the Hg authorized account representative for the source and each Hg
Budget unit at the source and all documents that demonstrate the truth
of the statements in the account certificate of representation;
provided that the certificate and documents shall be retained on site
at the source beyond such 5-year period until such documents are
superseded because of the submission of a new account certificate of
representation under Sec. 60.4113 changing the Hg authorized account
representative.
(ii) All emissions monitoring information, in accordance with
Sec. Sec. 60.4170 through 60.4176; provided that to the extent that
Sec. Sec. 60.4170 through 60.4176 of this part provides for a 3-year
period for recordkeeping, the 3-year period shall apply.
(iii) Copies of all reports, compliance certifications, and other
submissions and all records made or required under the Hg Budget
Trading Program.
(iv) Copies of all documents used to complete a Hg Budget permit
application and any other submission under the Hg Budget Trading
Program or to demonstrate compliance with the requirements of the Hg
Budget Trading Program.
(2) The Hg authorized account representative of a Hg Budget source
and each Hg Budget unit at the source shall submit the reports and
compliance certifications required under the Hg Budget Trading Program,
including those under Sec. Sec. 60.4130 through 60.4131 and Sec. Sec.
60.4170 through 60.4176.
(f) Liability. (1) Any person who knowingly violates any
requirement or prohibition of the Hg Budget Trading Program, a Hg
Budget permit, or an exemption under Sec. 60.4105 shall be subject to
enforcement pursuant to applicable State or Federal law.
(2) Any person who knowingly makes a false material statement in
any record, submission, or report under the Hg Budget Trading Program
shall be subject to criminal enforcement pursuant to the applicable
State or Federal law.
(3) No permit revision shall excuse any violation of the
requirements of the Hg Budget Trading Program that occurs prior to the
date that the revision takes effect.
(4) Each Hg Budget source and each Hg Budget unit shall meet the
requirements of the Hg Budget Trading Program.
(5) Any provision of the Hg Budget Trading Program that applies to
a Hg Budget source or the Hg authorized account representative of a Hg
Budget source shall also apply to the owners and operators of such
source and of the Hg Budget units at the source.
(6) Any provision of the Hg Budget Trading Program that applies to
a Hg Budget unit or the Hg authorized account representative of a Hg
budget unit shall also apply to the owners and operators of such unit.
Except with regard to the requirements applicable to units with a
common stack under Sec. Sec. 60.4170 through 60.4176, the owners and
operators and the Hg authorized account representative of one Hg Budget
unit shall not be liable for any violation by any other Hg Budget unit
of which they are not owners or operators or the Hg authorized account
representative and that is located at a source of which they are not
owners or operators or the Hg authorized account representative.
(g) Effect on other authorities. No provision of the Hg Budget
Trading Program, a Hg Budget permit application, a Hg Budget permit, or
an exemption under Sec. 60.4105 shall be construed as exempting or
excluding the owners and operators and, to the extent applicable, the
Hg authorized account representative of a Hg Budget source or Hg Budget
unit from compliance with any other provision of the applicable,
approved State implementation plan, a federally enforceable permit, or
the Clean Air Act.
Sec. 60.4107 Computation of time.
(a) Unless otherwise stated, any time period scheduled, under the
Hg Budget Trading Program, to begin on the occurrence of an act or
event shall begin on the day the act or event occurs.
(b) Unless otherwise stated, any time period scheduled, under the
Hg Budget Trading Program, to begin before the occurrence of an act or
event shall be computed so that the period ends the day before the act
or event occurs.
(c) Unless otherwise stated, if the final day of any time period,
under the Hg Budget Trading Program, falls on a weekend or a State or
Federal holiday, the time period shall be extended to the next business
day.
Hg Authorized Account Representative for Hg Budget Sources
Sec. 60.4110 Authorization and responsibilities of Hg authorized
account representative.
(a) Except as provided under Sec. 60.4111, each Hg Budget source,
including all Hg Budget units at the source, shall have one and only
one Hg authorized account representative, with regard to all matters
under the Hg Budget Trading Program concerning the source or any Hg
Budget unit at the source.
(b) The Hg authorized account representative of the Hg Budget
source shall be selected by an agreement binding on the owners and
operators of the source and all Hg Budget units at the source.
(c) Upon receipt by the Administrator of a complete account
certificate of representation under Sec. 60.4113, the Hg authorized
account representative of the source shall represent and, by his or her
representations, actions, inactions, or submissions, legally bind each
owner and operator of the Hg Budget source
[[Page 12443]]
represented and each Hg Budget unit at the source in all matters
pertaining to the Hg Budget Trading Program, not withstanding any
agreement between the Hg authorized account representative and such
owners and operators. The owners and operators shall be bound by any
decision or order issued to the Hg authorized account representative by
the permitting authority, the Administrator, or a court regarding the
source or unit.
(d) No Hg Budget permit shall be issued, and no Hg Allowance
Tracking System account shall be established for a Hg Budget unit at a
source, until the Administrator has received a complete account
certificate of representation under Sec. 60.4113 for a Hg authorized
account representative of the source and the Hg Budget units at the
source.
(e)(1) Each submission under the Hg Budget Trading Program shall be
submitted, signed, and certified by the Hg authorized account
representative for each Hg Budget source on behalf of which the
submission is made. Each such submission shall include the following
certification statement by the Hg authorized account representative:
``I am authorized to make this submission on behalf of the owners and
operators of the Hg Budget sources or Hg Budget units for which the
submission is made. I certify under penalty of law that I have
personally examined, and am familiar with, the statements and
information submitted in this document and all its attachments. Based
on my inquiry of those individuals with primary responsibility for
obtaining the information, I certify that the statements and
information are to the best of my knowledge and belief true, accurate,
and complete. I am aware that there are significant penalties for
submitting false statements and information or omitting required
statements and information, including the possibility of fine or
imprisonment.''
(2) The permitting authority and the Administrator will accept or
act on a submission made on behalf of owner or operators of a Hg Budget
source or a Hg Budget unit only if the submission has been made,
signed, and certified in accordance with paragraph (e)(1) of this
section.
Sec. 60.4111 Alternate Hg authorized account representative.
(a) An account certificate of representation may designate one and
only one alternate Hg authorized account representative who may act on
behalf of the Hg authorized account representative. The agreement by
which the alternate Hg authorized account representative is selected
shall include a procedure for authorizing the alternate Hg authorized
account representative to act in lieu of the Hg authorized account
representative.
(b) Upon receipt by the Administrator of a complete account
certificate of representation under Sec. 60.4113, any representation,
action, inaction, or submission by the alternate Hg authorized account
representative shall be deemed to be a representation, action,
inaction, or submission by the Hg authorized account representative.
(c) Except in this section and Sec. Sec. 60.4110(a), 60.4112,
60.4113, and 60.4151, whenever the term ``Hg authorized account
representative'' is used in this subpart, the term shall be construed
to include the alternate Hg authorized account representative.
Sec. 60.4112 Changing Hg authorized account representative and
alternate Hg authorized account representative; changes in owners and
operators.
(a) Changing Hg authorized account representative. The Hg
authorized account representative may be changed at any time upon
receipt by the Administrator of a superseding complete account
certificate of representation under Sec. 60.4113. Notwithstanding any
such change, all representations, actions, inactions, and submissions
by the previous Hg authorized account representative prior to the time
and date when the Administrator receives the superseding account
certificate of representation shall be binding on the new Hg authorized
account representative and the owners and operators of the Hg Budget
source and the Hg Budget units at the source.
(b) Changing alternate Hg authorized account representative. The
alternate Hg authorized account representative may be changed at any
time upon receipt by the Administrator of a superseding complete
account certificate of representation under Sec. 60.4113.
Notwithstanding any such change, all representations, actions,
inactions, and submissions by the previous alternate Hg authorized
account representative prior to the time and date when the
Administrator receives the superseding account certificate of
representation shall be binding on the new alternate Hg authorized
account representative and the owners and operators of the Hg Budget
source and the Hg Budget units at the source.
(c) Changes in owners and operators. (1) In the event a new owner
or operator of a Hg Budget source or a Hg Budget unit is not included
in the list of owners and operators submitted in the account
certificate of representation under Sec. 60.4113, such new owner or
operator shall be deemed to be subject to and bound by the account
certificate of representation, the representations, actions, inactions,
and submissions of the Hg authorized account representative and any
alternate Hg authorized account representative of the source or unit,
and the decisions, orders, actions, and inactions of the permitting
authority or the Administrator, as if the new owner or operator were
included in such list.
(2) Within 30 days following any change in the owners and operators
of a Hg Budget source or a Hg Budget unit, including the addition of a
new owner or operator, the Hg authorized account representative or
alternate Hg authorized account representative shall submit a revision
to the account certificate of representation under Sec. 60.4113
amending the list of owners and operators to include the change.
Sec. 60.4113 Account certificate of representation.
(a) A complete account certificate of representation for a Hg
authorized account representative or an alternate Hg authorized account
representative shall include the following elements in a format
prescribed by the Administrator:
(1) Identification of the Hg Budget source and each Hg Budget unit
at the source for which the account certificate of representation is
submitted.
(2) The name, address, e-mail address (if any), telephone number,
and facsimile transmission number (if any) of the Hg authorized account
representative and any alternate Hg authorized account representative.
(3) A list of the owners and operators of the Hg Budget source and
of each Hg Budget unit at the source.
(4) The following certification statement by the Hg authorized
account representative and any alternate Hg authorized account
representative: ``I certify that I was selected as the Hg authorized
account representative or alternate Hg authorized account
representative, as applicable, by an agreement binding on the owners
and operators of the Hg Budget source and each Hg Budget unit at the
source. I certify that I have all the necessary authority to carry out
my duties and responsibilities under the Hg Budget Trading Program on
behalf of the owners and operators of the Hg Budget source and of each
Hg Budget unit at the source and that each such owner and operator
shall be fully bound by my representations, actions, inactions, or
submissions and by any decision or order issued to me by the permitting
[[Page 12444]]
authority, the Administrator, or a court regarding the source or
unit.''
(5) The signature of the Hg authorized account representative and
any alternate Hg authorized account representative and the dates
signed.
(b) Unless otherwise required by the permitting authority or the
Administrator, documents of agreement referred to in the account
certificate of representation shall not be submitted to the permitting
authority or the Administrator. Neither the permitting authority nor
the Administrator shall be under any obligation to review or evaluate
the sufficiency of such documents, if submitted.
Sec. 60.4114 Objections concerning Hg authorized account
representative.
(a) Once a complete account certificate of representation under
Sec. 60.4113 has been submitted and received, the permitting authority
and the Administrator will rely on the account certificate of
representation unless and until a superseding complete account
certificate of representation under Sec. 60.4113 is received by the
Administrator.
(b) Except as provided in Sec. 60.4112(a) or (b), no objection or
other communication submitted to the permitting authority or the
Administrator concerning the authorization, or any representation,
action, inaction, or submission of the Hg authorized account
representative shall affect any representation, action, inaction, or
submission of the Hg authorized account representative or the finality
of any decision or order by the permitting authority or the
Administrator under the Hg Budget Trading Program.
(c) Neither the permitting authority nor the Administrator will
adjudicate any private legal dispute concerning the authorization or
any representation, action, inaction, or submission of any Hg
authorized account representative, including private legal disputes
concerning the proceeds of Hg allowance transfers.
Permits
Sec. 60.4120 General Hg Budget Trading Program permit requirements.
(a) For each Hg Budget source required to have a title V operating
permit, such permit shall include a Hg Budget permit administered by
the permitting authority for the title V operating permit. The Hg
Budget portion of the title V permit shall be administered in
accordance with the permitting authority's title V operating permits
regulations promulgated under part 70 or 71 of this chapter, except as
provided otherwise by this subpart or subpart I of this part.
(b) Each Hg Budget permit shall contain all applicable Hg Budget
Trading Program requirements and shall be a complete and segregable
portion of the title V operating permit under paragraph (a) of this
section.
Sec. 60.4121 Submission of Hg Budget permit applications.
(a) Duty to apply. The Hg authorized account representative of any
Hg Budget source required to have a title V operating permit shall
submit to the permitting authority a complete Hg Budget permit
application under Sec. 60.4122 by the applicable deadline in paragraph
(b) of this section.
(b) Application deadline. (1) For any source, with one or more Hg
Budget units under Sec. 60.4104(a) that commence operation before
[DATE OF PUBLICATION OF FINAL RULE IN THE Federal Register], the Hg
authorized account representative shall submit a complete Hg Budget
permit application under Sec. 60.4122 covering such Hg Budget units to
the permitting authority at least 18 months (or such lesser time
provided by the permitting authority) before January 1, 2010.
(2) For any source, with any Hg Budget unit under Sec. 60.4104(a)
that commences operation on or after [DATE OF PUBLICATION OF FINAL RULE
IN THE Federal Register], the Hg authorized account representative
shall submit a complete Hg Budget permit application under Sec.
60.4122 covering such Hg Budget unit to the permitting authority at
least 18 months (or such lesser time provided by the permitting
authority) before the later of January 1, 2010 or the date on which the
Hg Budget unit commences operation.
(c) Duty to Reapply. For a Hg Budget source required to have a
title V operating permit, the Hg authorized account representative
shall submit a complete Hg Budget permit application under Sec.
60.4122 for the Hg Budget source covering the Hg Budget units at the
source in accordance with the permitting authority's title V operating
permits regulations addressing operating permit renewal.
Sec. 60.4122 Information requirements for Hg Budget permit
applications.
A complete Hg Budget permit application shall include the following
elements concerning the Hg Budget source for which the application is
submitted, in a format prescribed by the permitting authority:
(a) Identification of the Hg Budget source, including plant name
and the ORIS (Office of Regulatory Information Systems) or facility
code assigned to the source by the Energy Information Administration,
if applicable;
(b) Identification of each Hg Budget unit at the Hg Budget source
and whether it is a Hg Budget unit under Sec. 60.4104(a); and
(c) The standard requirements under Sec. 60.4106.
Sec. 60.4123 Hg Budget permit contents.
(a) Each Hg Budget permit will contain, in a format prescribed by
the permitting authority, all elements required for a complete Hg
Budget permit application under Sec. 60.4122.
(b) Each Hg Budget permit is deemed to incorporate automatically
the definitions of terms under Sec. 60.4102 and, upon recordation by
the Administrator under Sec. Sec. 60.4150 through 60.4162, every
allocation, transfer, or deduction of a Hg allowance to or from the
compliance accounts of the Hg Budget units covered by the permit.
Sec. 60.4124 Hg Budget permit revisions.
Except as provided in Sec. 60.4123(b), the permitting authority
will revise the Hg Budget permit, as necessary, in accordance with the
permitting authority's title V operating permits regulations addressing
permit revisions.
Compliance Certification
Sec. 60.4130 Compliance certification report.
(a) Applicability and deadline. For each control period in which
one or more Hg Budget units at a source are subject to the Hg Budget
emissions limitation, the Hg authorized account representative of the
source shall submit to the permitting authority and the Administrator
by March 1 of the immediately following control period, a compliance
certification report for each source covering all such units.
(b) Contents of report. The Hg authorized account representative
shall include in the compliance certification report under paragraph
(a) of this section the following elements, in a format prescribed by
the Administrator, concerning each unit at the source and subject to
the Hg Budget emissions limitation for the control period covered by
the report:
(1) Identification of each Hg Budget unit;
(2) At the Hg authorized account representative's option, the
serial numbers of the Hg allowances that are to be deducted from each
source's compliance account under Sec. 60.4154 for the control period;
and
(3) The compliance certification under paragraph (c) of this
section.
(c) Compliance certification. In the compliance certification
report under
[[Page 12445]]
paragraph (a) of this section, the Hg authorized account representative
shall certify, based on reasonable inquiry of those persons with
primary responsibility for operating the source and the Hg Budget units
at the source in compliance with the Hg Budget Trading Program, whether
each Hg Budget unit for which the compliance certification is submitted
was operated during the control period covered by the report in
compliance with the requirements of the Hg Budget Trading Program
applicable to the unit, including:
(1) Whether the unit was operated in compliance with the Hg Budget
emissions limitation;
(2) Whether the monitoring plan that governs the unit has been
maintained to reflect the actual operation and monitoring of the unit
and contains all information necessary to attribute Hg emissions to the
unit, in accordance with Sec. Sec. 60.4170 through 60.4176;
(3) Whether all the Hg emissions from the unit, or a group of units
(including the unit) using a common stack, were monitored or accounted
for through the missing data procedures and reported in the quarterly
monitoring reports, including whether conditional data were reported in
the quarterly reports in accordance with Sec. Sec. 60.4170 through
60.4176. If conditional data were reported, the owner or operator shall
indicate whether the status of all conditional data has been resolved
and all necessary quarterly report resubmissions have been made;
(4) Whether the facts that form the basis for certification under
this subpart of each monitor at the unit or a group of units (including
the unit) using a common stack, or for using an excepted monitoring
method or alternative monitoring method approved under this subpart, if
any, have changed; and
(5) If a change is required to be reported under paragraph (c)(4)
of this section, specify the nature of the change, the reason for the
change, when the change occurred, and how the unit's compliance status
was determined subsequent to the change, including what method was used
to determine emissions when a change mandated the need for monitor
recertification.
Sec. 60.4131 Administrator's action on compliance certifications.
(a) The Administrator may review and conduct independent audits
concerning any compliance certification or any other submission under
the Hg Budget Trading Program and make appropriate adjustments of the
information in the compliance certifications or other submissions.
(b) The Administrator may deduct Hg allowances from or transfer Hg
allowances to a source's compliance account based on the information in
the compliance certifications or other submissions, as adjusted under
paragraph (a) of this section.
Hg Allowance Allocations
Sec. 60.4140 State trading program budget.
(a) For each state listed in paragraph (b) of this section, the
state plan required under subpart B, 40 CFR part 60, and this section
shall limit total annual Hg emissions from Hg Budget units to the
amounts specified in paragraph (b) of this section.
(b) The state-by-state trading program budgets for annual
allocations for 2010 through 2017 and for 2018 and thereafter are
respectively as follows:
------------------------------------------------------------------------
Budget (tons)
-----------------------
State 2018 and
2010-2017 thereafter
------------------------------------------------------------------------
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
------------------------------------------------------------------------
Sec. 60.4141 Timing requirements for Hg allowance allocations.
(a) By October 31, 2006, the permitting authority will submit to
the Administrator the Hg allowance allocations, in format prescribed by
the Administrator and in accordance with Sec. 60.4142, for the control
periods in 2010, 2011, 2012, 2013, and 2014. If the permitting
authority fails to submit to the Administrator the Hg allowance
allocations in accordance with this paragraph (a), the Administrator
will allocate Hg allowances for the applicable control periods, in
accordance with Sec. 60.4142, within 60 days of the deadline for
submission by the permitting authority.
(b) By October 31, 2009 and October 31 of each year thereafter, the
permitting authority will submit to the Administrator the Hg allowance
allocations, in a format prescribed by the Administrator and in
accordance with Sec. 60.4142, for the control period in the year that
is 6 years after the year of the applicable deadline for submission
under this paragraph (b). If the permitting authority fails to submit
to the Administrator the Hg allowance allocations in accordance with
this paragraph (b), the Administrator will allocate Hg allowances for
the applicable control period, in accordance with Sec. 60.4142, within
60 days of the applicable deadline for submission by the permitting
authority.
Sec. 60.4142 Hg allowance allocations.
(a)(1) The baseline heat input (in mmBtu) used for calculating Hg
allowance allocations for each Hg Budget unit under Sec. 60.4104 will
be:
(i) For units that commenced operation before January 1, 2000 the
average of the three highest amounts of the unit's annual heat input
for 1998 through 2002 and multiplied by:
(A) 3.0, for the portion of such average heat input that equals the
unit's average annual combustion of lignite during 1999,
(B) 1.25, for the portion of such average heat input that equals
the unit's average annual combustion of subbituminous coal during 1999,
(C) 1.0, for the portion of such average heat input that is not
covered by
[[Page 12446]]
paragraph (a)(1)(i)(A) or (B) of this section.
(ii) For units that commence operation on or after January 1, 2000
and operate during five years or more, the average of the three highest
amounts of the unit's total converted annual heat input over the first
five years during which the unit operates.
(2)(i) A unit's annual heat input for a year specified under
paragraph (a)(1)(i) of this section will be determined in accordance
with part 75 of this chapter, if the Hg Budget unit was otherwise
subject to the requirements of part 75 of this chapter for the year, or
will be based on the best available data reported to the permitting
authority for the unit, if the unit was not otherwise subject to the
requirements of part 75 of this chapter for the year.
(ii) A unit's converted annual heat input for a year specified
under paragraph (a)(1)(ii) of this section equals the gross electrical
output of the generator or generators served by the unit multiplied by
8,000 Btu/kWh, plus, for a cogeneration unit, one half of the unit's
gross process steam output multiplied by 8,000 Btu/kWh. If the
generator is served by two or more units, then the gross electrical
output of the generator will be attributed to each unit in proportion
to the unit's heat input.
(b) For each control period under Sec. 60.4141, the permitting
authority will allocate to all Hg Budget units under Sec. 60.4104 in
the State that have operated for at least five years a total amount of
Hg allowances equal to 98 percent of the ounces of Hg emissions in the
State trading program budget under Sec. 60.4140 (except as provided in
Sec. 60.4143) in accordance with the following procedures:
(1) The permitting authority will allocate Hg allowances to each Hg
Budget unit in an amount determined by multiplying the allocation
amount in State trading budget by the ratio of the baseline heat input
of such unit to the total amount of baseline heat input of all affected
units in the State (as calculated in Sec. 60.4142(a)(1))
(2) If the initial total number of Hg allowances allocated to all
Hg Budget units in the State for a control period under paragraph
(b)(1) of this section does not equal 98 percent of the amount of
ounces of Hg emissions in the State trading program budget, the
permitting authority will adjust the total amount of Hg allowances
allocated to all such Hg Budget units for the control period under
paragraph (b)(1) of this section so that the total amount of Hg
allowances allocated equals 98 percent of the amount of ounces of Hg
emissions in the State trading program budget. This adjustment will be
made by: Multiplying each unit's allocation by the total amount of Hg
allowances allocated under paragraph (b)(1) of this section divided by
98 percent of the amount of ounces of Hg emissions in the State trading
program budget, and rounding to the nearest whole allowance as
appropriate.
(c) For each control period under Sec. 60.4141, the permitting
authority will allocate Hg allowances to Hg Budget units under Sec.
60.4104 in the State that commenced operation on or after January 1,
2000 and have operated or operate during less than five years, in
accordance with the following procedures:
(1) The permitting authority will establish a separate allocation
set-aside for each control period. Each allocation set-aside will be
allocated Hg allowances equal to 2 percent of the amount of ounces of
Hg emissions in the State trading program budget under Sec. 60.4140.
(2) The Hg authorized account representative of a Hg Budget unit
under paragraph (c) of this section may submit to the permitting
authority a request, in writing or in a format specified by the
permitting authority, to be allocated Hg allowances for no more than
five consecutive control periods under Sec. 60.4141, starting with the
control period during which the Hg Budget unit is projected to commence
operation. The Hg allowance allocation request must be submitted prior
to January 1 of the first control period for which the Hg allowance
allocation is requested and after the date on which the permitting
authority issues a permit to construct the Hg Budget unit.
(3) In a Hg allowance allocation request under paragraph (c)(2) of
this section, the Hg authorized account representative may request for
a control period Hg allowances in an amount that does not exceed the
unit's mercury emissions rate limitation under Sec. 60.45a of this
chapter (in lb/GWh) multiplied by the Hg Budget unit's maximum design
output (in GW) multiplied by the number of hours remaining in the
control period starting with the first day in the control period on
which the unit is projected to operate multiplied by 0.90.
(4) The permitting authority will review, and allocate Hg
allowances pursuant to, Hg allowance allocation requests under
paragraph (c)(2) of this section in the order that the requests are
received by the permitting authority.
(i) Upon receipt of a Hg allowance allocation request, the
permitting authority will determine whether, and will make any
necessary adjustments to the request to ensure that, the control period
and the amount of allowances specified are consistent with the
requirements of paragraphs (c)(2) and (3) of this section.
(ii) If the allocation set-aside for the control period for which
Hg allowances are requested has an amount of Hg allowances not less
than the amount requested (as adjusted under paragraph (c)(4)(i) of
this section), the permitting authority will allocate the full,
adjusted amount of the Hg allowances requested to the Hg Budget unit.
(iii) If the allocation set-aside for the control period for which
Hg allowances are requested has a smaller amount of Hg allowances than
the amount requested (as adjusted under paragraph (b)(4)(i) of this
section), the permitting authority will deny in part the request and
allocate only the remaining amount of Hg allowances in the allocation
set-aside to the Hg Budget unit.
(iv) Once an allocation set-aside for a control period has been
depleted of all Hg allowances, the permitting authority will deny, and
will not allocate any Hg allowances pursuant to, any Hg allowance
allocation requests under which Hg allowances have not already been
allocated for the control period.
(5) Within 60 days of receipt of a Hg allowance allocation request,
the permitting authority will take appropriate action under paragraph
(c)(4) of this section and notify the Hg authorized account
representative that submitted the request and the Administrator of the
amount of Hg allowances (if any) allocated for the control period to
the Hg Budget unit.
(d) For a Hg Budget unit that is allocated Hg allowances under
paragraph (c) of this section for a control period, the Administrator
will deduct Hg allowances under Sec. 60.4154(b) to account for the
actual utilization of the unit during the control period, using the
following formula, provided that the amount of Hg allowances to be
deducted shall be zero if the amount calculated is less than zero:
Unit's Hg allowances deducted for actual utilization = (Unit's Hg
allowances allocated for control period) - (Unit's actual control
period utilization x Unit's mercury emission rate limitation under
Sec. 60.45a of this chapter)
Where:
``Unit's Hg allowances allocated for control period'' is the amount of
Hg allowances allocated to the unit for the control period under
paragraph (c) of this section.
[[Page 12447]]
``Unit's actual control period utilization'' is the utilization (in
kwh), as defined in Sec. 60.4102, of the unit during the control
period.
(e) The permitting authority will reallocate any Hg allowances
deducted by the Administrator in accordance with paragraph (d) of this
section, pursuant to any Hg allowance allocation requests that were
originally denied in whole or in part under paragraph (c)(4)(iii) or
(iv) of this section as follows:
(1) Such Hg allowance allocation requests will be considered in the
order that they were received by the permitting authority.
(2) The amount of Hg allowances reallocated pursuant to each such
Hg allowance allocation request will equal the unit's actual control
period utilization multiplied by the unit's mercury emission rate
limitation under Sec. 60.45a of this chapter, except as provided under
paragraph (e)(3) of this section.
(3) As each such Hg allowance request is considered for
reallocation, if fewer Hg allowances remain available for reallocation
pursuant to an Hg allowance allocation request than the amount of Hg
allowances under paragraph (e)(2) of this section, then all of the Hg
allowances remaining available for reallocation will be reallocated
pursuant to such Hg allowance allocation request.
(4) The permitting authority will notify the Hg authorized account
representative that submitted the request and the Administrator of the
amount of Hg allowances (if any) allocated under this paragraph.
(f) If, after completion of the procedures under paragraphs (c) and
(e) of this section, there are remaining unallocated Hg allowances from
the allocation set-aside for a control period remain, the permitting
authority shall reallocate to each Hg Budget unit that was allocated Hg
allowances under paragraph (b) an amount of Hg allowances equal to the
total amount of such remaining unallocated Hg allowances multiplied by
the unit's allocation under paragraph (b) of this section divided by 98
percent of the amount of ounces of Hg emissions in the State trading
program budget and rounding to the nearest whole allowance as
appropriate.
Sec. 60.4143 Hg safety valve provisions.
(a) Any person may purchase Hg allowances from the permitting
authority during any control period. Each mercury allowance shall be
sold for $2,187.50, with such price adjusted for inflation based on the
Consumer Price Index on the January 1, 2004 and annually thereafter.
(b) The proceeds from any sales of Hg allowances under paragraph
(a) of this section shall be deposited in the State Treasury.
(c) Each Hg allowance purchased under paragraph (a) of this section
shall be taken from, and reduce, the total amount of Hg allowances
available for allocation under Sec. 60.4142 (b) for the first control
period after the control period during which such Hg allowance is
purchased and for which Hg allowances have not already been allocated
under Sec. 60.4142 (b).
(d) Notwithstanding paragraph (c) of this section, each Hg
allowance purchased under paragraph (a) of this section shall be
treated as being allocated for the control period during which such Hg
allowance was purchased or for the immediately preceding control
period.
Hg Allowance Tracking System
Sec. 60.4150 Hg Allowance Tracking System accounts.
(a) Nature and function of compliance accounts. Consistent with
Sec. 60.4151(a), the Administrator will establish one compliance
account for each Hg Budget source with one or more Hg Budget units.
Allocations of Hg allowances pursuant to this subpart, and deductions
or transfers of Hg allowances pursuant to Sec. 60.4131, Sec. 60.4154,
Sec. 60.4156, or Sec. Sec. 60.4160 through 60.4162 will be recorded
in compliance accounts in accordance with Sec. Sec. 60.4151 through
60.4157.
(b) Nature and function of general accounts. Consistent with Sec.
60.4151(b), the Administrator will establish, upon request, a general
account for any person. Transfers of allowances pursuant to Sec. Sec.
60.4160 through 60.4162 will be recorded in general accounts in
accordance with this subpart.
Sec. 60.4151 Establishment of accounts.
(a) Compliance accounts. Upon receipt of a complete account
certificate of representation under Sec. 60.4113, the Administrator
will establish a compliance account for each Hg Budget source for which
the account certificate of representation was submitted.
(b) General accounts.
(1) Application for general account.
(i) Any person may apply to open a general account for the purpose
of holding and transferring allowances. An application for a general
account may designate one and only one Hg authorized account
representative and one and only one alternate Hg authorized account
representative who may act on behalf of the Hg authorized account
representative. The agreement by which the alternate Hg authorized
account representative is selected shall include a procedure for
authorizing the alternate Hg authorized account representative to act
in lieu of the Hg authorized account representative. A complete
application for a general account shall be submitted to the
Administrator and shall include the following elements in a format
prescribed by the Administrator:
(A) Name, mailing address, e-mail address (if any), telephone
number, and facsimile transmission number (if any) of the Hg authorized
account representative and any alternate Hg authorized account
representative;
(B) At the option of the Hg authorized account representative,
organization name and type of organization;
(C) A list of all persons subject to a binding agreement for the Hg
authorized account representative and any alternate Hg authorized
account representative to represent their ownership interest with
respect to the allowances held in the general account;
(D) The following certification statement by the Hg authorized
account representative and any alternate Hg authorized account
representative: ``I certify that I was selected as the Hg authorized
account representative or the Hg alternate authorized account
representative, as applicable, by an agreement that is binding on all
persons who have an ownership interest with respect to allowances held
in the general account. I certify that I have all the necessary
authority to carry out my duties and responsibilities under the Hg
Budget Trading Program on behalf of such persons and that each such
person shall be fully bound by my representations, actions, inactions,
or submissions and by any order or decision issued to me by the
Administrator or a court regarding the general account.''
(E) The signature of the Hg authorized account representative and
any alternate Hg authorized account representative and the dates
signed.
(ii) Unless otherwise required by the permitting authority or the
Administrator, documents of agreement referred to in the application
for a general account shall not be submitted to the permitting
authority or the Administrator. Neither the permitting authority nor
the Administrator shall be under any obligation to review or evaluate
the sufficiency of such documents, if submitted.
(2) Authorization of Hg authorized account representative. Upon
receipt by the Administrator of a complete
[[Page 12448]]
application for a general account under paragraph (b)(1) of this
section:
(i) The Administrator will establish a general account for the
person or persons for whom the application is submitted.
(ii) The Hg authorized account representative and any alternate Hg
authorized account representative for the general account shall
represent and, by his or her representations, actions, inactions, or
submissions, legally bind each person who has an ownership interest
with respect to Hg allowances held in the general account in all
matters pertaining to the Hg Budget Trading Program, not withstanding
any agreement between the Hg authorized account representative or any
alternate Hg authorized account representative and such person. Any
such person shall be bound by any order or decision issued to the Hg
authorized account representative or any alternate Hg authorized
account representative by the Administrator or a court regarding the
general account.
(iii) Any representation, action, inaction, or submission by any
alternate Hg authorized account representative shall be deemed to be a
representation, action, inaction, or submission by the Hg authorized
account representative.
(iv) Each submission concerning the general account shall be
submitted, signed, and certified by the Hg authorized account
representative or any alternate Hg authorized account representative
for the persons having an ownership interest with respect to Hg
allowances held in the general account. Each such submission shall
include the following certification statement by the Hg authorized
account representative or any alternate Hg authorizing account
representative: ``I am authorized to make this submission on behalf of
the persons having an ownership interest with respect to the Hg
allowances held in the general account. I certify under penalty of law
that I have personally examined, and am familiar with, the statements
and information submitted in this document and all its attachments.
Based on my inquiry of those individuals with primary responsibility
for obtaining the information, I certify that the statements and
information are to the best of my knowledge and belief true, accurate,
and complete. I am aware that there are significant penalties for
submitting false statements and information or omitting required
statements and information, including the possibility of fine or
imprisonment.''
(v) The Administrator will accept or act on a submission concerning
the general account only if the submission has been made, signed, and
certified in accordance with paragraph (b)(2)(iv) of this section.
(3) Changing Hg authorized account representative and alternate Hg
authorized account representative; changes in persons with ownership
interest.
(i) The Hg authorized account representative for a general account
may be changed at any time upon receipt by the Administrator of a
superseding complete application for a general account under paragraph
(b)(1) of this section. Notwithstanding any such change, all
representations, actions, inactions, and submissions by the previous Hg
authorized account representative prior to the time and date when the
Administrator receives the superseding application for a general
account shall be binding on the new Hg authorized account
representative and the persons with an ownership interest with respect
to the Hg allowances in the general account.
(ii) The alternate Hg authorized account representative for a
general account may be changed at any time upon receipt by the
Administrator of a superseding complete application for a general
account under paragraph (b)(1) of this section. Notwithstanding any
such change, all representations, actions, inactions, and submissions
by the previous alternate Hg authorized account representative prior to
the time and date when the Administrator receives the superseding
application for a general account shall be binding on the new alternate
Hg authorized account representative and the persons with an ownership
interest with respect to the Hg allowances in the general account.
(iii) (A) In the event a new person having an ownership interest
with respect to Hg allowances in the general account is not included in
the list of such persons in the account certificate of representation,
such new person shall be deemed to be subject to and bound by the
account certificate of representation, the representation, actions,
inactions, and submissions of the Hg authorized account representative
and any alternate Hg authorized account representative of the source or
unit, and the decisions, orders, actions, and inactions of the
Administrator, as if the new person were included in such list.
(B) Within 30 days following any change in the persons having an
ownership interest with respect to Hg allowances in the general
account, including the addition of persons, the Hg authorized account
representative or any alternate Hg authorized account representative
shall submit a revision to the application for a general account
amending the list of persons having an ownership interest with respect
to the Hg allowances in the general account to include the change.
(4) Objections concerning Hg authorized account representative.
(i) Once a complete application for a general account under
paragraph (b)(1) of this section has been submitted and received, the
Administrator will rely on the application unless and until a
superseding complete application for a general account under paragraph
(b)(1) of this section is received by the Administrator.
(ii) Except as provided in paragraph (b)(3)(i) or (ii) of this
section, no objection or other communication submitted to the
Administrator concerning the authorization, or any representation,
action, inaction, or submission of the Hg authorized account
representative or any alternative Hg authorized account representative
for a general account shall affect any representation, action,
inaction, or submission of the Hg authorized account representative or
any alternative Hg authorized account representative or the finality of
any decision or order by the Administrator under the Hg Budget Trading
Program.
(iii) The Administrator will not adjudicate any private legal
dispute concerning the authorization or any representation, action,
inaction, or submission of the Hg authorized account representative or
any alternative Hg authorized account representative for a general
account, including private legal disputes concerning the proceeds of Hg
allowance transfers.
(c) Account identification. The Administrator will assign a unique
identifying number to each account established under paragraph (a) or
(b) of this section.
Sec. 60.4152 Hg Allowance Tracking System responsibilities of Hg
authorized account representative.
(a) Following the establishment of a Hg Allowance Tracking System
account, all submissions to the Administrator pertaining to the
account, including, but not limited to, submissions concerning the
deduction or transfer of Hg allowances in the account, shall be made
only by the Hg authorized account representative for the account.
(b) Authorized account representative identification. The
Administrator will assign a unique identifying number to each Hg
authorized account representative.
[[Page 12449]]
Sec. 60.4153 Recordation of Hg allowance allocations.
(a) The Administrator will record the Hg allowances for 2010 for a
Hg Budget unit allocated under Sec. Sec. 60.4140 through 60.4142 in
the source's compliance account.
(b) By January 1, 2008, the Administrator will record the Hg
allowances for 2011 for a Hg Budget unit allocated under Sec. Sec.
60.4140 through 60.4142 in the unit's compliance account.
(c) By January 1, 2009, the Administrator will record the Hg
allowances for 2012 for a Hg Budget unit allocated under Sec. Sec.
60.4140 through 60.4142 in the unit's compliance account.
(d) By January 1, 2010, the Administrator will record the Hg
allowances for 2013 for a Hg Budget unit allocated under Sec. Sec.
60.4140 through 60.4142 in the unit's compliance account.
(e) Each year starting with 2011, after the Administrator has made
all deductions from a Hg Budget unit's compliance account pursuant to
Sec. 60.4154 (except deductions pursuant to Sec. 60.4154(d)(2)), the
Administrator will record:
(1) Hg allowances, in the compliance account, as allocated to the
unit under Sec. Sec. 60.4140 through 60.4142 for the third year after
the year of the control period for which such deductions were or could
have been made; and
(2) Hg allowances, in the general account specified by the owners
and operators of the unit, as allocated under Sec. 60.4105(c)(2) for
the third year after the year of the control period for which such
deductions are or could have been made.
(f) Serial numbers for allocated Hg allowances. When allocating Hg
allowances to a Hg Budget unit and recording them in an account, the
Administrator will assign each Hg allowance a unique identification
number that will include digits identifying the year for which the Hg
allowance is allocated.
Sec. 60.4154 Compliance.
(a) Hg allowance transfer deadline. The Hg allowances are available
to be deducted for compliance with a source's Hg Budget emissions
limitation for a control period in a given year only if the Hg
allowances:
(1) Were allocated for a control period in a prior year or the same
year; and
(2) Are held in the source's compliance account as of the Hg
allowance transfer deadline for that control period or are transferred
into the compliance account by a Hg allowance transfer correctly
submitted for recordation under Sec. 60.4160 by the Hg allowance
transfer deadline for that control period.
(b) Deductions for compliance. (1) Following the recordation, in
accordance with Sec. 60.4161, of Hg allowance transfers submitted for
recordation in a source's compliance account by the Hg allowance
transfer deadline for a control period, the Administrator will deduct
from the compliance account Hg allowances available under paragraph (a)
of this section first to account for actual heat input under Sec.
60.4142, and then to cover the total Hg emissions of all Hg Budget
units at the source (as determined in Sec. Sec. 60.4170 through
60.4176), for the control period.
(2) The Administrator will deduct Hg allowances from the source's
compliance account under paragraph (b)(1) of this section:
(i) Until the number of Hg allowances deducted for the control
period equals the number of ounces of total Hg emissions, determined in
accordance with Sec. Sec. 60.4170 through 60.4176, from all Hg Budget
units at the source for the control period for which compliance is
being determined, plus the number of Hg allowances required for
deduction to account for actual heat input under Sec. 60.4142(e) for
the control period; or
(ii) Until no more Hg allowances available under paragraph (a) of
this section remain in the compliance account.
(c)(1) Identification of Hg allowances by serial number. The Hg
authorized account representative for each compliance account may
identify by serial number the Hg allowances to be deducted from the
source's compliance account under paragraph (b) or (d) of this section.
Such identification shall be made in the compliance certification
report submitted in accordance with Sec. 60.4130.
(2) First-in, first-out. The Administrator will deduct Hg
allowances for a control period from the source's compliance account,
in the absence of an identification or in the case of a partial
identification of Hg allowances by serial number under paragraph (c)(1)
of this section on a first-in, first-out (FIFO) accounting basis in the
following order:
(i) Those Hg allowances that were allocated in the order of
recordation to the units at the source under Sec. Sec. 60.4140 through
60.4142;
(ii) Those Hg allowances that were allocated for the control period
to any unit and transferred and recorded in the compliance account
pursuant to Sec. Sec. 60.4160 through 60.4162 in order of their date
of recordation;
(d) Deductions for excess emissions. (1) After making the
deductions for compliance under paragraph (b) of this section, the
Administrator will deduct from the source's compliance account a number
of Hg allowances, allocated for a control period after the control
period in which the source has excess emissions, equal to three times
the number of the source's excess emissions.
(2) If the compliance account does not contain sufficient Hg
allowances, the Administrator will deduct the required number of Hg
allowances, regardless of the control period for which they were
allocated, whenever Hg allowances are recorded in the compliance
account.
(3) Any allowance deduction required under paragraph (d) of this
section shall not affect the liability of the owners and operators of
the Hg Budget unit for any fine, penalty, or assessment, or their
obligation to comply with any other remedy, for the same violation, as
ordered under the Clean Air Act or applicable State law. The following
guidelines will be followed in assessing fines, penalties or other
obligations:
(i) For purposes of determining the number of days of violation, if
a Hg Budget source has excess emissions for a control period, each day
in the control period (153 days) constitutes a day in violation unless
the owners and operators of the source demonstrate that a lesser number
of days should be considered.
(ii) Each ounce of excess emissions is a separate violation.
(e) Recordation of deductions. The Administrator will record in the
appropriate compliance account all deductions from such an account
pursuant to paragraphs (b) or (d), of this section.
Sec. 60.4155 Banking.
Hg allowances may be banked for future use or transfer in a
compliance account or a general account, as follows: any Hg allowance
that is held in a compliance account or a general account will remain
in such account unless and until the Hg allowance is deducted or
transferred under Sec. 60.4131, Sec. 60.4154, Sec. 60.4156, or
Sec. Sec. 60.4160 through 60.4162.
Sec. 60.4156 Account error.
The Administrator may, at his or her sole discretion and on his or
her own motion, correct any error in any Hg Allowance Tracking System
account. Within 10 business days of making such correction, the
Administrator will notify
[[Page 12450]]
the Hg authorized account representative for the account.
Sec. 60.4157 Closing of general accounts.
(a) The Hg authorized account representative of a general account
may instruct the Administrator to close the account by submitting a
statement requesting deletion of the account from the Hg Allowance
Tracking System and by correctly submitting for recordation under Sec.
60.4160 an allowance transfer of all Hg allowances in the account to
one or more other Hg Allowance Tracking System accounts.
(b) If a general account shows no activity for a period of a year
or more and does not contain any Hg allowances, the Administrator may
notify the Hg authorized account representative for the account that
the account will be closed and deleted from the Hg Allowance Tracking
System following 20 business days after the notice is sent. The account
will be closed after the 20-day period unless before the end of the 20-
day period the Administrator receives a correctly submitted transfer of
Hg allowances into the account under Sec. 60.4160 or a statement
submitted by the Hg authorized account representative demonstrating to
the satisfaction of the Administrator good cause as to why the account
should not be closed.
Hg Allowance Transfers
Sec. 60.4160 Submission of Hg allowance transfers.
A Hg authorized account representative seeking recordation of a Hg
allowance transfer shall submit the transfer to the Administrator. To
be considered correctly submitted, the Hg allowance transfer shall
include the following elements in a format specified by the
Administrator:
(a) The numbers identifying both the transferor and transferee
accounts;
(b) A specification by serial number of each Hg allowance to be
transferred; and
(c) The printed name and signature of the Hg authorized account
representative of the transferor account and the date signed.
Sec. 60.4161 EPA recordation.
(a) Within 5 business days of receiving a Hg allowance transfer,
except as provided in paragraph (b) of this section, the Administrator
will record a Hg allowance transfer by moving each Hg allowance from
the transferor account to the transferee account as specified by the
request, provided that:
(1) The transfer is correctly submitted under Sec. 60.4160; and
(2) The transferor account includes each Hg allowance identified by
serial number in the transfer.
(b) A Hg allowance transfer that is submitted for recordation
following the Hg allowance transfer deadline and that includes any Hg
allowances allocated for a control period in a prior year or the same
year as the Hg allowance transfer deadline will not be recorded until
after the Administrator completes the recordation of Hg allowance
allocations under Sec. 60.4153 for the control period in the fourth
year after the control period to which the Hg allowance transfer
deadline applies.
(c) Where a Hg allowance transfer submitted for recordation fails
to meet the requirements of paragraph (a) of this section, the
Administrator will not record such transfer.
Sec. 60.4162 Notification.
(a) Notification of recordation. Within 5 business days of
recordation of a Hg allowance transfer under Sec. 60.4161, the
Administrator will notify the Hg authorized account representatives of
both the transferor and transferee accounts.
(b) Notification of non-recordation. Within 10 business days of
receipt of a Hg allowance transfer that fails to meet the requirements
of Sec. 60.4161(a), the Administrator will notify the Hg authorized
account representatives of both accounts subject to the transfer of:
(1) A decision not to record the transfer, and
(2) The reasons for such non-recordation.
(c) Nothing in this section shall preclude the submission of a Hg
allowance transfer for recordation following notification of non-
recordation.
Monitoring and Reporting
Sec. 60.4170 General Requirements.
The owners and operators, and to the extent applicable, the Hg
authorized account representative of a Hg Budget unit, shall comply
with the monitoring, recordkeeping, and reporting requirements as
provided in this section and Sec. Sec. 60.4171 through 60.4176 and in
subpart I of part 75 of this chapter. For purposes of complying with
such requirements, the definitions in Sec. 60.4102 and in Sec. 72.2
of this chapter shall apply, and the terms ``affected unit,''
``designated representative,'' and ``continuous emission monitoring
system'' (or ``CEMS'') in part 75 of this chapter shall be deemed to
refer to the terms ``Hg Budget unit,'' ``Hg authorized account
representative,'' and ``continuous emission monitoring system'' (or
``CEMS'') respectively, as defined in Sec. 60.4102. The owner or
operator of a unit that is not a Hg Budget unit but that is monitored
under Sec. 75.82(b)(2)(i) of this chapter shall comply with the
monitoring, recordkeeping, and reporting requirements for a Hg Budget
unit under this part.
(a) Requirements for installation, certification, and data
accounting. The owner or operator of each Hg Budget unit shall meet the
following requirements:
(1) Install all monitoring systems required under this subpart for
monitoring Hg mass emissions. This includes all systems required to
monitor Hg emission rate, Hg concentration, heat input rate, moisture,
and stack flow rate, in accordance with Sec. Sec. 75.81 and 75.82 of
this chapter.
(2) Successfully complete all certification tests required under
Sec. 60.4171 and meet all other requirements of this subpart and part
75 of this chapter applicable to the monitoring systems under paragraph
(a)(1) of this section.
(3) Record, report, and quality-assure the data from the monitoring
systems under paragraph (a)(1) of this section.
(b) Compliance deadlines. The owner or operator shall meet the
certification and other requirements of paragraphs (a)(1) and (a)(2) of
this section on or before the following dates. The owner or operator
shall record, report and quality-assure the data from the monitoring
systems under paragraph (a)(1) of this section on and after the
following dates.
(1) For the owner or operator of a Hg Budget unit that commences
operation before July 1, 2008, by January 1, 2009.
(2) For the owner or operator of a Hg Budget unit that commences
operation on or after July 1, 2008, by the later of the following
dates:
(i) January 1, 2009; or
(ii) 90 unit operating days or 180 calendar days, whichever occurs
first, after the date on which the unit commences commercial operation.
(3) For the owner or operator of a Hg Budget unit that has a new
stack or flue for which construction is completed after the applicable
deadline under paragraph (b)(1) or (b)(2) of this section, by the
earlier of 90 unit operating days or 180 calendar days after the date
on which emissions first exit to the atmosphere through the new stack
or flue.
(c) Reporting data prior to initial certification. The owner or
operator of a Hg Budget unit that does not meet the applicable
compliance date set forth in paragraph (b) of this section shall
determine, record and report Hg mass
[[Page 12451]]
emissions, heat input rate, and any other values required to determine
Hg mass emissions (e.g., Hg emission rate and heat input rate, or Hg
concentration and stack flow rate) in accordance with Sec. 75.80(g) of
this chapter.
(d) Prohibitions.
(1) No owner or operator of a Hg Budget unit shall use any
alternative monitoring system, alternative reference method, or any
other alternative for the required continuous emission monitoring
system without having obtained prior written approval in accordance
with Sec. 60.4175.
(2) No owner or operator of a Hg Budget unit shall operate the unit
so as to discharge, or allow to be discharged, Hg emissions to the
atmosphere without accounting for all such emissions in accordance with
the applicable provisions of this subpart and part 75 of this chapter.
(3) No owner or operator of a Hg Budget unit shall disrupt the
continuous emission monitoring system, any portion thereof, or any
other approved emission monitoring method, and thereby avoid monitoring
and recording Hg mass emissions discharged into the atmosphere, except
for periods of recertification or periods when calibration, quality
assurance testing, or maintenance is performed in accordance with the
applicable provisions of this subpart and part 75 of this chapter.
(4) No owner or operator of a Hg Budget unit shall retire or
permanently discontinue use of the continuous emission monitoring
system, any component thereof, or any other approved emission
monitoring system under this subpart, except under any one of the
following circumstances:
(i) During the period that the unit is covered by an exemption
under Sec. 60.4105 that is in effect;
(ii) The owner or operator is monitoring emissions from the unit
with another certified monitoring system approved, in accordance with
the applicable provisions of this subpart and part 75 of this chapter,
by the permitting authority for use at that unit that provides emission
data for the same pollutant or parameter as the retired or discontinued
monitoring system; or
(iii) The Hg authorized account representative submits notification
of the date of certification testing of a replacement monitoring system
for the retired or discontinued monitoring system in accordance with
Sec. 60.4171(c)(2).
Sec. 60.4171 Initial certification and recertification procedures.
(a) Requirements for initial certification. The owner or operator
shall ensure that each monitoring system required by subpart I of part
75 of this chapter (including the automated data acquisition and
handling system) successfully completes all of the initial
certification testing required under Sec. 75.20 of this chapter by the
applicable deadline in Sec. 60.4170(b).
(b) Requirements for recertification. Whenever the owner or
operator makes a replacement, modification, or change in a certified
monitoring system required by subpart I of part 75 of this chapter that
may significantly affect the ability of the system to accurately
measure or record Hg mass emissions or heat input rate or to meet the
requirements of Sec. 75.21 of this chapter or appendix B to part 75 of
this chapter, the owner or operator shall recertify the monitoring
system in accordance with Sec. 75.20(b) of this chapter. Furthermore,
whenever the owner or operator makes a replacement, modification, or
change to the flue gas handling system or the unit's operation that may
significantly change the stack flow or concentration profile, the owner
or operator shall recertify the continuous emission monitoring system
in accordance with Sec. 75.20(b) of this chapter. Examples of changes
that require recertification include: replacement of the analyzer,
complete replacement of an existing continuous emission monitoring
system, or change in location or orientation of the sampling probe or
site.
(c) Certification approval process for initial certification and
recertification.
(1) Notification of certification. The Hg authorized account
representative shall submit to the permitting authority, the
appropriate EPA Regional Office, and the Administrator written notice
of the dates of certification in accordance with Sec. 60.4173.
(2) Certification application. The Hg authorized account
representative shall submit to the permitting authority a certification
application for each monitoring system required under subpart I of part
75 of this chapter. A complete certification application shall include
the information specified in subpart I of part 75 of this chapter.
Notwithstanding this requirement, a certification application is not
required by subpart I if the system has been previously certified under
the Acid Rain Program or under an applicable State or Federal
NOX mass emission reduction program that adopts the
requirements of subpart H of part 75 of this chapter.
(3) Provisional certification date. The provisional certification
date for a monitoring system shall be determined in accordance with
Sec. 75.20(a)(3) of this chapter. A provisionally certified monitoring
system may be used under the Hg Budget Trading Program for a period not
to exceed 120 days after receipt by the permitting authority of the
complete certification application for the monitoring system under
paragraph (c)(2) of this section. Data measured and recorded by the
provisionally certified monitoring system, in accordance with the
requirements of part 75 of this chapter, will be considered valid
quality-assured data (retroactive to the date and time of provisional
certification), provided that the permitting authority does not
invalidate the provisional certification by issuing a notice of
disapproval within 120 days of receipt of the complete certification
application by the permitting authority.
(4) Certification application formal approval process. The
permitting authority will issue a written notice of approval or
disapproval of the certification application to the owner or operator
within 120 days of receipt of the complete certification application
under paragraph (c)(2) of this section. In the event the permitting
authority does not issue such a notice within such 120-day period, each
monitoring system that meets the applicable performance requirements of
part 75 of this chapter and is included in the certification
application will be deemed certified for use under the Hg Budget
Trading Program.
(i) Approval notice. If the certification application is complete
and shows that each monitoring system meets the applicable performance
requirements of part 75 of this chapter, then the permitting authority
will issue a written notice of approval of the certification
application within 120 days of receipt.
(ii) Incomplete application notice. A certification application
will be considered complete when all of the applicable information
required to be submitted under paragraph (c)(2) of this section has
been received by the permitting authority. If the certification
application is not complete, then the permitting authority will issue a
written notice of incompleteness that sets a reasonable date by which
the Hg authorized account representative must submit the additional
information required to complete the certification application. If the
Hg authorized account representative does not comply with the notice of
incompleteness by the specified date, then the permitting authority may
issue a notice of disapproval under paragraph (c)(4)(iii) of this
section. The 120-day review period shall not begin prior to receipt of
a complete certification application.
(iii) Disapproval notice. If the certification application shows
that any
[[Page 12452]]
monitoring system does not meet the performance requirements of this
part, or if the certification application is incomplete and the
requirement for disapproval under paragraph (c)(4)(ii) of this section
has been met, then the permitting authority will issue a written notice
of disapproval of the certification application. Upon issuance of such
notice of disapproval, the provisional certification is invalidated by
the permitting authority and the data measured and recorded by each
uncertified monitoring system shall not be considered valid quality-
assured data beginning with the date and hour of provisional
certification (as defined under Sec. 75.20(a)(3) of this chapter). The
owner or operator shall follow the procedures for loss of certification
in paragraph (c)(5) of this section for each monitoring system that is
disapproved for initial certification.
(iv) Audit decertification. The permitting authority may issue a
notice of disapproval of the certification status of a monitor in
accordance with Sec. 60.4172(b).
(5) Procedures for loss of certification. If the Permitting
authority issues a notice of disapproval of a certification application
under paragraph (c)(4)(iii) of this section or a notice of disapproval
of certification status under paragraph (c)(4)(iv) of this section,
then:
(i) The owner or operator shall substitute the following values,
for each hour of unit operation during the period of invalid data
specified under Sec. 75.20(a)(4)(iii), Sec. 75.20(b)(5), or Sec.
75.21(e) of this chapter and continuing until the date and hour
specified under Sec. 75.20(a)(5)(i) of this chapter:
(A) For units that the owner or operator monitors for Hg emission
rate and heat input rate, the maximum potential Hg emission rate and
the maximum potential hourly heat input of the unit; and
(B) For units that the owner or operator monitors for Hg mass
emissions using a Hg pollutant concentration monitor and a flow
monitor, the maximum potential concentration of Hg and the maximum
potential flow rate under section 2.1.4 of appendix A of part 75 of
this chapter.
(ii) The Hg authorized account representative shall submit a
notification of certification retest dates and a new certification
application in accordance with paragraphs (c)(1) and (c)(2) of this
section.
(iii) The owner or operator shall repeat all certification tests or
other requirements that were failed by the monitoring system, as
indicated in the permitting authority's notice of disapproval, no later
than 30 unit operating days after the date of issuance of the notice of
disapproval.
(d) Certification/recertification procedures for alternative
monitoring systems. The Hg authorized account representative of each
unit for which the owner or operator intends to use an alternative
monitoring system approved by the Administrator and, if applicable, the
permitting authority under subpart E of part 75 of this chapter shall
comply with the applicable certification procedures of paragraph (a) of
this section before using the system under the Hg Budget Trading
Program. The Hg authorized account representative shall also comply
with the applicable recertification procedures of paragraph (b) of this
section. Section 75.20(f) of this chapter shall apply to such
alternative monitoring system.
(e) Hg Budget units subject to other programs. For Hg Budget units
that are also subject to the Acid Rain Program or an applicable State
or Federal NOX mass emission reduction program that adopts
the requirements of subpart H of part 75 of this chapter, the owner or
operator shall meet the applicable initial certification and
recertification requirements of these programs, in addition to the
requirements of this section.
Sec. 60.4172 Out of control periods.
(a) Whenever any monitoring system fails to meet the quality
assurance or data validation requirements of part 75 of this chapter,
data shall be substituted using the applicable procedures in subpart D
of part 75 of this chapter.
(b) Audit decertification. Whenever both an audit of a monitoring
system and a review of the initial certification or recertification
application reveal that any system should not have been certified or
recertified because it did not meet a particular performance
specification or other requirement under Sec. 60.4171 or the
applicable provisions of part 75 of this chapter, both at the time of
the initial certification or recertification application submission and
at the time of the audit, the permitting authority will issue a notice
of disapproval of the certification status of such system. For the
purposes of this paragraph, an audit shall be either a field audit or
an audit of any information submitted to the permitting authority or
the Administrator. By issuing the notice of disapproval, the permitting
authority revokes prospectively the certification status of the system.
The data measured and recorded by the system shall not be considered
valid quality-assured data from the date of issuance of the
notification of the revoked certification status until the date and
time that the owner or operator completes subsequently approved initial
certification or recertification tests for the system.
Sec. 60.4173 Notifications.
The Hg authorized account representative for a Hg Budget unit shall
submit written notice to the permitting authority and the Administrator
in accordance with Sec. 75.61 of this chapter, except that if the unit
is not subject to an Acid Rain emissions limitation, the notification
is only required to be sent to the permitting authority.
Sec. 60.4174 Recordkeeping and reporting.
(a) General provisions.
(1) The Hg authorized account representative shall comply with all
recordkeeping and reporting requirements in this section and with the
requirements of Sec. 60.4110(e)(1).
(2) If a Hg Budget unit is subject to an Acid Rain emission
limitation or an applicable State or Federal NOX mass
emission reduction program that adopts the requirements of subpart H of
part 75 of this chapter, and the Hg authorized account representative
who signed and certified any submission that is made under subpart F or
G of part 75 of this chapter and that includes data and information
required under this subpart or subpart I of part 75 of this chapter is
not the same person as the designated representative, the alternative
designated representative, or the NOX authorized account
representative for the unit under parts 72 or 75 of this chapter, then
the submission must also be signed by the designated representative or
the alternative designated representative, and the NOX
authorized account representative, as applicable.
(b) Monitoring plans.
(1) The owner or operator of a Hg Budget unit shall comply with
requirements of Sec. 75.62 of this chapter, except that the monitoring
plan is only required to include the information required by subpart I
of part 75 of this chapter.
(2) For Hg Budget units that are also subject to the Acid Rain
Program or an applicable State or Federal NOX mass emission
reduction program that adopts the requirements of subpart H of part 75
of this chapter, the owner or operator shall comply with requirements
of Sec. Sec. 75.62 or 75.73(c), as applicable, of this chapter, except
that the monitoring plan shall also include all of the information
required by subpart I of part 75 of this chapter.
(c) Certification applications. The Hg authorized account
representative shall
[[Page 12453]]
submit an application to the permitting authority within 45 days after
completing all initial certification or recertification tests required
under Sec. 60.4171 including the information required under subpart I
of part 75 of this chapter.
(d) Quarterly reports. The Hg authorized account representative
shall submit quarterly reports, as follows:
(1) The Hg authorized account representative shall submit a
quarterly report for each calendar quarter beginning with:
(i) For a unit that commences commercial operation before July 1,
2008, the calendar quarter covering January 1, 2009 through March 31,
2009. Data shall be reported from the first hour on January 1, 2009; or
(ii) For a unit that commences commercial operation on or after
July 1, 2008, the calendar quarter corresponding to the earlier of the
date of provisional certification or the relevant deadline for initial
certification under Sec. 60.4170(b), unless that quarter is the third
or fourth quarter of 2008, in which case reporting shall commence in
the quarter covering January 1, 2009 through March 31, 2009. Data shall
be reported from the later of the date and hour corresponding to the
date and hour of provisional certification or the first hour on January
1, 2009.
(2) The Hg authorized account representative shall submit each
quarterly report to the Administrator within 30 days following the end
of the calendar quarter covered by the report. Quarterly reports shall
be submitted in the manner specified in subpart I of part 75 of this
chapter and Sec. 75.64 of this chapter.
(i) For Hg Budget units that are also subject to an Acid Rain
emissions limitation, quarterly reports shall include the data and
information required in subpart I of 40 CFR part 75 of this chapter and
the data and information required in subpart G of 40 CFR part 75 of
this chapter.
(ii) For Hg Budget units that are also subject to an applicable
State or Federal NOX mass emission reduction program that
adopts the requirements of subpart H of 40 CFR part 75 of this chapter,
quarterly reports shall include the data and information required in
subpart H of 40 CFR part 75 of this chapter and the information and
data required in subpart I of 40 CFR part 75 of this chapter.
(iii) For Hg Budget units not subject to an Acid Rain emissions
limitation or an applicable State or Federal NOX mass
emission reduction program that adopts the requirements of subpart H of
40 CFR part 75 of this chapter, quarterly reports shall only include
the data and information required in subpart I of part 75 of this
chapter.
(3) Compliance certification. The Hg authorized account
representative shall submit to the Administrator a compliance
certification in support of each quarterly report based on reasonable
inquiry of those persons with primary responsibility for ensuring that
all of the unit's emissions are correctly and fully monitored. The
certification shall state that:
(i) The monitoring data submitted were recorded in accordance with
the applicable requirements of this subpart and part 75 of this
chapter, including the quality assurance procedures and specifications;
and
(ii) For a unit with add-on Hg emission controls or that has an
installed flue gas desulfurization system, for all hours where Hg data
are substituted in accordance with Sec. 75.38(b) of this chapter, the
add-on emission controls were operating within the range of parameters
listed in the quality assurance/quality control program under appendix
B of 40 CFR part 75 of this chapter and the substitute values do not
systematically underestimate Hg emissions.
Sec. 60.4175 Petitions.
(a) The Hg authorized account representative of a Hg Budget unit
that is subject to an Acid Rain emissions limitation may submit a
petition under Sec. 75.66 of this chapter to the Administrator
requesting approval to apply an alternative to any requirement of this
subpart.
(1) Application of an alternative to any requirement of this
subpart is in accordance with this subpart only to the extent that the
petition is approved by the Administrator, in consultation with the
permitting authority.
(2) Notwithstanding paragraph (a)(1) of this section, if the
petition requests approval to apply an alternative to a requirement
concerning any additional CEMS required under the common stack
provisions of Sec. 75.82 of this chapter, the petition is governed by
paragraph (b) of this section.
(b) The Hg authorized account representative of a Hg Budget unit
that is not subject to an Acid Rain emissions limitation may submit a
petition under Sec. 75.66 of this chapter to the permitting authority
and the Administrator requesting approval to apply an alternative to
any requirement of this subpart.
(1) The Hg authorized account representative of a Hg Budget unit
that is subject to an Acid Rain emissions limitation may submit a
petition under Sec. 75.66 of this chapter to the permitting authority
and the Administrator requesting approval to apply an alternative to a
requirement concerning any additional CEMS required under the common
stack provisions of Sec. 75.82 of this chapter or a Hg emission rate
(or Hg-diluent) monitoring system, a Hg concentration monitoring
system, or a carbon canister monitoring system, as applicable, used
under Sec. 75.81 of this chapter.
(2) Application of an alternative to any requirement of this
subpart is in accordance with this subpart only to the extent that the
petition is approved by both the permitting authority and the
Administrator.
Sec. 60.4176 Additional requirements to provide heat input data.
The owner or operator of a Hg Budget unit that monitors and reports
Hg mass emissions using a Hg concentration system and a flow system
shall also monitor and report heat input rate at the unit level using
the procedures set forth in part 75 of this chapter.
PART 72--PERMITS REGULATION
1. The authority citation for Part 72 continues to read as follows:
Authority: 42 U.S.C. 7601 and 7651, et. seq.
2. Section 72.2 is amended in the definition of ``Continuous
emission monitoring system or CEMS'' by revising the introductory text
and adding paragraphs (7) and (8); and by adding, in alphabetical
order, a new definition for ``sorbent trap monitoring system'', to read
as follows:
Sec. 72.2 Definitions.
* * * * *
Continuous emission monitoring system or CEMS means the equipment
required by part 75 of this chapter used to sample, analyze, measure,
and provide, by means of readings recorded at least once every 15
minutes (using an automated data acquisition and handling system
(DAHS)), a permanent record of SO2, NOX, or
CO2 emissions or stack gas volumetric flow rate. The
following are the principal types of continuous emission monitoring
systems required under part 75 of this chapter. Sections 75.10 through
75.18, Sec. 75.71(a), and Sec. 75.81 of this chapter indicate which
type(s) of CEMS is required for specific applications:
* * *
(7) A mercury (Hg) emission rate (or Hg-diluent) monitoring system,
consisting of a Hg pollutant concentration monitor, a diluent gas
(CO2 or O2) monitor, and an automated
[[Page 12454]]
DAHS. A Hg-diluent monitoring system provides a permanent, continuous
record of: Hg concentration in units of micrograms per dry standard
cubic meter ([mu]g/dscm), diluent gas concentration in units of percent
O2 or CO2 (% O2 or CO2),
and Hg emission rate in units of pounds per trillion British thermal
units (lb/10\12\ Btu);
(8) A Hg concentration monitoring system, consisting of a Hg
pollutant concentration monitor and an automated DAHS. A Hg
concentration monitoring system provides a permanent, continuous record
of Hg emissions in units of micrograms per dry standard cubic meter
([mu]g/dscm).
* * * * *
Sorbent trap monitoring system means the equipment required by part
75 of this chapter for the continuous monitoring of Hg emissions, using
paired sorbent traps containing iodinized charcoal (IC) or other
suitable reagent(s). The monitoring system consists of a probe, the
paired sorbent traps, a heated umbilical line, moisture removal
components, an air-tight sample pump, a dry gas meter, and an automated
data acquisition and handling system. The monitoring system samples the
stack gas at a rate proportional to the stack gas volumetric flow rate.
The sampling is a batch process. The sorbent traps can be used for a
time period ranging from hours to weeks in length, depending upon the
Hg concentration in the stack. Using the sample volume measured by the
dry gas meter and the results of laboratory analysis of the sorbent
traps, the Hg concentration in the stack gas is determined, in units of
micrograms per dry standard cubic meter ([mu]g/dscm). Mercury mass
emissions for each hour in the sampling period are calculated using the
higher of the two average Hg concentrations for that period in
conjunction with contemporaneous measurements of stack gas flow rate.
* * * * *
PART 75--CONTINUOUS EMISSION MONITORING
3. The authority citation for Part 75 continues to read as follows:
Authority: 42 U.S.C. 7601, 7651k, and 7651k note.
4. Section 75.2 is amended by adding paragraph (d) to read as
follows:
Sec. 75.2 Applicability.
* * * * *
(d) The provisions of this part apply to sources subject to a State
or Federal mercury (Hg) mass emission reduction program, to the extent
that these provisions are adopted as requirements under such a program.
5. Section 75.10 is amended by revising the second sentence of
paragraph (d)(1) and revising the first two sentences of paragraph
(d)(3) to read as follows:
Sec. 75.10 General operating requirements.
* * * * *
(d) * * *
(1) * * * The owner or operator shall reduce all SO2
concentrations, volumetric flow, SO2 mass emissions,
CO2 concentration, O2 concentration,
CO2 mass emissions (if applicable), NOX
concentration, NOX emission rate, Hg concentration, and Hg
emission rate data collected by the monitors to hourly averages.
* * * * *
(3) Failure of an SO2, CO2, or O2
pollutant concentration monitor, NOX concentration monitor,
Hg concentration monitor, flow monitor, moisture monitor,
NOX-diluent continuous emission monitoring system, or Hg-
diluent continuous emission monitoring system to acquire the minimum
number of data points for calculation of an hourly average in paragraph
(d)(1) of this section shall result in the failure to obtain a valid
hour of data and the loss of such component data for the entire hour.
For a NOX-diluent monitoring system or for a Hg-diluent
monitoring system, hourly average NOX (or Hg) emission rate
in lb/mmBtu (or lb/10 \12\ Btu) is valid only if the minimum number of
data points is acquired by both the NOX (or Hg) pollutant
concentration monitor and the diluent monitor (CO2 or
O2). * * *
* * * * *
6. Section 75.15 is added to read as follows:
Sec. 75.15 Special provisions for measuring Hg mass emissions with
sorbent trap monitoring systems.
For an affected coal-fired unit under a State or Federal Hg mass
emission reduction program that adopts the provisions of subpart I of
this part, if the owner or operator elects to use sorbent trap
monitoring systems (as defined in Sec. 72.2 of this chapter) to
quantify Hg mass emissions:
(a) For sorbent trap monitoring system (whether primary or
redundant backup), the use of paired sorbent traps, as described in
Method 324 in appendix B to part 63 of this chapter, is required;
(b) Each sorbent trap shall have both a main portion and a backup
portion;
(c) A certified flow monitoring system is required;
(d) Correction for stack gas moisture content is required, and in
some cases, a certified O2 or CO2 monitoring
system is required (see Sec. 75.81(b));
(e) Each sorbent trap monitoring system shall be installed and
operated in accordance with EPA Method 324. The Hg sampling shall be
proportional to the stack gas volumetric flow rate. Use an intermediate
sampling rate of 0.3 to 0.5 liters per minute through each sorbent trap
when the unit is operating at the normal (i.e., most frequently-used)
load level, as defined in section 6.5.2.1(d) of appendix A to this
part. Increase or decrease the sampling rate by 0.1 liters/min when the
unit operates at the other two load levels. For example, if mid load
level is normal and the sampling rate is set at 0.4 liters/min,
decrease the sampling rate to 0.3 liters/min when the unit is operating
at low load and increase it to 0.5 liters/min when the unit operates at
high load.
(f) At the beginning and end of each sample collection period,
record the dry gas meter readings, for the purposes of determining the
total volume of dry gas sampled during the collection period.
(g) After each sample collection period, the mass of Hg adsorbed in
each sorbent trap (both the main and backup portions) shall be
determined according to Method 324.
(h) The hourly Hg mass emissions for each collection period are
determined using the results of the Method 324 analyses in conjunction
with contemporaneous data recorded by the stack flow monitor. For each
pair of sorbent traps analyzed, the higher of the two Hg concentrations
shall be used for reporting purposes under Sec. 75.84(f).
(i) All unit operating hours for which valid Hg concentration data
are obtained with the primary sorbent trap monitoring system (as
verified using the quality assurance procedures in section 8.3 of
Method 324) shall be reported in the electronic quarterly report under
Sec. 75.84(f). For hours in which data from the primary monitoring
system are invalid, the owner or operator may report valid Hg
concentration data from a certified redundant backup monitoring system
or from the applicable reference method under Sec. 75.22. If no
quality-assured Hg concentration are available for a particular hour,
the owner or operator shall report the appropriate substitute data
value in accordance with Sec. 75.39.
(j) Initial certification requirements and additional quality-
assurance requirements for the sorbent trap monitoring systems are
found in Sec. 75.20(c)(9), in section 6.5.7 of appendix A to this part
and in sections 1.5 and 2.3 of appendix B to this part.
7. Section 75.20 is amended by:
a. Revising paragraph (a)(5)(i);
[[Page 12455]]
b. Revising the first sentence of paragraph (b) introductory text;
c. Revising paragraph (c)(1);
d. Redesignating existing paragraphs (c)(9) and (c)(10) as
paragraphs (c)(10) and (c)(11), respectively;
e. Adding a new paragraph (c)(9); and
f. Revising paragraph (d)(2)(v).
The revisions and additions read as follows:
Sec. 75.20 Initial certification and recertification procedures.
(a) * * *
(5) * * *
(i) Until such time, date, and hour as the continuous emission
monitoring system can be adjusted, repaired, or replaced and
certification tests successfully completed (or, if the conditional data
validation procedures in paragraphs (b)(3)(ii) through (b)(3)(ix) of
this section are used, until a probationary calibration error test is
passed following corrective actions in accordance with paragraph
(b)(3)(ii) of this section), the owner or operator shall substitute the
following values, as applicable, for each hour of unit operation during
the period of invalid data specified in paragraph (a)(4)(iii) of this
section or in Sec. 75.21: The maximum potential concentration of
SO2, as defined in section 2.1.1.1 of appendix A to this
part, to report SO2 concentration; the maximum potential
NOX emission rate, as defined in Sec. 72.2 of this chapter,
to report NOX emissions in lb/mmBtu; the maximum potential
concentration of NOX, as defined in section 2.1.2.1 of
appendix A to this part, to report NOX emissions in ppm
(when a NOX concentration monitoring system is used to
determine NOX mass emissions, as defined under Sec.
75.71(a)(2)); the maximum potential Hg emission rate, as defined in
section 2.1.7 of appendix A to this part, to report Hg emissions in lb/
10\12\ Btu; the maximum potential concentration of Hg, as defined in
section 2.1.7 of appendix A to this part, to report Hg emissions in
[mu]g/dcsm (when a Hg concentration monitoring system or a sorbent trap
monitoring system is used to determine Hg mass emissions, as defined
under Sec. 75.81(b)); the maximum potential flow rate, as defined in
section 2.1.4.1 of appendix A to this part, to report volumetric flow;
the maximum potential concentration of CO2, as defined in
section 2.1.3.1 of appendix A to this part, to report CO2
concentration data; and either the minimum potential moisture
percentage, as defined in section 2.1.5 of appendix A to this part or,
if Equation 19-3, 19-4 or 19-8 in Method 19 in appendix A to part 60 of
this chapter is used to determine NOX emission rate, the
maximum potential moisture percentage, as defined in section 2.1.6 of
appendix A to this part; and
* * * * *
(b) Recertification approval process. Whenever the owner or
operator makes a replacement, modification, or change in a certified
continuous emission monitoring system or continuous opacity monitoring
system that may significantly affect the ability of the system to
accurately measure or record the SO2 or CO2
concentration, stack gas volumetric flow rate, NOX emission
rate, NOX concentration, Hg concentration, Hg emission rate,
percent moisture, or opacity, or to meet the requirements of Sec.
75.21 or appendix B to this part, the owner or operator shall recertify
the continuous emission monitoring system or continuous opacity
monitoring system, according to the procedures in this paragraph. * * *
* * * * *
(c) * * *
(1) For each SO2 pollutant concentration monitor, each
NOX concentration monitoring system used to determine
NOX mass emissions, as defined under Sec. 75.71(a)(2), each
Hg concentration monitoring system, each NOX-diluent
continuous emission monitoring system, and each Hg-diluent monitoring
system:
(i) A 7-day calibration error test, where, for the NOX-
diluent and Hg-diluent continuous emission monitoring systems, the test
is performed separately on the NOX (or Hg) pollutant
concentration monitor and the diluent gas monitor;
(ii) A linearity check, where, for the NOX-diluent and
Hg-diluent continuous emission monitoring systems, the test is
performed separately on the NOX (or Hg) pollutant
concentration monitor and the diluent gas monitor;
(iii) A relative accuracy test audit. For the NOX-
diluent continuous emission monitoring system, the RATA shall be done
on a system basis, in units of lb/mmBtu. For the NOX
concentration monitoring system, the RATA shall be done on a ppm basis.
For the Hg concentration monitoring system, the RATA shall be done on a
[mu]g/dscm basis. For the Hg-diluent monitoring system, the RATA shall
be done on a lb/10\12\ Btu basis;
(iv) A bias test;
(v) A cycle time test; and
(vi) For Hg monitors only, a 3-point check of the converter, using
HgCl2 standards, as described in sections 8.3 and 13.1 of
Performance Specification 12A in appendix B to part 60 of this chapter.
* * * * *
(9) For each sorbent trap monitoring system, perform a RATA, on a
[mu]g/dscm basis, and a bias test.
* * * * *
(d) * * *
(2) * * *
(v) For each parameter monitored (i.e., SO2,
CO2, O2, NOX, Hg or flow rate) at each
unit or stack, a regular non-redundant backup CEMS may not be used to
report data at that affected unit or common stack for more than 720
hours in any one calendar year (or 720 hours in any ozone season, for
sources that report emission data only during the ozone season, in
accordance with Sec. 75.74(c)), unless the CEMS passes a RATA at that
unit or stack. For each parameter monitored at each unit or stack, the
use of a like-kind replacement non-redundant backup analyzer (or
analyzers) is restricted to 720 cumulative hours per calendar year (or
ozone season, as applicable), unless the owner or operator redesignates
the like-kind replacement analyzer(s) as component(s) of regular non-
redundant backup CEMS and each redesignated CEMS passes a RATA at that
unit or stack.
* * * * *
8. Section 75.21 is amended by revising paragraph (a)(3) to read as
follows:
Sec. 75.21 Quality assurance and quality control requirements.
(a) * * *
(3) The owner or operator shall perform quality assurance upon a
reference method backup monitoring system according to the requirements
of method 2, 6C, 7E, or 3A in appendix A of part 60 of this chapter
(supplemented, as necessary, by guidance from the Administrator), or
the Ontario Hydro method, as applicable, instead of the procedures
specified in appendix B of this part.
* * * * *
9. Section 75.22 is amended by adding new paragraphs (a)(7) and
(b)(5) to read as follows:
Sec. 75.22 Reference methods.
(a) * * *
(7) ASTM D6784-02, Standard Test Method for Elemental, Oxidized,
Particle-Bound, and Total Mercury in Flue Gas Generated from Coal-Fired
Stationary Sources (also known as the Ontario Hydro Method) is the
reference method for determining Hg concentration.
(b) * * *
(5) ASTM D6784-02, Standard Test Method for Elemental, Oxidized,
Particle-Bound, and Total Mercury in Flue Gas Generated from Coal-Fired
[[Page 12456]]
Stationary Sources (also known as the Ontario Hydro Method) for
determining Hg concentration.
* * * * *
10. Section 75.24 is amended by revising paragraph (d) to read as
follows:
Sec. 75.24 Out-of-control periods and adjustment for system bias.
* * * * *
(d) When the bias test indicates that an SO2 monitor, a
flow monitor, a NOX-diluent continuous emission monitoring
system, a Hg-diluent monitoring system, a NOX concentration
monitoring system used to determine NOX mass emissions, as
defined in Sec. 75.71(a)(2), a Hg concentration monitoring system or a
sorbent trap monitoring system is biased low (i.e., the arithmetic mean
of the differences between the reference method value and the monitor
or monitoring system measurements in a relative accuracy test audit
exceed the bias statistic in section 7 of appendix A to this part), the
owner or operator shall adjust the monitor or continuous emission
monitoring system to eliminate the cause of bias such that it passes
the bias test or calculate and use the bias adjustment factor as
specified in section 2.3.4 of appendix B to this part.
* * * * *
11. Section 75.31 is amended by:
a. Revising the first sentence of paragraph (a);
b. Revising paragraph (b) introductory text; and
c. Revising paragraphs (b)(1) and (b)(2).
The revisions read as follows:
Sec. 75.31 Initial missing data procedures.
(a) During the first 720 quality-assured monitor operating hours
following initial certification of the required SO2,
CO2, O2, Hg concentration, Hg-diluent, or
moisture monitoring system(s) at a particular unit or stack location *
* *
(b) SO2, CO2, or O2 concentration data, Hg concentration data, Hg
emission rate data, and moisture data. For each hour of missing
SO2, Hg or CO2 pollutant concentration data
(including CO2 data converted from O2 data using
the procedures in appendix F of this part), missing Hg emission rate
data, or missing O2 or CO2 diluent concentration
data used to calculate heat input, or missing moisture data, the owner
or operator shall calculate the substitute data as follows:
(1) Whenever prior quality-assured data exist, the owner or
operator shall substitute, by means of the data acquisition and
handling system, for each hour of missing data, the average of the
hourly SO2, CO2 , Hg or O2
concentrations, Hg emission rates, or moisture percentages recorded by
a certified monitor for the unit operating hour immediately before and
the unit operating hour immediately after the missing data period.
(2) Whenever no prior quality assured SO2, Hg,
CO2 or O2 concentration data, Hg emission rate
data, or moisture data exist, the owner or operator shall substitute,
as applicable, for each hour of missing data, the maximum potential
SO concentration or the maximum potential CO2
concentration or the minimum potential O2 concentration or
(unless Equation 19-3, 19-4 or 19-8 in Method 19 in appendix A to part
60 of this chapter is used to determine NOX emission rate)
the minimum potential moisture percentage, or the maximum potential Hg
concentration, or the maximum potential Hg emission rate, as specified,
respectively, in sections 2.1.1.1, 2.1.3.1, 2.1.3.2, 2.1.5, and 2.1.7
of appendix A to this part. If Equation 19-3, 19-4 or 19-8 in Method 19
in appendix A to part 60 of this chapter is used to determine
NOX emission rate, substitute the maximum potential moisture
percentage, as specified in section 2.1.6 of appendix A to this part.
* * * * *
12. Section 75.32 is amended by revising the first sentence of
paragraph (a) introductory text to read as follows:
Sec. 75.32 Determination of monitor data availability for standard
missing data procedures.
(a) Following initial certification of the required SO2,
CO2, O2 , Hg concentration, Hg-diluent, or
moisture monitoring system(s) at a particular unit or stack location *
* *
* * * * *
13. Table 1 in section 75.33 is revised as follows:
Sec. 75.33 Standard missing data procedures for SO2, NOX and flow
rate.
Table 1.--Missing Data Procedure for SO2 CEMS, CO2 CEMS, Moisture CEMS, Hg CEMS, and Diluent (CO2 or O2)
Monitors for Heat Input Determination
----------------------------------------------------------------------------------------------------------------
Trigger conditions Calculation routines
----------------------------------------------------------------------------------------------------------------
Monitor data availability Duration (N) of CEMS
(percent) outage (hours) 2 Method Lookback period
----------------------------------------------------------------------------------------------------------------
95 or more........................ N <= 24 Average................... HB/HA
N 24 For SO2, CO2, Hg, and ....................
H2O**, the greater of:
Average................. HB/HA
.......................... 90th percentile........... 720 hours*
For O2 and H2Ox, the ....................
lesser of:
.......................... Average................... HB/HA
.......................... 10th percentile........... 720 hours*
90 or more, but below 95.......... N <= 8 Average................... HB/HA
N 8 For SO2, CO2, Hg, and ....................
H2O**, the greater of:
.......................... Average................... HB/HA
.......................... 95th percentile........... 720 hours*
.......................... For O2 and H2Ox, the
lesser of:
.......................... Average................... HB/HA
.......................... 5th percentile............ 720 hours*
80 or more, but below 90.......... N 0 For SO2, CO2, Hg, and 720 hours*
H2O**, Maximum value \1\.
For O2 and H2O x: Minimum 720 hours*
value 1.
[[Page 12457]]
Below 80.......................... N 0 Maximum potential None
concentration or % (for
SO2, CO2, , Hg, and
H2O**).
or........................
Minimum potential
concentration or % (for
O2 and H2Ox).
----------------------------------------------------------------------------------------------------------------
HB/HA = hour before and hour after the CEMS outage.
* Quality-assured, monitor operating hours, during unit operation. May be either fuel-specific or non-fuel-
specific. For units that report data only for the ozone season, include only quality assured monitor operating
hours within the ozone season in the lookback period. Use data from no earlier than 3 years prior to the
missing data period.
\1\ Where a unit with add-on SO2 emission controls can demonstrate that the controls are operating properly, as
provided in Sec. 75.34, the unit may, upon approval, use the maximum controlled emission rate from the
previous 720 operating hours.
\2\ During unit operating hours.
\x\ Use this algorithm for moisture except when Equation 19-3, 19-4 or 19-8 in Method 19 in appendix A to part
60 of this chapter is used for NOX emission rate.
** Use this algorithm for moisture only when Equation 19-3, 19-4 or 19-8 in Method 19 in appendix A to part 60
of this chapter is used for NOX emission rate.
* * * * *
14. Subpart D is further amended by adding two new sections, Sec.
75.38 and Sec. 75.39 to read as follows:
Sec. 75.38 Standard missing data procedures for Hg CEMS
(a) Upon completion of 720 quality assured monitor operating hours
using the initial missing data procedures of Sec. 75.31(b), the owner
or operator shall provide substitute data for Hg concentration or for
Hg emission rate (as applicable), in accordance with the procedures in
Sec. 75.33(b)(1) through (b)(4), except that the term ``Hg
concentration'' or ``Hg emission rate'' shall apply rather than
``SO2 concentration,'' the term ``Hg concentration
monitoring system'' or ``Hg-diluent monitoring system'' shall apply
rather than ``SO2 pollutant concentration monitor,'' and the
term ``maximum potential Hg concentration, as defined in section 2.1.7
of appendix A to this part'' or ``maximum potential Hg emission rate,
as defined in section 2.1.7 of appendix A to this part'' shall apply,
rather than ``maximum potential SO2 concentration.''
(b) For a unit equipped with a flue gas desulfurization (FGD)
system that significantly reduces the concentration of Hg emitted to
the atmosphere (including circulating fluidized bed units that use
limestone injection), or for a unit equipped with add-on Hg emission
controls (e.g., carbon injection), the standard missing data procedures
in paragraph (a) of this section may only be used for hours in which
the SO2 or Hg emission controls are documented to be
operating properly, as described in Sec. 75.58(b)(3). For any hour(s)
in the missing data period for which this documentation is unavailable,
the owner or operator shall report, as applicable, the maximum
potential Hg concentration, as defined in section 2.1.7 of appendix A
to this part or the maximum potential Hg emission rate, as defined in
section 2.1.7 of appendix A to this part. In addition, under Sec.
75.64(c), the designated representative shall submit as part of each
electronic quarterly report, a certification statement, verifying the
proper operation of the SO2 or Hg emission controls for each
missing data period in which the procedures in paragraph (a) of this
section are applied.
(c) For units with FGD systems or add-on Hg controls, when the
percent monitor data availability is less than 90.0 percent, and a
missing data period occurs, the owner or operator may petition to
report the maximum controlled Hg concentration or emission rate in the
previous 720 quality-assured monitor operating hours, consistent with
Sec. 75.34(a)(3).
Sec. 75.39 Missing data procedures for sorbent trap monitoring
systems.
(a) If a sorbent trap monitoring system has not been certified by
the applicable compliance date specified under a State or Federal Hg
mass emission reduction program that adopts the requirements of subpart
I of this part, the owner or operator shall report the maximum
potential Hg concentration, as defined in section 2.1.7 of appendix A
to this part, until the system is certified.
(b) For a certified sorbent trap system, a missing data period will
occur whenever:
(1) A gas sample is not extracted from the stack (e.g., during a
monitoring system malfunction or when the system undergoes
maintenance); or
(2) The results of the Hg analysis for either one (or both) of the
paired sorbent traps are missing or invalid (as determined using the
quality assurance procedures in section 8.3 of Method 324). The missing
data period begins with the hour in which the paired sorbent traps for
which the Hg analysis is missing or invalid were put into service. The
missing data period ends at the first hour in which valid Hg
concentration data are obtained with another pair of sorbent traps.
(c) Initial missing data procedures. Use these missing data
procedures until 720 hours of quality-assured data have been collected
with the sorbent trap monitoring system(s), following initial
certification. For each hour of the missing data period, the substitute
data value for Hg concentration shall be the average Hg concentration
from all valid sorbent trap analyses to date, including data from the
initial certification test runs.
(d) Standard missing data procedures. Once 720 quality-assured
hours of data have been obtained with the sorbent trap system(s), begin
reporting the percent monitor data availability in accordance with
Sec. 75.32 and switch from the initial missing data procedures in
paragraph (c) of this section to the following standard missing data
procedures:
(1) If the percent monitor data availability (PMA) at the end of
the missing data period is = 95.0%, report the average Hg
concentration for all valid sorbent trap analyses in the previous 12
months.
(2) If the PMA at the end of the missing data period is
=90.0%, but
[[Page 12458]]
<95.0%, report the highest Hg concentration obtained from all of the
valid sorbent trap analyses in the previous 12 months.
(3) If the PMA at the end of the missing data period is
= 80.0%, but <90.0%, report 1.5 times the highest Hg
concentration obtained from all of the valid sorbent trap analyses in
the previous 12 months.
(4) If the PMA at the end of the missing data period is <80.0%,
report the maximum potential Hg concentration, as defined in section
2.1.7 of appendix A to this part.
(5) For the purposes of paragraphs (d)(1), (d)(2), and (d)(3) of
this section, if fewer than 12 months have elapsed since initial
certification, use whatever valid sorbent trap analyses are available
to determine the appropriate substitute data values.
(e) Notwithstanding the requirements of paragraphs (c) and (d) of
this section, if the unit has add-on Hg emission controls or is
equipped with a flue gas desulfurization system that significantly
reduces Hg emissions, the owner or operator shall report the maximum
potential Hg concentration, as defined in section 2.1.7 of appendix A
to this part, for any hour(s) in the missing data period for which
proper operation of the Hg emission controls or FGD system is not
documented according to Sec. 75.58(b)(3).
15. Section 75.53 is amended by:
a. Revising paragraph (e)(1)(i)(E);
b. Revising paragraph (e)(1)(iv) introductory text; and
c. Revising paragraph (e)(1)(x).
The revisions read as follows:
Sec. 75.53 Monitoring plan.
* * * * *
(e) * * *
(1) * * *
(i) * * *
(E) Type(s) of emission controls for SO2,
NOX, Hg, and particulates installed or to be installed,
including specifications of whether such controls are pre-combustion,
post-combustion, or integral to the combustion process; control
equipment code, installation date, and optimization date; control
equipment retirement date (if applicable); primary/secondary controls
indicator; and an indicator for whether the controls are an original
installation;
* * * * *
(iv) Identification and description of each monitoring component
(including each monitor and its identifiable components, such as
analyzer and/or probe) in the CEMS (e.g., SO2 pollutant
concentration monitor, flow monitor, moisture monitor; NOX
pollutant concentration monitor, Hg monitor, and diluent gas monitor),
the continuous opacity monitoring system, or the excepted monitoring
system (e.g., fuel flowmeter, data acquisition and handling system),
including:
* * * * *
(x) For each parameter monitored: scale, maximum potential
concentration (and method of calculation), maximum expected
concentration (if applicable) (and method of calculation), maximum
potential flow rate (and method of calculation), maximum potential
NOX emission rate, maximum potential Hg emission rate, span
value, full-scale range, daily calibration units of measure, span
effective date/hour, span inactivation date/hour, indication of whether
dual spans are required, default high range value, flow rate span, and
flow rate span value and full scale value (in scfh) for each unit or
stack using SO2, NOX, CO2,
O2, Hg, or flow component monitors.
* * * * *
16. Section 75.57 is amended by adding new paragraphs (i) and (j)
to read as follows:
Sec. 75.57 General recordkeeping provisions.
* * * * *
(i) Hg emission record provisions (CEMS). The owner or operator
shall record for each hour the information required by this paragraph
for each affected unit using Hg CEMS in combination with flow rate,
moisture, and (in certain cases) diluent gas monitors, to determine Hg
mass emissions under a State or Federal Hg mass emissions reduction
program that adopts the requirements of subpart I of this part.
(1) For Hg concentration during unit operation, as measured and
reported from each certified primary monitor, certified back-up
monitor, or other approved method of emissions determination:
(i) Component-system identification code, as provided in Sec.
75.53;
(ii) Date and hour;
(iii) Hourly average Hg concentration ([mu]g/dscm, rounded to the
nearest tenth);
(iv) For Hg concentration monitoring systems only, record the bias-
adjusted hourly average Hg concentration ([mu]g/dscm, rounded to the
nearest tenth) if a bias adjustment factor is required, as provided in
Sec. 75.24(d);
(v) Method of determination for hourly average Hg concentration
using Codes 1-55 in Table 4a of this section; and
(vi) For Hg concentration monitoring systems only, record the
percent monitor data availability (to the nearest tenth of a percent),
calculated pursuant to Sec. 75.32.
(2) For flue gas moisture content during unit operation, as
measured and reported from each certified primary monitor, certified
back-up monitor, or other approved method of emissions determination
(except where a default moisture value is used in accordance with Sec.
75.11(b), Sec. 75.12(b), or approved under Sec. 75.66):
(i) Component-system identification code, as provided in Sec.
75.53;
(ii) Date and hour;
(iii) Hourly average moisture content of flue gas (percent, rounded
to the nearest tenth). If the continuous moisture monitoring system
consists of wet- and dry-basis oxygen analyzers, also record both the
wet- and dry-basis oxygen hourly averages (in percent O2,
rounded to the nearest tenth);
(iv) Percent monitor data availability (recorded to the nearest
tenth of a percent) for the moisture monitoring system, calculated
pursuant to Sec. 75.32; and
(v) Method of determination for hourly average moisture percentage,
using Codes 1-55 in Table 4a of this section.
(3) For diluent gas (O2 or CO2) concentration
during unit operation, as measured and reported from each certified
primary monitor, certified back-up monitor, or other approved method of
emissions determination:
(i) Component-system identification code, as provided in Sec.
75.53;
(ii) Date and hour;
(iii) Hourly average diluent gas (O2 or CO2)
concentration (in percent, rounded to the nearest tenth);
(iv) Method of determination code for diluent gas (O2 or
CO2) concentration data using Codes 1-55, in Table 4a of
this section; and
(v) If the diluent monitor is used only for heat input rate
determination, record the percent monitor data availability (to the
nearest tenth of a percent) for the O2 or CO2
monitoring system, calculated pursuant to Sec. 75.32.
(4) For stack gas volumetric flow rate during unit operation, as
measured and reported from each certified primary monitor, certified
back-up monitor, or other approved method of emissions determination,
record the information required under paragraphs (c)(2)(i) through
(c)(2)(vi) of this section.
(5) For Hg emission rate during unit operation, as measured and
reported from each certified primary Hg-diluent monitoring system,
certified back-up monitoring system, or other approved method of
emissions determination:
(i) Monitoring system identification code, as provided in Sec.
75.53;
(ii) Date and hour;
[[Page 12459]]
(iii) Hourly average Hg emission rate (in units of lb/10\12\ Btu,
rounded to three decimal places);
(iv) Hourly average Hg emission rate (in units of lb/10\12\ Btu,
rounded to three decimal places), adjusted for bias if a bias
adjustment factor is required, as provided in Sec. 75.24(d);
(v) Percent monitor data availability (recorded to the nearest
tenth of a percent), calculated pursuant to Sec. 75.32;
(vi) Method of determination for hourly average Hg emission rate,
using Codes 1-55 in Table 4a of this section;
(vii) Identification codes for emissions formulas used to derive
hourly average Hg emission rate and total Hg mass emissions, as
provided in Sec. 75.53; and
(viii) The F-factor used to convert Hg concentrations into emission
rates.
(6) For Hg mass emissions during unit operation, as measured and
reported from the certified primary monitoring system(s), certified
redundant or non-redundant back-up monitoring system(s), or other
approved method(s) of emissions determination:
(i) Date and hour;
(ii) Hourly Hg mass emissions (ounces, rounded to one decimal
place);
(iii) Hourly Hg mass emissions (ounces, rounded to one decimal
place), adjusted for bias if a bias adjustment factor is required, as
provided in Sec. 75.24(d); and
(iv) Identification code for emissions formula used to derive
hourly Hg mass emissions from Hg concentration, flow rate and moisture
data, as provided in Sec. 75.53.
(j) Hg emission record provisions (sorbent trap systems). The owner
or operator shall record for each hour the information required by this
paragraph, for each affected unit using sorbent trap monitoring systems
in combination with flow rate, moisture, and (in certain cases) diluent
gas monitors, to determine Hg mass emissions under a State or Federal
Hg mass emissions reduction program that adopts the requirements of
subpart I of this part.
(1) For Hg concentration during unit operation, as measured and
reported from each certified primary monitor, certified back-up
monitor, or other approved method of emissions determination:
(i) Component-system identification code, as provided in Sec.
75.53;
(ii) Date and hour;
(iii) Hourly average Hg concentration ([mu]g/dscm, rounded to the
nearest tenth);
(iv) The bias-adjusted hourly average Hg concentration ([mu]g/dscm,
rounded to the nearest tenth) if a bias adjustment factor is required,
as provided in Sec. 75.24(d);
(v) Method of determination for hourly average Hg concentration
using Codes 1-55 in Table 4a of this section; and
(vi) Percent monitor data availability (recorded to the nearest
tenth of a percent), calculated pursuant to Sec. 75.32;
(2) For flue gas moisture content during unit operation, as
measured and reported from each certified primary monitor, certified
back-up monitor, or other approved method of emissions determination
(except where a default moisture value is used in accordance with Sec.
75.11(b), Sec. 75.12(b), or approved under Sec. 75.66):
(i) Component-system identification code, as provided in Sec.
75.53;
(ii) Date and hour;
(iii) Hourly average moisture content of flue gas (percent, rounded
to the nearest tenth). If the continuous moisture monitoring system
consists of wet- and dry-basis oxygen analyzers, also record both the
wet- and dry-basis oxygen hourly averages (in percent O2,
rounded to the nearest tenth);
(iv) Percent monitor data availability (recorded to the nearest
tenth of a percent) for the moisture monitoring system, calculated
pursuant to Sec. 75.32; and
(v) Method of determination for hourly average moisture percentage,
using Codes 1-55 in Table 4a of this section.
(3) For diluent gas (O2 or CO2) concentration
during unit operation (if required for heat input determination),
record the information required under paragraph (g) of this section.
(4) For stack gas volumetric flow rate during unit operation, as
measured and reported from each certified primary monitor, certified
back-up monitor, or other approved method of emissions determination,
record the information required under paragraphs (c)(2)(i) through
(c)(2)(vi) of this section.
(5) For Hg mass emissions during unit operation, as measured and
reported from the certified primary monitoring system(s), certified
redundant or non-redundant back-up monitoring system(s), or other
approved method(s) of emissions determination, record the information
required under paragraph (i)(6) of this section.
(6) Record the average flow rate of stack gas through each sorbent
trap (in liters per minute, rounded to the nearest tenth), and the unit
or stack operating level (i.e., low, mid, or high, as defined in
section 6.5.2.1 of appendix A to this part) during the hour.
17. Section 75.58 is amended by revising paragraphs (b)(3)
introductory text, (b)(3)(i), and (b)(3)(ii) to read as follows:
Sec. 75.58 General recordkeeping provisions for specific situations.
* * * * *
(b) * * *
(3) Except as otherwise provided in Sec. 75.34(d), for units with
add-on SO2 or NOX emission controls following the
provisions of Sec. 75.34(a)(1), (a)(2) or (a)(3), or for units with
add-on Hg emission controls, the owner or operator shall record:
(i) Parametric data which demonstrate, for each hour of missing
SO2, Hg, or NOX emission data, the proper
operation of the add-on emission controls, as described in the quality
assurance/quality control program for the unit. The parametric data
shall be maintained on site and shall be submitted, upon request, to
the Administrator, EPA Regional office, State, or local agency;
(ii) A flag indicating, for each hour of missing SO2,
Hg, or NOX emission data, either that the add-on emission
controls are operating properly, as evidenced by all parameters being
within the ranges specified in the quality assurance/quality control
program, or that the add-on emission controls are not operating
properly;
* * * * *
18. Section 75.59 is amended by:
a. Revising the introductory text of paragraphs (a)(1),
(a)(3),(a)(5), (a)(5)(ii), (a)(6), and (a)(9);
b. Adding paragraphs (a)(7)(vii) and (a)(14);
c. Revising paragraph (a)(9)(vi); and
d. Revising the introductory text of paragraph (c).
The revisions read as follows:
Sec. 75.59 Certification, quality assurance, and quality control
record provisions.
* * * * *
(a) * * *
(1) For each SO2 or NOX pollutant
concentration monitor, flow monitor, CO2 pollutant
concentration monitor (including O2 monitors used to
determine CO2 emissions), Hg monitor, or diluent gas monitor
(including wet- and dry-basis O2 monitors used to determine
percent moisture), the owner or operator shall record the following for
all daily and 7-day calibration error tests and all off-line
calibration demonstrations, including any follow-up tests after
corrective action:
* * * * *
(3) For each SO2 or NOX pollutant
concentration monitor, CO2 pollutant concentration monitor
(including O2 monitors used to determine CO2
emissions), Hg concentration monitor, or diluent gas monitor (including
wet- and dry-basis O2 monitors used to determine percent
moisture), the owner
[[Page 12460]]
or operator shall record the following for the initial and all
subsequent linearity check(s) and converter checks (Hg monitors, only),
including any follow-up tests after corrective action:
* * * * *
[For Alternative 1 in Section II.B.3 of Appendix A to the
Preamble]:
(5) For each SO2 pollutant concentration monitor, flow
monitor, each CO2 pollutant concentration monitor (including
any O2 concentration monitor used to determine
CO2 mass emissions or heat input), each NOX-
diluent continuous emission monitoring system, each NOX
concentration monitoring system, each diluent gas (O2 or
CO2) monitor used to determine heat input, each moisture
monitoring system, each Hg concentration monitoring system, each Hg-
diluent monitoring system, each sorbent trap monitoring system, and
each approved alternative monitoring system, the owner or operator
shall record the following information for the initial and all
subsequent relative accuracy test audits:
[For Alternative 2 in Section II.B.3 of Appendix A to the
Preamble]:
(5) For each SO2 pollutant concentration monitor, flow
monitor, each CO2 pollutant concentration monitor (including
any O2 concentration monitor used to determine
CO2 mass emissions or heat input), each NOX-
diluent continuous emission monitoring system, each NOX
concentration monitoring system, each diluent gas (O2 or
CO2) monitor used to determine heat input, each moisture
monitoring system, each Hg concentration monitoring system, each Hg-
diluent monitoring system, each sorbent trap monitoring system, and
each approved alternative monitoring system, the owner or operator
shall record the following information for the initial and all
subsequent relative accuracy test audits. Also record the applicable
information for all periodic relative accuracy audits (RAAs) of sorbent
trap monitoring systems:
* * * * *
(ii) Individual test run data from the relative accuracy test audit
for the SO2 concentration monitor, flow monitor,
CO2 pollutant concentration monitor, NOX-diluent
continuous emission monitoring system, SO2-diluent
continuous emission monitoring system, diluent gas (O2 or
CO2) monitor used to determine heat input, NOX
concentration monitoring system, moisture monitoring system, Hg
concentration monitoring system, Hg-diluent monitoring system, sorbent
trap monitoring system, or approved alternative monitoring system,
including:
* * * * *
(6) For each SO2, NOX, Hg, or CO2
pollutant concentration monitor, NOX-diluent continuous
emission monitoring system, Hg-diluent continuous emission monitoring
system, NOX concentration monitoring system, or diluent gas
(O2 or CO2) monitor used to determine heat input,
the owner or operator shall record the following information for the
cycle time test:
* * * * *
(7) * * *
(vii) For each RATA run using the Ontario Hydro method to determine
Hg concentration:
(A) Percent CO2 and O2 in the stack gas, dry
basis;
(B) Moisture content of the stack gas (percent H2O);
(C) Average stack temperature ([deg]F);
(D) Dry gas volume metered (dscm);
(E) Percent isokinetic;
(F) Particle-bound Hg collected by the filter, blank, and probe
rinse ([mu]g);
(G) Oxidized Hg collected by the KCl impingers ([mu]g)
(H) Elemental Hg collected in the HNO3/
H2O2 impinger and in the KMnO4/
H2SO4 impingers ([mu]g);
(I) Total Hg, including particle-bound Hg ([mu]g); and
(J) Total Hg, excluding particle-bound Hg ([mu]g)
* * * * *
(9) When hardcopy relative accuracy test reports, certification
reports, recertification reports, or semiannual or annual reports for
gas or flow rate CEMS, Hg CEMS, or sorbent trap monitoring systems are
required or requested under Sec. 75.60(b)(6) or Sec. 75.63, the
reports shall include, at a minimum, the following elements (as
applicable to the type(s) of test(s) performed:
* * * * *
(vi) Laboratory calibrations of the source sampling equipment. For
sorbent trap monitoring systems, the laboratory analyses of all sorbent
traps, and information documenting the results of all Method 324 leak
checks and other quality control procedures.
* * * * *
(14) For the sorbent traps used in sorbent trap monitoring systems
to quantify Hg concentration under subpart I of this part (including
sorbent traps used for relative accuracy testing), the owner or
operator shall keep records of the following:
(i) The ID number of the monitoring system in which each sorbent
trap was used to collect Hg;
(ii) The unique identification number of each sorbent trap;
(iii) The beginning and ending dates and hours of the data
collection period for each sorbent trap;
(iv) The average Hg concentration (in [mu]g/dscm) for the data
collection period;
(v) Information documenting the results of the required Method 324
leak checks;
(vi) The Method 324 laboratory analysis of the Hg collected by each
sorbent trap; and
(vii) Information documenting the results of the applicable quality
control procedures in section 8.3 of Method 324.
* * * * *
(c) For units with add-on SO2 or NOX emission
controls following the provisions of Sec. 75.34(a)(1) or (a)(2), and
for units with add-on Hg emission controls, the owner or operator shall
keep the following records on-site in the quality assurance/quality
control plan required by section 1 of appendix B to this part: * * *
* * * * *
19. Part 75 is amended by adding Subpart I to read as follows:
Subpart I--Hg Mass Emission Provisions
Sec.
75.80 General provisions.
75.81 Monitoring of Hg mass emissions and heat input at the unit
level.
75.82 Monitoring of Hg mass emissions and heat input at common and
multiple stacks.
75.83 Calculation of Hg mass emissions and heat input rate.
75.84 Recordkeeping and reporting.
Sec. 75.80 General provisions.
(a) Applicability. The owner or operator of a unit shall comply
with the requirements of this subpart to the extent that compliance is
required by an applicable State or Federal Hg mass emission reduction
program that incorporates by reference, or otherwise adopts the
provisions of, this subpart.
(1) For purposes of this subpart, the term ``affected unit'' shall
mean any coal-fired unit (as defined in Sec. 72.2 of this chapter)
that is subject to a State or Federal Hg mass emission reduction
program requiring compliance with this subpart. The term ``non-affected
unit'' shall mean any unit that is not subject to such a program, the
term ``permitting authority'' shall mean the permitting authority under
an applicable State or Federal Hg mass emission reduction program that
adopts the requirements of this subpart, and the term ``designated
representative'' shall mean the responsible party under the applicable
State or Federal Hg mass emission reduction program that adopts the
requirements of this subpart.
[[Page 12461]]
(2) In addition, the provisions of subparts A, C, D, E, F, and G
and appendices A through G of this part applicable to Hg concentration,
flow rate, Hg emission rate and heat input, as set forth and referenced
in this subpart, shall apply to the owner or operator of a unit
required to meet the requirements of this subpart by a State or Federal
Hg mass emission reduction program. The requirements of this part for
SO2, NOX, CO2 and opacity monitoring,
recordkeeping and reporting do not apply to units that are subject only
to a State or Federal Hg mass emission reduction program that adopts
the requirements of this subpart, but are not affected units under the
Acid Rain Program or under a State or Federal NOX mass
emission reduction program that adopts the requirements of subpart H of
this part.
(b) Compliance dates. The owner or operator of an affected unit
shall meet the compliance deadlines established by an applicable State
or Federal Hg mass emission reduction program that adopts the
requirements of this subpart.
(c) Prohibitions.
(1) No owner or operator of an affected unit or a non-affected unit
under Sec. 75.82(b)(2)(ii) shall use any alternative monitoring
system, alternative reference method, or any other alternative for the
required continuous emission monitoring system without having obtained
prior written approval in accordance with paragraph (h) of this
section.
(2) No owner or operator of an affected unit or a non-affected unit
under Sec. 75.82(b)(2)(ii) shall operate the unit so as to discharge,
or allow to be discharged emissions of Hg to the atmosphere without
accounting for all such emissions in accordance with the applicable
provisions of this part.
(3) No owner or operator of an affected unit or a non-affected unit
under Sec. 75.82(b)(2)(ii) shall disrupt the continuous emission
monitoring system, any portion thereof, or any other approved emission
monitoring method, and thereby avoid monitoring and recording Hg mass
emissions discharged into the atmosphere, except for periods of
recertification or periods when calibration, quality assurance testing,
or maintenance is performed in accordance with the provisions of this
part applicable to monitoring systems under Sec. 75.81.
(4) No owner or operator of an affected unit or a non-affected unit
under Sec. 75.82(b)(2)(ii) shall retire or permanently discontinue use
of the continuous emission monitoring system, any component thereof, or
any other approved emission monitoring system under this part, except
under any one of the following circumstances:
(i) During the period that the unit is covered by a retired unit
exemption that is in effect under the State or Federal Hg mass emission
reduction program that adopts the requirements of this subpart; or
(ii) The owner or operator is monitoring Hg mass emissions from the
affected unit with another certified monitoring system approved, in
accordance with the provisions of paragraph (d) of this section; or
(iii) The designated representative submits notification of the
date of certification testing of a replacement monitoring system in
accordance with Sec. 75.61.
(d) Initial certification and recertification procedures.
(1) The owner or operator of an affected unit that is subject to
the Acid Rain Program or to a State or Federal NOX mass
emission reduction program that adopts the requirements of subpart H of
this part shall comply with the applicable initial certification and
recertification procedures in Sec. 75.20 and Sec. 75.70(d), except
that the owner or operator shall meet any additional requirements for
Hg-diluent continuous emission monitoring systems, Hg concentration
monitoring systems, sorbent trap monitoring systems (as defined in
Sec. 72.2 of this chapter), flow monitors, CO2 monitors,
O2 monitors, or moisture monitors, as set forth under Sec.
75.81, under the common stack provisions in Sec. 75.82, or under an
applicable State or Federal Hg mass emission reduction program that
adopts the requirements of this subpart.
(2) The owner or operator of an affected unit that is not subject
to the Acid Rain Program or to a State or Federal NOX mass
emission reduction program that adopts the requirements of subpart H of
this part shall comply with the initial certification and
recertification procedures established by an applicable State or
Federal Hg mass emission reduction program that adopts the requirements
of this subpart.
(e) Quality assurance and quality control requirements. For units
that use continuous emission monitoring systems to account for Hg mass
emissions, the owner or operator shall meet the applicable quality
assurance and quality control requirements in Sec. 75.21 and appendix
B to this part for the Hg-diluent continuous emission monitoring
systems, flow monitoring systems, Hg concentration monitoring systems,
moisture monitoring systems, and diluent monitors required under Sec.
75.81. Units using sorbent trap monitoring systems shall meet the
applicable quality assurance requirements of Method 324 and section 2.3
of appendix B to this part.
(f) Missing data procedures. Except as provided in Sec. 75.38(b)
and paragraph (g) of this section, the owner or operator shall provide
substitute data from monitoring systems required under Sec. 75.81 for
each affected unit as follows:
(1) For an owner or operator using continuous emissions monitoring
systems, substitute for missing data in accordance with the applicable
missing data procedures in `75.31 through Sec. 75.38 whenever the unit
combusts fuel and:
(i) A valid, quality-assured hour of Hg emission rate data (in lb/
10 12 Btu) has not been measured and recorded for a unit,
either by a certified Hg-diluent continuous emission monitoring system,
by an appropriate EPA reference method under Sec. 75.22, or by an
approved monitoring system under subpart E of this part; or
(ii) A valid, quality-assured hour of flow rate data (in scfh) has
not been measured and recorded for a unit either by a certified flow
monitor, by an appropriate EPA reference method under Sec. 75.22, or
by an approved alternative monitoring system under subpart E of this
part; or
(iii) A valid, quality-assured hour of heat input rate data (in
mmBtu/hr) has not been measured and recorded for a unit, either by
certified flow rate and diluent (CO2 or O2)
monitors, by appropriate EPA reference methods under Sec. 75.22, or by
approved alternative monitoring systems under subpart E of this part,
where heat input is required either for calculating Hg mass or
allocating allowances under the applicable State or Federal Hg mass
emission reduction program that adopts the requirements of this
subpart; or
(iv) A valid, quality-assured hour of Hg concentration data (in
micrograms per dry standard cubic meter) has not been measured and
recorded, either by a certified Hg concentration monitoring system, by
an appropriate EPA reference method under Sec. 75.22, or by an
approved alternative monitoring method under subpart E of this part,
where the owner or operator chooses to use a Hg concentration
monitoring system with a flow monitor to calculate Hg mass emissions;
or
(v) A valid, quality-assured hour of moisture data (in percent
H2O) has not been measured or recorded for an affected unit,
either by a certified moisture monitoring system, by an appropriate EPA
reference method under Sec. 75.22, or an approved alternative
monitoring method under subpart E of this part. This requirement
[[Page 12462]]
does not apply when a default percent moisture value, as provided in
Sec. 75.11(b) or Sec. 75.12(b), is used to account for the hourly
moisture content of the stack gas.
(2) For an owner or operator using a sorbent trap monitoring system
to quantify Hg mass emissions, substitute for missing data in
accordance with the missing data procedures in Sec. 75.39.
(g) Reporting data prior to initial certification. If, by the
applicable compliance date under the State or Federal Hg mass emission
reduction program that adopts the requirements of this subpart, the
owner or operator of an affected unit has not successfully completed
all required certification tests for any monitoring system(s), he or
she shall determine, record and report hourly data prior to initial
certification using one of the following procedures, for the monitoring
system(s) that are uncertified:
(1) If Hg mass emissions are determined from the Hg emission rate
and the heat input rate, report the maximum potential Hg emission rate
(as defined in section 2.1.7 of appendix A to this part), the maximum
potential flow rate, as defined in section 2.1.4.1 of appendix A to
this part, and, for heat input rate determinations, the maximum
potential CO2 concentration, as defined in section 2.1.3.1
of appendix A to this part, the minimum potential O2
concentration, as defined in section 2.1.3.2 of appendix A to this
part, and the minimum potential percent moisture, as defined in section
2.1.5 of appendix A to this part.
(2) If Hg mass emissions are determined using a Hg concentration
monitoring system or a sorbent trap monitoring system and a flow
monitoring system, report the maximum potential concentration of Hg as
defined in section 2.1.7 of appendix A to this part and the maximum
potential flow rate, as defined in section 2.1.4.1 of appendix A to
this part;
(3) For any unit, report data from the reference methods under
Sec. 75.22.
(4) For any unit using the procedures in paragraph (g)(2) of this
section that is required to report heat input for purposes of
allocating allowances, report the maximum potential flow rate, as
defined in section 2.1.4.1 of appendix A to this part, the maximum
potential CO2 concentration, as defined in section 2.1.3.1
of appendix A to this part, the minimum potential O2
concentration, as defined in section 2.1.3.2 of appendix A to this
part, and the minimum potential percent moisture, as defined in section
2.1.5 of appendix A to this part.
(h) Petitions.
(1) The designated representative of an affected unit that is also
subject to the Acid Rain Program may submit a petition to the
Administrator requesting an alternative to any requirement of this
subpart. Such a petition shall meet the requirements of Sec. 75.66 and
any additional requirements established by the applicable State or
Federal Hg mass emission reduction program that adopts the requirements
of this subpart. Use of an alternative to any requirement of this
subpart is in accordance with this subpart and with such State or
Federal Hg mass emission reduction program only to the extent that the
petition is approved by the Administrator, in consultation with the
permitting authority.
(2) Notwithstanding paragraph (h)(1) of this section, petitions
requesting an alternative to a requirement concerning any additional
CEMS required solely to meet the common stack provisions of Sec. 75.82
shall be submitted to the permitting authority and the Administrator
and shall be governed by paragraph (h)(3) of this section. Such a
petition shall meet the requirements of Sec. 75.66 and any additional
requirements established by an applicable State or Federal Hg mass
emission reduction program that adopts the requirements of this
subpart.
(3) The designated representative of an affected unit that is not
subject to the Acid Rain Program may submit a petition to the
permitting authority and the Administrator requesting an alternative to
any requirement of this subpart. Such a petition shall meet the
requirements of Sec. 75.66 and any additional requirements established
by the applicable State or Federal Hg mass emission reduction program
that adopts the requirements of this subpart. Use of an alternative to
any requirement of this subpart is in accordance with this subpart only
to the extent that it is approved by the Administrator and by the
permitting authority.
Sec. 75.81 Monitoring of Hg mass emissions and heat input at the unit
level.
The owner or operator of the affected coal-fired unit shall either:
(a) Meet the general operating requirements in Sec. 75.10 for the
following continuous emission monitors (except as provided in
accordance with subpart E of this part):
(1) A Hg-diluent continuous emission monitoring system (consisting
of a Hg pollutant concentration monitor, an O2 or
CO2 diluent gas monitor, and an automated data acquisition
and handling system) to measure Hg emission rate in lb/10 12
Btu; and
(2) A flow rate monitoring system; and
(3) An O2 or CO2 diluent gas monitor to
measure heat input rate; and
(4) A continuous moisture monitoring system, as described in Sec.
75.11(b) or Sec. 75.12(b). Alternatively, the owner or operator may
use the appropriate fuel-specific default moisture value provided in
Sec. 75.11 or Sec. 75.12, or a site-specific moisture value approved
by petition under Sec. 75.66; or
(b) Meet the general operating requirements in Sec. 75.10 for the
following continuous emission monitors (except as provided in
accordance with subpart E of this part):
[For Alternative 1 in Section II.B.3 of Appendix A to the
Preamble]:
(1) A Hg concentration monitoring system (consisting of a Hg
pollutant concentration monitor and a n automated data acquisition and
handling system) or, for affected units that qualify, a sorbent trap
monitoring system (as defined in Sec. 72.2 of this chapter) to measure
Hg concentration. The use of sorbent trap monitoring systems is
restricted to affected units with estimated average Hg mass emissions
of 144 ounces (9 lbs) or less for the same three calendar years that
are used to allocate the Hg allowances; and
[For Alternative 2 in Section II.B.3 of Appendix A to the
Preamble]:
(1) A Hg concentration monitoring system (consisting of a Hg
pollutant concentration monitor and a n automated data acquisition and
handling system) or, for affected units that qualify, a sorbent trap
monitoring system (as defined in Sec. 72.2 of this chapter) to measure
Hg concentration; and
(2) A flow rate monitoring system; and
(3) A continuous moisture monitoring system, as described in Sec.
75.11(b) or Sec. 75.12(b). Alternatively, the owner or operator may
use the appropriate fuel-specific default moisture value provided in
Sec. 75.11 or Sec. 75.12, or a site-specific moisture value approved
by petition under Sec. 75.66; and
(4) If heat input is required to be reported under the applicable
State or Federal Hg mass emission reduction program that adopts the
requirements of this subpart, the owner or operator also must meet the
general operating requirements for a flow monitoring system and an
O2 or CO2 monitoring system to measure heat input
rate.
(c) Notwithstanding the provisions of paragraph (b)(1) of this
section, the owner or operator shall quantify mercury mass emissions
using either a mercury concentration CEMS or a
[[Page 12463]]
mercury-diluent CEMS for any affected unit that commences operation
more than 6 months after the date of publication of a final rule
implementing a State or Federal Hg mass emission reduction program that
adopts the requirements of this subpart.
Sec. 75.82 Monitoring of Hg mass emissions and heat input at common
and multiple stacks.
(a) Unit utilizing common stack with other affected unit(s). When
an affected unit utilizes a common stack with one or more affected
units, but no non-affected units, the owner or operator shall either:
(1) Install, certify, operate, and maintain the monitoring systems
described in Sec. 75.81(a) or Sec. 75.81(b) at the common stack,
record the combined Hg mass emissions for the units exhausting to the
common stack, and, where unit heat input rate determination is
required, determine the hourly unit heat input rates by either:
(i) Apportioning the common stack heat input rate to the individual
units according to the procedures in Sec. 75.16(e)(3); or
(ii) Installing, certifying, operating, and maintaining a flow
monitoring system and diluent monitor in the duct to the common stack
from each unit; or
(2) Install, certify, operate, and maintain the monitoring systems
described in Sec. 75.81(a) or Sec. 75.81(b) in the duct to the common
stack from each unit.
(b) Unit utilizing common stack with nonaffected unit(s). When one
or more affected units utilizes a common stack with one or more
nonaffected units, the owner or operator shall either:
(1) Install, certify, operate, and maintain the monitoring systems
described in Sec. 75.81(a) or Sec. 75.81(b) in the duct to the common
stack from each affected unit; or
(2) Install, certify, operate, and maintain the monitoring systems
described in Sec. 75.81(a) or Sec. 75.81(b) in the common stack; and
(i) Install, certify, operate, and maintain the monitoring systems
described in Sec. 75.81(a) or Sec. 75.81(b) in the common stack and
in the duct to the common stack from each non-affected unit. The
designated representative shall submit a petition to the permitting
authority and the Administrator to allow a method of calculating and
reporting the Hg mass emissions from the affected units as the
difference between Hg mass emissions measured in the common stack and
Hg mass emissions measured in the ducts of the non-affected units, not
to be reported as an hourly value less than zero. The permitting
authority and the Administrator may approve such a method whenever the
designated representative demonstrates, to the satisfaction of the
permitting authority and the Administrator, that the method ensures
that the Hg mass emissions from the affected units are not
underestimated; or
(ii) Count the combined emissions measured at the common stack as
the Hg mass emissions for the affected units, for recordkeeping and
compliance purposes, in accordance with paragraph (a) of this section;
or
(iii) Submit a petition to the permitting authority and the
Administrator to allow use of a method for apportioning Hg mass
emissions measured in the common stack to each of the units using the
common stack and for reporting the Hg mass emissions. The permitting
authority and the Administrator may approve such a method whenever the
designated representative demonstrates, to the satisfaction of the
permitting authority and the Administrator, that the method ensures
that the Hg mass emissions from the affected units are not
underestimated.
(c) Unit with a main stack and a bypass stack. Whenever any portion
of the flue gases from an affected unit can be routed through a bypass
stack to avoid the Hg monitoring system(s) installed on the main stack,
the owner and operator shall either:
(1) Install, certify, operate, and maintain the monitoring systems
described in Sec. 75.81(a) or Sec. 75.81(b) on both the main stack
and the bypass stack and calculate Hg mass emissions for the unit as
the sum of the Hg mass emissions measured at the two stacks;
(2) Install, certify, operate, and maintain the monitoring systems
described in Sec. 75.81(a) or Sec. 75.81(b) at the main stack and
measure Hg mass emissions at the bypass stack using the appropriate
reference methods in Sec. 75.22(b). Calculate Hg mass emissions for
the unit as the sum of the emissions recorded by the installed
monitoring systems on the main stack and the emissions measured by the
reference method monitoring systems; or
(3) Install, certify, operate, and maintain the monitoring systems
described in Sec. 75.81(a) or Sec. 75.81(b) only on the main stack.
If this option is chosen, it is not necessary to designate the exhaust
configuration as a multiple stack configuration in the monitoring plan
required under Sec. 75.53, since only the main stack is monitored. For
each unit operating hour in which the bypass stack is used, report, as
applicable, the maximum potential Hg emission rate (as defined in
section 2.1.7 of appendix A to this part), and the appropriate
substitute data values for flow rate, CO2 concentration,
O2 concentration, and moisture (as applicable), in
accordance with the missing data procedures of Sec. 75.31 through
Sec. 75.37.
(d) Unit with multiple stack or duct configuration. When the flue
gases from an affected unit discharge to the atmosphere through more
than one stack, or when the flue gases from an affected unit utilize
two or more ducts feeding into a single stack and the owner or operator
chooses to monitor in the ducts rather than in the stack, the owner or
operator shall either:
(1) Install, certify, operate, and maintain the monitoring systems
described in Sec. 75.81(a) or Sec. 75.81(b) in each of the multiple
stacks and determine Hg mass emissions from the affected unit as the
sum of the Hg mass emissions recorded for each stack. If another unit
also exhausts flue gases into one of the monitored stacks, the owner or
operator shall comply with the applicable requirements of paragraphs
(a) and (b) of this section, in order to properly determine the Hg mass
emissions from the units using that stack; or
(2) Install, certify, operate, and maintain the monitoring systems
described in Sec. 75.81(a) or Sec. 75.81(b) in each of the ducts that
feed into the stack, and determine Hg mass emissions from the affected
unit using the sum of the Hg mass emissions measured at each duct,
except that where another unit also exhausts flue gases to one or more
of the stacks, the owner or operator shall also comply with the
applicable requirements of paragraphs (a) and (b) of this section to
determine and record Hg mass emissions from the units using that stack.
Sec. 75.83 Calculation of Hg mass emissions and heat input rate.
The owner or operator shall calculate Hg mass emissions and heat
input rate in accordance with the procedures in sections 9.1 through
9.3 of appendix F to this part.
Sec. 75.84 Recordkeeping and reporting.
(a) General recordkeeping provisions. The owner or operator of any
affected unit shall maintain for each affected unit and each non-
affected unit under Sec. 75.82(b)(2)(ii) a file of all measurements,
data, reports, and other information required by this part at the
source in a form suitable for inspection for at least three (3) years
from the date of each record. Except for the certification data
required in Sec. 75.57(a)(4) and the initial submission
[[Page 12464]]
of the monitoring plan required in Sec. 75.57(a)(5), the data shall be
collected beginning with the earlier of the date of provisional
certification or the compliance deadline in Sec. 75.80(b). The
certification data required in Sec. 75.57(a)(4) shall be collected
beginning with the date of the first certification test performed. The
file shall contain the following information:
(1) The information required in Sec. Sec. 75.57(a)(2), (a)(4),
(a)(5), (a)(6), (b), (c)(2), (g) (if applicable), (h), and (i) or (j)
(as applicable). For the information in Sec. 75.57(a)(2), replace the
phrase ``the deadline in Sec. 75.4(a), (b) or (c)'' with the phrase
``the applicable certification deadline under the State or Federal Hg
mass emission reduction program'';
(2) The information required in Sec. 75.58(b)(3), for units with
flue gas desulfurization systems or add-on Hg emission controls;
(3) For affected units using Hg CEMS or sorbent trap monitoring
systems, for each hour when the unit is operating, record the Hg mass
emissions, calculated in accordance with section 9 of appendix F to
this part.
(4) Heat input and Hg methodologies for the hour; and
(5) Formulas from monitoring plan for total Hg mass emissions and
heat input rate (if applicable);
(b) Certification, quality assurance and quality control record
provisions. The owner or operator of any affected unit shall record the
applicable information in Sec. 75.59 for each affected unit or group
of units monitored at a common stack and each non-affected unit under
Sec. 75.82(b)(2)(ii).
(c) Monitoring plan recordkeeping provisions.
(1) General provisions. The owner or operator of an affected unit
shall prepare and maintain a monitoring plan for each affected unit or
group of units monitored at a common stack and each non-affected unit
under Sec. 75.82(b)(2)(ii). The monitoring plan shall contain
sufficient information on the continuous monitoring systems and the use
of data derived from these systems to demonstrate that all the unit's
Hg emissions are monitored and reported.
(2) Updates. Whenever the owner or operator makes a replacement,
modification, or change in a certified continuous monitoring system or
alternative monitoring system under subpart E of this part, including a
change in the automated data acquisition and handling system or in the
flue gas handling system, that affects information reported in the
monitoring plan (e.g., a change to a serial number for a component of a
monitoring system), then the owner or operator shall update the
monitoring plan.
(3) Contents of the monitoring plan. Each monitoring plan shall
contain the information in Sec. 75.53(e)(1) in electronic format and
the information in Sec. 75.53(e)(2) in hardcopy format.
(d) General reporting provisions.
(1) The designated representative for an affected unit shall comply
with all reporting requirements in this section and with any additional
requirements set forth in an applicable State or Federal Hg mass
emission reduction program that adopts the requirements of this
subpart.
(2) The designated representative for an affected unit shall submit
the following for each affected unit or group of units monitored at a
common stack and each non-affected unit under Sec. 75.82(b)(2)(ii):
(i) Initial certification and recertification applications in
accordance with Sec. 75.80(d);
(ii) Monitoring plans in accordance with paragraph (e) of this
section; and
(iii) Quarterly reports in accordance with paragraph (f) of this
section.
(3) Other petitions and communications. The designated
representative for an affected unit shall submit petitions,
correspondence, application forms, and petition-related test results in
accordance with the provisions in Sec. 75.80(h).
[For Alternative 1 in Section II.B.3 of Appendix A to the
Preamble]:
(4) Quality assurance RATA reports. If requested by the permitting
authority, the designated representative of an affected unit shall
submit the quality assurance RATA report for each affected unit or
group of units monitored at a common stack and each non-affected unit
under Sec. 75.82(b)(2)(ii) by the later of 45 days after completing a
quality assurance RATA according to section 2.3 of appendix B to this
part or 15 days of receiving the request. The designated representative
shall report the hardcopy information required by Sec. 75.59(a)(9) to
the permitting authority.
[For Alternative 2 in Section II.B.3 of Appendix A to the
Preamble]:
(4) Quality assurance RATA (or RAA) reports. If requested by the
permitting authority, the designated representative of an affected unit
shall submit the quality assurance RATA or RAA report for each affected
unit or group of units monitored at a common stack and each non-
affected unit under Sec. 75.82(b)(2)(ii) by the later of 45 days after
completing a quality assurance RATA or RAA according to section 2.3 of
appendix B to this part or 15 days of receiving the request. The
designated representative shall report the hardcopy information
required by Sec. 75.59(a)(9) to the permitting authority.
(5) Notifications. The designated representative for an affected
unit shall submit written notice to the permitting authority according
to the provisions in Sec. 75.61 for each affected unit or group of
units monitored at a common stack and each non-affected unit under
Sec. 75.82(b)(2)(ii).
(e) Monitoring plan reporting.
(1) Electronic submission. The designated representative for an
affected unit shall submit to the Administrator a complete, electronic,
up-to-date monitoring plan file for each affected unit or group of
units monitored at a common stack and each non-affected unit under
Sec. 75.82(b)(2)(ii), as follows: no later than 45 days prior to the
commencement of initial certification testing; at the time of a
certification or recertification application submission; and whenever
an update of the electronic monitoring plan is required, either under
Sec. 75.53 or elsewhere in this part.
(2) Hardcopy submission. The designated representative of an
affected unit shall submit all of the hardcopy information required
under Sec. 75.53, for each affected unit or group of units monitored
at a common stack and each non-affected unit under Sec.
75.82(b)(2)(ii), to the permitting authority prior to initial
certification. Thereafter, the designated representative shall submit
hardcopy information only if that portion of the monitoring plan is
revised. The designated representative shall submit the required
hardcopy information as follows: no later than 45 days prior to the
commencement of initial certification testing; with any certification
or recertification application, if a hardcopy monitoring plan change is
associated with the recertification event; and within 30 days of any
other event with which a hardcopy monitoring plan change is associated,
pursuant to Sec. 75.53(b). Electronic submittal of all monitoring plan
information, including hardcopy portions, is permissible provided that
a paper copy of the hardcopy portions can be furnished upon request.
(f) Quarterly reports.
(1) Electronic submission. Electronic quarterly reports shall be
submitted , beginning with the calendar quarter containing the
compliance date in Sec. 75.80(b), unless otherwise specified in the
final rule implementing a State or Federal Hg mass emissions reduction
program that adopts the requirements of this subpart. The designated
representative for an affected unit shall report the data and
information in this paragraph (f)(1) and the applicable
[[Page 12465]]
compliance certification information in paragraph (f)(2) of this
section to the Administrator quarterly. Each electronic report must be
submitted to the Administrator within 30 days following the end of each
calendar quarter. Each electronic report shall include the date of
report generation and the following information for each affected unit
or group of units monitored at a common stack:
(i) The facility information in Sec. 75.64(a)(1); and
(ii) The information and hourly data required in paragraph (a) of
this section, except for:
(A) Descriptions of adjustments, corrective action, and
maintenance;
(B) Information which is incompatible with electronic reporting
(e.g., field data sheets, lab analyses, quality control plan);
(C) For units with flue gas desulfurization systems or with add-on
Hg emission controls, the information in Sec. 75.58(b)(3);
(D) Information required by Sec. 75.57(h) concerning the causes of
any missing data periods and the actions taken to cure such causes;
(E) Hardcopy monitoring plan information required by Sec. 75.53
and hardcopy test data and results required by Sec. 75.59;
(F) Records of flow polynomial equations and numerical values
required by Sec. 75.59(a)(5)(vi);
(G) Stratification test results required as part of the RATA
supplementary records under Sec. 75.59(a)(7);
[For Alternative 1 in Section II.B.3 of Appendix A to the
Preamble]:
(H) Data and results of RATAs that are aborted or invalidated due
to problems with the reference method or operational problems with the
unit and data and results of linearity checks that are aborted or
invalidated due to operational problems with the unit; and
(I) Supplementary RATA information required under Sec.
75.59(a)(7)(i) through Sec. 75.59(a)(14), as applicable, except that:
The data under Sec. 75.59(a)(7)(ii)(A) through (T) and the data under
Sec. 75.59(a)(7)(iii)(A) through (M) shall, as applicable, be reported
for flow RATAs in which angular compensation (measurement of pitch and/
or yaw angles) is used and for flow RATAs in which a site-specific wall
effects adjustment factor is determined by direct measurement; and the
data under Sec. 75.59(a)(7)(ii)(T) shall be reported for all flow
RATAs in which a default wall effects adjustment factor is applied; and
[For Alternative 2 in Section II.B.3 of Appendix A to the
Preamble]:
(H) Data and results of RATAs (or RAAs) that are aborted or
invalidated due to problems with the reference method or operational
problems with the unit and data and results of linearity checks that
are aborted or invalidated due to operational problems with the unit;
and
(I) Supplementary RATA (or RAA) information required under Sec.
75.59(a)(7)(i) through Sec. 75.59(a)(14), as applicable, except that:
The data under Sec. 75.59(a)(7)(ii)(A) through (T) and the data under
Sec. 75.59(a)(7)(iii)(A) through (M) shall, as applicable, be reported
for flow RATAs in which angular compensation (measurement of pitch and/
or yaw angles) is used and for flow RATAs in which a site-specific wall
effects adjustment factor is determined by direct measurement; and the
data under Sec. 75.59(a)(7)(ii)(T) shall be reported for all flow
RATAs in which a default wall effects adjustment factor is applied; and
(iii) If a Hg-diluent monitoring system is used to quantify Hg mass
emissions, the average Hg emission rate during the quarter (lb/
1012 Btu, rounded to three decimal places) and the average
Hg emission rate for the year-to-date; and
(iv) Ounces of Hg emitted during quarter and cumulative ounces of
Hg emitted in the year-to-date (rounded to the nearest tenth); and
(v) Unit or stack operating hours for quarter, cumulative unit or
stack operating hours for year-to-date; and
(vi) Reporting period heat input (if applicable) and cumulative,
year-to-date heat input.
(2) Compliance certification.
(i) The designated representative shall certify that the monitoring
plan information in each quarterly electronic report (i.e., component
and system identification codes, formulas, etc.) represent current
operating conditions for the affected unit(s)
(ii) The designated representative shall submit and sign a
compliance certification in support of each quarterly emissions
monitoring report based on reasonable inquiry of those persons with
primary responsibility for ensuring that all of the unit's emissions
are correctly and fully monitored. The certification shall state that:
(1) The monitoring data submitted were recorded in accordance with
the applicable requirements of this part, including the quality
assurance procedures and specifications; and
(2) With regard to a unit with an FGD system or with add-on Hg
emission controls, that for all hours where data are substituted in
accordance with Sec. 75.38(b), the add-on emission controls were
operating within the range of parameters listed in the quality-
assurance plan for the unit, and that the substitute values do not
systematically underestimate Hg emissions.
(3) Additional reporting requirements. The designated
representative shall also comply with all of the quarterly reporting
requirements in Sec. Sec. 75.64(d), (f), and (g).
20. Appendix A to 40 CFR part 75 is amended by revising the title
of section 1.1 and revising the second sentence of section 1.1
introductory text to read as follows:
Appendix A to Part 75--Specifications and Test Procedures
1. Installation and Measurement Location
1.1 Gas and Hg Monitors
* * * Select a representative measurement point or path for the
monitor probe(s) (or for the path from the transmitter to the
receiver) such that the SO2, CO2,
O2, or NOX concentration monitoring system or
NOX-diluent continuous emission monitoring system
(NOX pollutant concentration monitor and diluent gas
monitor), Hg concentration monitoring system, Hg-diluent monitoring
system, or sorbent trap monitoring system will pass the relative
accuracy test (see section 6 of this appendix).
* * * * *
Appendix A to Part 75--[Amended]
21. Appendix A to part 75 is further amended by adding new sections
2.1.7 through 2.1.7.4 and 2.2.3 to read as follows:
2. Equipment Specifications
* * * * *
2.1.7 Hg Monitors
Determine the appropriate span and range value(s) for each Hg
pollutant concentration monitor, so that all expected Hg
concentrations can be determined accurately.
2.1.7.1 Maximum Potential Concentration
(a) The maximum potential concentration depends upon the type of
coal combusted in the unit. For the initial MPC determination, there
are three options:
(1) Use one of the following default values: 9 [mu]g/dscm for
bituminous coal; 10 [mu]g/dscm for sub-bituminous coal; 16 [mu]g/
dscm for lignite, and 1 [mu]g/dscm for waste coal, i.e., anthracite
culm or bituminous gob (if different coals are blended, use the
highest MPC for any fuel in the blend); or
(2) You may base the MPC on the results of site-specific
emission testing using the Ontario Hydro method, if the unit does
not have add-on Hg emission controls or a flue gas desulfurization
system, or if you test upstream of these control devices. A minimum
of 3 test runs, two hours (or more) in duration, are required, at
the normal operating load. Use the highest total Hg concentration
obtained in any of the tests as the MPC; or
(3) You may base the MPC on 720 or more hours of historical CEMS
data, if the unit does not have add-on Hg emission controls or a
flue gas desulfurization system (or if the CEMS is located upstream
of these control
[[Page 12466]]
devices) and if the Hg CEMS that has been tested for relative
accuracy against the Ontario Hydro method and has met a relative
accuracy specification of 20.0% or less.
(b) If a Hg-diluent monitoring system is used to quantify Hg
mass emissions, calculate (for purposes of missing data
substitution) the maximum potential Hg emission rate (MER), in lb/
1012 Btu. To determine the MER, use the appropriate
emission rate equation from section 9 of appendix F to this part,
substituting into the equation the MPC value, the minimum expected
CO2 concentration or maximum expected O2
concentration during normal operation (excluding unit startup,
shutdown and process upsets), the expected stack gas moisture
content (if applicable), and the appropriate F-factor.
(c) For the purposes of missing data substitution, the fuel-
specific or site-specific MPC values defined in paragraph (a) of
this section apply to units using sorbent trap monitoring systems.
2.1.7.2 Maximum Expected Concentration
For units with FGD systems that significantly reduce Hg
emissions (including fluidized bed units that use limestone
injection) and for units equipped with add-on Hg emission controls
(e.g., carbon injection), determine the maximum expected Hg
concentration (MEC) during normal, stable operation of the unit and
emission controls. To calculate the MEC, substitute the MPC value
from section 2.1.7.1 of this appendix into Equation A-2 in section
2.1.1.2 of this appendix. For units with add-on Hg emission
controls, base the percent removal efficiency on design engineering
calculations. For units with FGD systems, use the best available
estimate of the Hg removal efficiency of the FGD system.
2.1.7.3 Span and Range Value(s)
(a) For each Hg monitor, determine a high span value, by
rounding the MPC value from section 2.1.7.1 of this appendix upward
to the next highest multiple of 10 [mu]g/dscm.
(b) For an affected unit equipped with an FGD system or a unit
with add-on Hg emission controls, if the MEC value from section
2.1.7.2 of this appendix is less than 20 percent of the high span
value from paragraph (a) of this section, and if the high span value
is 20 [mu]g/dscm or greater, define a second, low span value of 10
[mu]g/dscm.
(c) If only a high span value is required, set the full-scale
range of the Hg analyzer to be greater than or equal to the span
value.
(d) If two span values are required, you may either:
(1) Use two separate (high and low) measurement scales, setting
the range of each scale to be greater than or equal to the high or
low span value, as appropriate; or
(2) Quality-assure two segments of a single measurement scale.
2.1.7.4 Adjustment of Span and Range
For each affected unit or common stack, the owner or operator
shall make a periodic evaluation of the MPC, MEC, span, and range
values for each Hg monitor (at a minimum, an annual evaluation is
required) and shall make any necessary span and range adjustments,
with corresponding monitoring plan updates. Span and range
adjustments may be required, for example, as a result of changes in
the fuel supply, changes in the manner of operation of the unit, or
installation or removal of emission controls. In implementing the
provisions in paragraphs (a) and (b) of this section, data recorded
during short-term, non-representative process operating conditions
(e.g., a trial burn of a different type of fuel) shall be excluded
from consideration. The owner or operator shall keep the results of
the most recent span and range evaluation on-site, in a format
suitable for inspection. Make each required span or range adjustment
no later than 45 days after the end of the quarter in which the need
to adjust the span or range is identified, except that up to 90 days
after the end of that quarter may be taken to implement a span
adjustment if the calibration gases currently being used for daily
calibration error tests and linearity checks are unsuitable for use
with the new span value.
(a) The guidelines of section 2.1 of this appendix do not apply
to Hg monitoring systems.
(b) Whenever a full-scale range exceedance occurs during a
quarter and is not caused by a monitor out-of-control period,
proceed as follows:
(1) For monitors with a single measurement scale, report 200
percent of the full-scale range as the hourly Hg concentration until
the readings come back on-scale and if appropriate, make adjustments
to the MPC, span, and range to prevent future full-scale
exceedances; or
(2) For units with two separate measurement scales, if the low
range is exceeded, no further action is required, provided that the
high range is available and is not out-of-control or out-of-service
for any reason. However, if the high range is not able to provide
quality assured data at the time of the low range exceedance or at
any time during the continuation of the exceedance, report the MPC
until the readings return to the low range or until the high range
is able to provide quality assured data (unless the reason that the
high-scale range is not able to provide quality assured data is
because the high-scale range has been exceeded; if the high-scale
range is exceeded follow the procedures in paragraph (b)(1) of this
section).
(c) Whenever changes are made to the MPC, MEC, full-scale range,
or span value of the Hg monitor, record and report (as applicable)
the new full-scale range setting, the new MPC or MEC and
calculations of the adjusted span value in an updated monitoring
plan. The monitoring plan update shall be made in the quarter in
which the changes become effective. In addition, record and report
the adjusted span as part of the records for the daily calibration
error test and linearity check specified by appendix B to this part.
Whenever the span value is adjusted, use calibration gas
concentrations that meet the requirements of section 5.1 of this
appendix, based on the adjusted span value. When a span adjustment
is so significant that the calibration gases currently being used
for daily calibration error tests and linearity checks are
unsuitable for use with the new span value, then a diagnostic
linearity test using the new calibration gases must be performed and
passed. Use the data validation procedures in Sec. 75.20(b)(3),
beginning with the hour in which the span is changed.
2.2 Design for Quality Control Testing
* * * * *
2.2.3 Mercury Monitors
Design and equip each mercury monitor to permit the introduction
of known concentrations of elemental Hg and HgCl2
separately, at a point immediately preceding the sample extraction
filtration system, such that the entire measurement system can be
checked.
Appendix A to Part 75--[Amended]
22. Appendix A to part 75 is further amended by:
a. Adding a new paragraph (c) to section 3.1;
b. Revising section 3.2; and
c. Adding new sections 3.3.8 and 3.4.3.
The revisions and additions read as follows:
3. Performance Specifications
3.1 Calibration Error
* * * * *
(c) The calibration error of a Hg concentration monitor shall
not deviate from the reference value of either the zero or upscale
calibration gas by more than 5.0 percent of the span value, as
calculated using Equation A-5 of this appendix. Alternatively, if
the span value is 10 [mu]g/dscm, the calibration error test results
are also acceptable if the absolute value of the difference between
the monitor response value and the reference value, [bond] R-A
[bond] in Equation A-5 of this appendix, is <=1.0 [mu]g/dscm.
3.2 Linearity Check
(a) For SO2 and NOX pollutant
concentration monitors, the error in linearity for each calibration
gas concentration (low-, mid-, and high-levels) shall not exceed or
deviate from the reference value by more than 5.0 percent (as
calculated using equation A-4 of this appendix). Linearity check
results are also acceptable if the absolute value of the difference
between the average of the monitor response values and the average
of the reference values, [bond] R-A [bond] in equation A-4 of this
appendix, is less than or equal to 5 ppm.
(b) For CO2 or O2 monitors (including
O2 monitors used to measure CO2 emissions or
percent moisture):
(1) The error in linearity for each calibration gas
concentration (low-, mid-, and high-levels) shall not exceed or
deviate from the reference value by more than 5.0 percent as
calculated using equation A-4 of this appendix; or
(2) The absolute value of the difference between the average of
the monitor response values and the average of the reference values,
[bond] R-A [bond] in equation A-4 of this appendix, shall be less
than or equal to 0.5
[[Page 12467]]
percent CO2 or O2, whichever is less
restrictive.
(c) For Hg monitors:
(1) The error in linearity for each calibration gas
concentration (low-, mid-, and high-levels) shall not exceed or
deviate from the reference value by more than 10.0 percent as
calculated using equation A-4 of this appendix; or
(2) The absolute value of the difference between the average of
the monitor response values and the average of the reference values,
[bond] R-A [bond] in equation A-4 of this appendix, shall be less
than or equal to 1.0 [mu]g/dscm, whichever is less restrictive.
(3) For the converter check required under Sec.
75.20(c)(1)(vi), the measurement error shall not exceed 5.0 percent
of the span value at any of the three gas levels.
3.3 Relative Accuracy
* * * * *
3.3.8 Relative Accuracy for Hg Monitoring Systems
[For Alternative 1 in Section II.B.3 of Appendix A to
the Preamble]:
(a) The relative accuracy of a Hg concentration monitoring
system or a sorbent trap monitoring system shall not exceed 20.0
percent. Alternatively, for affected units where the average of the
reference method measurements of Hg concentration during the
relative accuracy test audit is less than 5.0 [mu]g/dscm, the test
results are acceptable if the difference between the mean value of
the monitor measurements and the reference method mean value does
not exceed 1.0 [mu]g/dscm, in cases where the relative accuracy
specification of 20.0 percent is not achieved.
[For Alternative 2 in Section II.B.3 of Appendix A to
the Preamble]:
(a) The relative accuracy of a Hg concentration monitoring
system or a sorbent trap monitoring system shall not exceed 20.0
percent. Alternatively, for affected units where the average of the
reference method measurements of Hg concentration during the
relative accuracy test audit is less than 5.0 [mu]g/dscm, the test
results are acceptable if the difference between the mean value of
the monitor measurements and the reference method mean value does
not exceed 1.0 [mu]g/dscm, in cases where the relative accuracy
specification of 20.0 percent is not achieved. For sorbent trap
monitoring systems, these specifications apply both to RATAs and to
RAAs.
(b) The relative accuracy of a Hg-diluent continuous emission
monitoring systems shall not exceed 20.0 percent. Alternatively, for
affected units where the average of the reference method
measurements of Hg emission rate during the relative accuracy test
audit is less than 5.5 lb/10\12\ Btu, the test results are
acceptable if the difference between the mean value of the
continuous emission monitoring system measurements and the reference
method mean value does not exceed 1.1 lb/
10\12\ Btu, in cases where the relative accuracy specification of
20.0 percent is not achieved.
3.4 Bias
* * * * *
3.4.3 Hg Monitoring Systems
Hg concentration monitoring systems, Hg-diluent monitoring
systems, and sorbent trap monitoring systems shall not be biased low
as determined by the test procedure in section 7.6 of this appendix.
* * * * *
Appendix A to Part 75--[Amended]
23. Appendix A to part 75 is further amended by revising the second
sentence in the first paragraph of the introductory text of section 4
and revising the second paragraph of the introductory text of section 4
to read as follows:
4. Data Acquisition and Handling Systems
* * * These systems also shall have the capability of
interpreting and converting the individual output signals from an
SO2 pollutant concentration monitor, a flow monitor, a
CO2 monitor, an O2 monitor, a NOX
pollutant concentration monitor, a NOX-diluent continuous
emission monitoring system, a moisture monitoring system, a Hg
concentration monitoring system, a Hg-diluent monitoring system, and
a sorbent trap monitoring system, to produce a continuous readout of
pollutant emission rates or pollutant mass emissions (as applicable)
in the appropriate units (e.g., lb/hr, lb/mmBtu, lb/10\12\ Btu,
tons/hr).
Data acquisition and handling systems shall also compute and
record monitor calibration error; any bias adjustments to
SO2, NOX, and Hg pollutant concentration data,
flow rate data, Hg emission rate data, or NOX emission
rate data; and all missing data procedure statistics specified in
subpart D of this part.
* * * * *
Appendix A to Part 75--[Amended]
24. Appendix A to part 75 is further amended by adding new section
5.1.9 to read as follows:
5. Calibration Gas
* * * * *
5.1.9 Mercury Standards
For calibration error tests and linearity checks of Hg pollutant
concentration monitors, elemental mercury standards shall be used.
For the converter checks required under Sec. 75.20(c)(1)(vi) and
section 2.6 of appendix B to this part, HgCl2 standards
shall be used.
* * * * *
Appendix A to Part 75--[Amended]
25. Appendix A to part 75 is further amended by:
a. Revising the first sentence of the introductory text to section
6.2 ;
b. Adding new paragraph (g) to section 6.2;
c. Revising the second sentence of section 6.3.1;
d. Revising the fifteenth sentence (by replacing the words
``SO2-diluent'' with the words ``Hg-diluent'') in section
6.4, introductory text;
e. Revising the first sentence of section 6.5;
f. Revising the first sentence of section 6.5(a) and adding a new
third sentence;
g. Revising the second sentence of section 6.5(c);
h. Revising section 6.5(g);
i. Revising section 6.5.1(a);
j. Revising section 6.5.1(b);
k. Adding new paragraph (c) to section 6.5.6;
l. Revising the first sentence and adding two sentences at the end
of section 6.5.7(a); and
m. Revising sections 6.5.7(b) and 6.5.10.
The revisions read as follows:
6. Certification Tests and Procedures
* * * * *
6.2 Linearity Check (General Procedures)
Check the linearity of each SO2, NOX,
CO2, Hg, and O2 monitor while the unit, or
group of units for a common stack, is combusting fuel at conditions
of typical stack temperature and pressure; it is not necessary for
the unit to be generating electricity during this test. * * *
* * * * *
(g) For Hg monitors, follow the guidelines in section 2.2.3 of
this appendix in addition to the applicable procedures in this
section 6.2 when conducting linearity checks using elemental mercury
calibration standards and when performing the converter checks
required under Sec. 75.20(c)(1)(vi) using HgCl2
calibration standards.
6.3 7-Day Calibration Error Test
6.3.1 Gas Monitor 7-day Calibration Error Test
* * * In all other cases, measure the calibration error of each
SO2 monitor, each NOX monitor, each Hg
monitor, and each CO2 or O2 monitor while the
unit is combusting fuel (but not necessarily generating electricity)
once each day for 7 consecutive operating days according to the
following procedures. * * *
* * * * *
6.4 Cycle Time Test
* * * For the NOX-diluent continuous emission
monitoring system test and Hg-diluent continuous emission monitoring
system test, record and report the longer cycle time of the two
component analyzers as the system cycle time. * * *
* * * * *
6.5 Relative Accuracy and Bias Tests (General Procedures)
Perform the required relative accuracy test audits (RATAs) as
follows for each CO2 pollutant concentration monitor
(including O2 monitors used to determine CO2
pollutant concentration), each SO2 pollutant
concentration monitor, each NOX concentration monitoring
system used to determine NOX mass emissions, each flow
monitor, each NOX-diluent continuous emission monitoring
system, each O2 or CO2 diluent monitor used to
calculate heat input,
[[Page 12468]]
each Hg concentration monitoring system, each Hg-diluent monitoring
system, each sorbent trap monitoring system, and each moisture
monitoring system. * * *
(a) Except as otherwise provided in this paragraph or in Sec.
75.21(a)(5), perform each RATA while the unit (or units, if more
than one unit exhausts into the flue) is combusting the fuel that is
a normal primary or backup fuel for that unit (for some units, more
than one type of fuel may be considered normal, e.g., a unit that
combusts gas or oil on a seasonal basis). For units that co-fire
fuels as the predominant mode of operation, perform the RATAs while
co-firing. For Hg monitoring systems, perform the RATAs while the
unit is combusting coal. When relative accuracy test audits are
performed on continuous emission monitoring systems installed on
bypass stacks/ducts, use the fuel normally combusted by the unit (or
units, if more than one unit exhausts into the flue) when emissions
exhaust through the bypass stack/ducts.
* * * * *
(c) * * * For units with add-on SO2 or NOX
controls or add-on Hg controls that operate continuously rather than
seasonally, or for units that need a dual range to record high
concentration ``spikes'' during startup conditions, the low range is
considered normal. * * *
* * * * *
(g) For each SO2 or CO2 pollutant
concentration monitor, each flow monitor, each CO2 or
O2 diluent monitor used to determine heat input, each
NOX concentration monitoring system used to determine
NOX mass emissions, as defined in Sec. 75.71(a)(2), each
moisture monitoring system, each NOX-diluent continuous
emission monitoring system, each Hg concentration monitoring system,
each Hg-diluent monitoring system, and each sorbent trap monitoring
system, calculate the relative accuracy, in accordance with section
7.3 or 7.4 of this appendix, as applicable. In addition (except for
CO2, O2, or moisture monitors), test for bias
and determine the appropriate bias adjustment factor, in accordance
with sections 7.6.4 and 7.6.5 of this appendix, using the data from
the relative accuracy test audits.
6.5.1 Gas and Hg Monitoring System RATAs (Special Considerations)
(a) Perform the required relative accuracy test audits for each
SO2 or CO2 pollutant concentration monitor,
each CO2 or O2 diluent monitor used to
determine heat input, each NOX-diluent continuous
emission monitoring system, each NOX concentration
monitoring system used to determine NOX mass emissions,
as defined in Sec. 75.71(a)(2), each Hg concentration monitoring
system, each Hg-diluent monitoring system, and each sorbent trap
monitoring system at the normal load level or normal operating level
for the unit (or combined units, if common stack), as defined in
section 6.5.2.1 of this appendix. If two load levels or operating
levels have been designated as normal, the RATAs may be done at
either load level.
(b) For the initial certification of a gas or Hg monitoring
system and for recertifications in which, in addition to a RATA, one
or more other tests are required (i.e., a linearity test, cycle time
test, or 7-day calibration error test), EPA recommends that the RATA
not be commenced until the other required tests of the CEMS have
been passed.
* * * * *
6.5.6 Reference Method Traverse Point Selection
* * * * *
(c) For Hg monitoring systems, use the same traverse points that
are used for the gas monitor RATAs.
* * * * *
6.5.7 Sampling Strategy
(a) Conduct the reference method tests so they will yield
results representative of the pollutant concentration, emission
rate, moisture, temperature, and flue gas flow rate from the unit
and can be correlated with the pollutant concentration monitor,
CO2 or O2 monitor, flow monitor, and
SO2, Hg, or NOX continuous emission monitoring
system measurements. * * * For Hg monitoring system RATAs using the
Ontario Hydro method, the minimum acceptable time per run is 2
hours. For the RATA of a sorbent trap monitoring system, install a
new pair of sorbent traps prior to each test run.
(b) To properly correlate individual SO2, Hg, or
NOX continuous emission monitoring system data (in lb/
mmBtu) and volumetric flow rate data with the reference method data,
annotate the beginning and end of each reference method test run
(including the exact time of day) on the individual chart
recorder(s) or other permanent recording device(s).
* * * * *
6.5.10 Reference Methods
The following methods from appendix A to part 60 of this chapter
or their approved alternatives are the reference methods for
performing relative accuracy test audits: Method 1 or 1A for siting;
Method 2 or its allowable alternatives in appendix A to part 60 of
this chapter (except for Methods 2B and 2E) for stack gas velocity
and volumetric flow rate; Methods 3, 3A, or 3B for O2 or
CO2; Method 4 for moisture; Methods 6, 6A, or 6C for
SO2; Methods 7, 7A, 7C, 7D, or 7E for NOX,
excluding the exception in section 5.1.2 of Method 7E; and the
Ontario Hydro method for Hg (see Sec. 75.22). When using Method 7E
for measuring NOX concentration, total NOX,
both NO and NO2, must be measured. Notwithstanding these
requirements, Method 20 may be used as the reference method for
relative accuracy test audits of NOX monitoring systems
installed on combustion turbines.
* * * * *
Appendix A to Part 75--[Amended]
26. Appendix A to part 75 is further amended by:
a. Revising the title of section 7.3 and the first sentence of the
introductory text of section 7.3;
b. Revising the introductory text of section 7.6;
[For Alternative 1 in Section II.B.3 of Appendix A to the
Preamble]:
c. Revising the first sentence in paragraph (b) of section 7.6.5
and adding a sentence at the end of paragraph (b); and
[For Alternative 2 in Section II.B.3 of Appendix A to the
Preamble]:
c. Revising the first sentence in paragraph (b) of section 7.6.5
and adding two new sentences at the end of paragraph (b); and
d. Revising paragraph (f) in section 7.6.5.
The revisions and additions read as follows:
7. Calculations
* * * * *
7.3 Relative Accuracy for SO2 and CO2 Pollutant Concentration
Monitors, O2 Monitors, NOX Concentration Monitoring Systems, Hg
Monitoring Systems, and Flow Monitors
Analyze the relative accuracy test audit data from the reference
method tests for SO2 and CO2 pollutant
concentration monitors, CO2 or O2 monitors
used only for heat input rate determination, NOX
concentration monitoring systems used to determne NOX
mass emissions under subpart H of this part, Hg monitoring systems
used to determine Hg mass emissions under subpart I of this part,
and flow monitors using the following procedures. * * *
* * * * *
7.6 Bias Test and Adjustment Factor
Test the following relative accuracy test audit data sets for
bias: SO2 pollutant concentration monitors; flow
monitors; NOX concentration monitoring systems used to
determine NOX mass emissions, as defined in Sec.
75.71(a)(2); NOX-diluent continuous emission monitoring
systems, Hg concentration monitoring systems, Hg-diluent monitoring
systems, and sorbent trap monitoring systems, using the procedures
outlined in sections 7.6.1 through 7.6.5 of this appendix. For
multiple-load flow RATAs, perform a bias test at each load level
designated as normal under section 6.5.2.1 of this appendix.
* * * * *
7.6.5 Bias Adjustment
* * * * *
[For Alternative 1 in Section II.B.3 of Appendix A to
the Preamble]:
(b) For single-load RATAs of SO2 pollutant
concentration monitors, NOX concentration monitoring
systems, NOX-diluent monitoring systems, Hg concentration
monitoring systems, Hg-diluent monitoring systems, and sorbent trap
monitoring systems, and for the single-load flow RATAs required or
allowed under section 6.5.2 of this appendix and sections 2.3.1.3(b)
and 2.3.1.3(c) of appendix B to this part, the appropriate BAF is
determined directly from the RATA results at normal load, using
Equation A-12. * * * Similarly, for Hg concentration and sorbent
trap monitoring systems, where the average Hg concentration during
the RATA is <5.0 [mu]g/dscm, or, for Hg-diluent monitoring systems,
where the average Hg emission rate
[[Page 12469]]
during the RATA is <5.5 lb/10\12\ Btu, if the monitoring system
meets the normal or the alternative relative accuracy specification
in section 3.3.8 of this appendix but fails the bias test, the owner
or operator may either use the bias adjustment factor (BAF)
calculated from Equation A-12 or may use a default BAF of 1.250 for
reporting purposes under this part.
[For Alternative 2 in Section II.B.3 of Appendix A to
the Preamble]:
(b) For single-load RATAs of SO2 pollutant
concentration monitors, NOX concentration monitoring
systems, NOX-diluent monitoring systems, Hg concentration
monitoring systems, Hg-diluent monitoring systems, and sorbent trap
monitoring systems, and for the single-load flow RATAs required or
allowed under section 6.5.2 of this appendix and sections 2.3.1.3(b)
and 2.3.1.3(c) of appendix B to this part, the appropriate BAF is
determined directly from the RATA results at normal load, using
Equation A-12. * * * Similarly, for Hg concentration and sorbent
trap monitoring systems, where the average Hg concentration during
the RATA is < 5.0 [mu]g/dscm, or, for Hg-diluent monitoring systems,
where the average Hg emission rate during the RATA is <5.5 lb/10\12\
Btu, if the monitoring system meets the normal or the alternative
relative accuracy specification in section 3.3.8 of this appendix
but fails the bias test, the owner or operator may either use the
bias adjustment factor (BAF) calculated from Equation A-12 or may
use a default BAF of 1.250 for reporting purposes under this part.
The provisions of this paragraph (b) also apply to relative accuracy
audits (RAAs) of sorbent trap monitoring systems.
* * * * *
(f) Use the bias-adjusted values in computing substitution
values in the missing data procedure, as specified in subpart D of
this part, and in reporting the concentration of SO2 or
Hg, the flow rate, the average NOX emission rate, the
unit heat input, and the calculated mass emissions of SO2
and CO2 during the quarter and calendar year, as
specified in subpart G of this part. In addition, when using a
NOX concentration monitoring system and a flow monitor to
calculate NOX mass emissions under subpart H of this
part, or when using a Hg concentration or sorbent trap monitoring
system and a flow monitor to calculate Hg mass emissions under
subpart I of this part, use bias-adjusted values for NOX
(or Hg) concentration and flow rate in the mass emission
calculations and use bias-adjusted NOX (or Hg)
concentrations to compute the appropriate substitution values for
NOX (or Hg) concentration in the missing data routines
under subpart D of this part.
* * * * *
27. Appendix B to part 75 is amended by adding sections 1.5 through
1.5.6 to read as follows:
Appendix B to Part 75--Quality Assurance and Quality Control Procedures
* * * * *
1.5 Requirements for Sorbent Trap Monitoring Systems
1.5.1 Sorbent Trap Identification and Tracking
Include procedures for inscribing or otherwise permanently
marking a unique identification number on each sorbent trap, for
tracking purposes. Keep records of the ID of the monitoring system
in which each sorbent trap is used, and the dates and hours of each
Hg collection period.
1.5.2 Monitoring System Integrity and Data Quality
Explain the procedures used to perform the leak checks when a
sorbent trap is placed in service and removed from service. These
procedures must be consistent with Method 324, Determination of
Vapor-Phase Flue Gas Mercury Emissions from Stationary Sources Using
Dry Sorbent Trap Sampling. Also explain the other QA procedures used
to ensure system integrity and data quality, including, but not
limited to, dry gas meter calibrations, verification of moisture
removal, and ensuring air-tight pump operation. In addition, the QA
plan must include the data acceptance and quality control criteria
in section 9.0 of Method 324.
1.5.3 Hg Analysis
Explain the chain of custody employed in transporting and
analyzing the sorbent traps. Keep records of all Hg analyses. The
analyses shall be performed in accordance with Method 324.
1.5.4 Laboratory Certification
The QA Plan shall include documentation that the laboratory
performing the Method 324 analyses on the carbon sorbent traps is
certified by the International Organization for Standardization
(ISO) to have a proficiency that meets the requirements of ISO 9000.
1.5.5 Data Collection Period
State, and provide the rationale for, the minimum acceptable
data collection time for each sorbent trap. Include in the
discussion such factors as the Hg concentration in the stack gas,
the size and capacity of the sorbent traps, and the minimum mass of
Hg required for the Method 324 analysis.
1.5.6 Relative Accuracy Test Audit Procedures
Keep records of the procedures and details peculiar to the
sorbent trap monitoring systems that are to be followed for relative
accuracy test audits, such as sampling and analysis methods.
Appendix B to Part 75--[Amended]
28. Appendix B to part 75 is further amended by:
a. Revising the first sentence in section 2.1.1 introductory text;
b. Revising paragraph (a) of section 2.1.4;
c. Revising the first sentence of section 2.2.1;
d. Revising the first sentence in paragraph (a) of section 2.3.1.1
and adding a new second sentence to paragraph (a);
e. Revising paragraph (a) of section 2.3.1.3;
f. Revising paragraph (i) of section 2.3.2;
g. Revising section 2.3.4;
h. Revising the first sentence in paragraph (b) of section 2.4;
[For Alternative 1 in Section II.B.3 of Appendix A to the
Preamble]:
i. Adding new section 2.6;
[For Alternative 2 in Section II.B.3 of Appendix A to the
Preamble]:
i. Adding new sections 2.6 and 2.7;
j. Revising Figure 1;
k. Revising Figure 2.
The revisions and additions read as follows:
2. Frequency of Testing
* * * * *
2.1.1 Calibration Error Test
Except as provided in section 2.1.1.2 of this appendix, perform
the daily calibration error test of each gas and Hg monitoring
system (including moisture monitoring systems consisting of wet- and
dry-basis O2 analyzers) according to the procedures in
section 6.3.1 of appendix A to this part, and perform the daily
calibration error test of each flow monitoring system according to
the procedure in section 6.3.2 of appendix A to this part. * * *
* * * * *
2.1.4 Data Validation
(a) An out-of-control period occurs when the calibration error
of an SO2 or NOX pollutant concentration
monitor exceeds 5.0 percent of the span value, when the calibration
error of a CO2 or O2 monitor (including
O2 monitors used to measure CO2 emissions or
percent moisture) exceeds 1.0 percent O2 or
CO2, or when the calibration error of a flow monitor or a
moisture sensor exceeds 6.0 percent of the span value, which is
twice the applicable specification of appendix A to this part.
Notwithstanding, a differential pressure-type flow monitor for which
the calibration error exceeds 6.0 percent of the span value shall
not be considered out-of-control if [bond] R-A [bond], the absolute
value of the difference between the monitor response and the
reference value in Equation A-6 of appendix A to this part, is <=
0.02 inches of water. In addition, an SO2 or
NOX monitor for which the calibration error exceeds 5.0
percent of the span value shall not be considered out-of-control if
[bond] R-A [bond] in Equation A-6 does not exceed 5.0 ppm (for span
values <= 50 ppm), or if [bond] R-A [bond] does not exceed 10.0 ppm
(for span values 50 ppm, but <= 200 ppm). For a Hg
monitor, an out-of-control period occurs when the calibration error
exceeds 7.5% of the span value. Notwithstanding, the Hg monitor
shall not be considered out-of-control if R-A in Equation A-6 does
not exceed 1.5 [mu]g/dscm. The out-of-control period begins upon
failure of the calibration error test and ends upon completion of a
successful calibration error test. Note, that if a failed
calibration, corrective action, and successful calibration error
test occur within the same hour, emission data for that hour
recorded by the
[[Page 12470]]
monitor after the successful calibration error test may be used for
reporting purposes, provided that two or more valid readings are
obtained as required by Sec. 75.10. A NOX-diluent
continuous emission monitoring system is considered out-of-control
if the calibration error of either component monitor exceeds twice
the applicable performance specification in appendix A to this part.
A Hg-diluent continuous emission monitoring system is considered
out-of-control if the calibration error of either component monitor
exceeds the appplicable specification in this paragraph. Emission
data shall not be reported from an out-of-control monitor.
* * * * *
2.2.1 Linearity Check
Unless a particular monitor (or monitoring range) is exempted
under this paragraph or under section 6.2 of appendix A to this
part, perform a linearity check, in accordance with the procedures
in section 6.2 of appendix A to this part, for each primary and
redundant backup SO2, Hg, and NOX pollutant
concentration monitor and each primary and redundant backup
CO2 or O2 monitor (including O2
monitors used to measure CO2 emissions or to continuously
monitor moisture) at least once during each QA operating quarter, as
defined in Sec. 72.2 of this chapter.
* * * * *
2.3.1.1 Standard RATA Frequencies
(a) Except for Hg monitoring systems and as otherwise specified
in Sec. 75.21(a)(6) or (a)(7) or in section 2.3.1.2 of this
appendix, perform relative accuracy test audits semiannually, i.e.,
once every two successive QA operating quarters (as defined in Sec.
72.2 of this chapter) for each primary and redundant backup
SO2 pollutant concentration monitor, flow monitor,
CO2 pollutant concentration monitor (including
O2 monitors used to determine CO2 emissions),
CO2 or O2 diluent monitor used to determine
heat input, moisture monitoring system, NOX concentration
monitoring system, or NOX-diluent continuous emission
monitoring system. For each primary and redundant backup Hg
concentration monitoring system, Hg-diluent monitoring system, and
sorbent trap monitoring system, RATAs shall be performed annually,
i.e., once every four successive QA operating quarters (as defined
in Sec. 72.2 of this chapter).
* * * * *
2.3.1.3 RATA Load (or Operating) Levels and Additional RATA
Requirements
(a) For SO2 pollutant concentration monitors,
CO2 pollutant concentration monitors (including
O2 monitors used to determine CO2 emissions),
CO2 or O2 diluent monitors used to determine
heat input, NOX concentration monitoring systems, Hg
concentration monitoring systems, sorbent trap monitoring systems,
moisture monitoring systems, Hg-diluent monitoring systems, and
NOX-diluent monitoring systems, the required semiannual
or annual RATA tests shall be done at the load level (or operating
level) designated as normal under section 6.5.2.1(d) of appendix A
to this part. If two load levels (or operating levels) are
designated as normal, the required RATA(s) may be done at either
load level (or operating level).
* * * * *
2.3.2 Data Validation
* * * * *
(i) Each time that a hands-off RATA of an SO2
pollutant concentration monitor, a NOX-diluent monitoring
system, a NOX concentration monitoring system, a Hg
concentration monitoring system, a Hg-diluent monitoring system, a
sorbent trap monitoring system, or a flow monitor is passed, perform
a bias test in accordance with section 7.6.4 of appendix A to this
part. Apply the appropriate bias adjustment factor to the reported
SO2, Hg, NOX, or flow rate data, in accordance
with section 7.6.5 of appendix A to this part.
* * * * *
2.3.4 Bias Adjustment Factor
Except as otherwise specified in section 7.6.5 of appendix A to
this part, if an SO2 pollutant concentration monitor,
flow monitor, NOX continuous emission monitoring system,
NOX concentration monitoring system used to calculate
NOX mass emissions, Hg concentration monitoring system,
Hg-diluent monitoring system, or sorbent trap monitoring system
fails the bias test specified in section 7.6 of appendix A to this
part, use the bias adjustment factor given in Equations A-11 and A-
12 of appendix A to this part, or the allowable alternative BAF
specified in section 7.6.5(b) of appendix A to this part, to adjust
the monitored data.
2.4 Recertification, Quality Assurance, RATA Frequency and Bias
Adjustment Factors (Special Considerations)
* * * * *
(b) Except as provided in section 2.3.3 of this appendix,
whenever a passing RATA of a gas monitor or Hg monitoring system is
performed, or a passing 2-load (or 2-level) RATA or a passing 3-load
(or 3-level) RATA of a flow monitor is performed (irrespective of
whether the RATA is done to satisfy a recertification requirement or
to meet the quality assurance requirements of this appendix, or
both), the RATA frequency (semi-annual or annual) shall be
established based upon the date and time of completion of the RATA
and the relative accuracy percentage obtained.
* * * * *
[For Alternatives 1 and 2 in Section II.B.3
of Appendix A to the Preamble]:
2.6 Converter Check for Hg Monitors
For each Hg pollutant concentration monitor, perform the
converter check described in Sec. 75.20(c)(1)(vi) once in every
month in which there are at least 168 unit or stack operating hours.
[For Alternative 2 in Section II.B.3 of Appendix A to
the Preamble]:
2.7 Relative Accuracy Audits (RAAs) of Sorbent Trap Monitoring
Systems
For affected units with average Hg emissions 9 lbs/
yr for the 3 calendar years used to allocate the Hg allowances, if
the owner or operator elects to use sorbent trap monitoring systems
to quantify Hg emissions, a 3-run relative accuracy audit (RAA) of
each sorbent trap monitoring system shall be performed in each QA
operating quarter (as defined in Sec. 72.2 of this chapter)
following initial certification, except for a quarter in which a
full RATA is performed. The load level and data validation
provisions of sections 2.3.1.3 and 2.3.2 of this appendix apply to
the RAAs.
[For Alternative 1 in Section II.B.3 of Appendix A to the
Preamble]:
Figure 1 to Appendix B of Part 75.--Quality Assurance Test Requirements
----------------------------------------------------------------------------------------------------------------
QA test frequency requirements
Test ------------------------------------------------------------------------
Daily Monthly Quarterly Semiannual * Annual
----------------------------------------------------------------------------------------------------------------
Calibration Error (2 pt.).............. [bcheck] ............ ............ ............... ............
Interference Check (flow).............. [bcheck] ............ ............ ............... ............
Flow-to-Load Ratio..................... ............ ............ [bcheck] ............... ............
Leak Check (DP flow monitors).......... ............ ............ [bcheck] ............... ............
Linearity Check (3 pt.)................ ............ ............ [bcheck] ............... ............
Converter Check (Hg monitors).......... ............ [bcheck] ............ ............... ............
RATA (SO2, NOX, CO2, O2, H2O) \1\...... ............ ............ ............ [bcheck] ............
RATA (all Hg monitoring systems)....... ............ ............ ............ ............... [bcheck]
RATA (flow) 1,2........................ ............ ............ ............ [bcheck] ............
----------------------------------------------------------------------------------------------------------------
* For monitors on bypass stack/duct, ``daily'' means bypass operating days, only. ``Quarterly'' means once every
QA operating quarter. ``Semiannual'' means once every two QA operating quarters. ``Annual'' means once every
four QA operating quarters.
[[Page 12471]]
* * * * *
Figure 2 to Appendix B of Part 75.--Relative Accuracy Test Frequency
Incentive System
------------------------------------------------------------------------
Semiannual w
RATA (percent) Annual w
------------------------------------------------------------------------
SO2 or NOX y................ 7.5% < RA <= 10.0% RA <= 7.5% or
thn-eq> 15.0 ppm x. 12.0 ppm x
NOX -diluent................ 7.5% < RA <= 10.0% RA <= 7.5% or
thn-eq> 0.020. 0.015
Hg-diluent.................. .................... RA <= 20.0% or
1.1 lb/10 12
Flow........................ 7.5% < RA <= 10.0% RA <= 7.5%
or 1.5 fps x.
CO2 or O2................... 7.5% < RA <= 10.0% RA <= 7.5% or
thn-eq> 1.0% CO2/O2 0.7% CO2/O2 x
x.
Hg.......................... .................... RA <= 20.0% or
1.0 [mu]g/dscm x
Moisture.................... 7.5% < RA <= 10.0% RA <= 7.5% or
thn-eq> 1.5% H2O x. 1.0% H2O X
------------------------------------------------------------------------
w The deadline for the next RATA is the end of the second (if
semiannual) or fourth (if annual) successive QA operating quarter
following the quarter in which the CEMS was last tested. Exclude
calendar quarters with fewer than 168 unit operating hours (or, for
common stacks and bypass stacks, exclude quarters with fewer than 168
stack operating hours) in determining the RATA deadline. For SO2
monitors, QA operating quarters in which only very low sulfur fuel as
defined in Sec. 72.2, is combusted may also be excluded. However,
the exclusion of calendar quarters is limited as follows: the deadline
for the next RATA shall be no more than 8 calendar quarters after the
quarter in which a RATA was last performed.
x The difference between monitor and reference method mean values
applies to moisture monitors, CO2, and O2 monitors, low emitters of
SO2, NOX, or Hg, and low flow, only.
y A NOX concentration monitoring system used to determine NOX mass
emissions under Sec. 75.71.
z Including sorbent trap monitoring systems.
* * * * *
[For Alternative 2 in Section II.B.3 of Appendix A to the
Preamble]:
Figure 1 to Appendix B of Part 75.--Quality Assurance Test Requirements
----------------------------------------------------------------------------------------------------------------
QA test frequency requirements
Test ------------------------------------------------------------------------
Daily Monthly Quarterly Semiannual * Annual
----------------------------------------------------------------------------------------------------------------
Calibration Error (2 pt.).............. [bcheck] ............ ............ ............... ............
Interference Check (flow).............. [bcheck] ............ ............ ............... ............
Flow-to-Load Ratio..................... ............ ............ [bcheck] ............... ............
Leak Check (DP flow monitors).......... ............ ............ [bcheck] ............... ............
Linearity Check (3 pt.)................ ............ ............ [bcheck] ............... ............
Converter Check (Hg monitors).......... ............ [bcheck] ............ ............... ............
RATA (SO2, NOX, CO2, O2, H2O)\1\....... ............ ............ ............ [bcheck] ............
RATA (all Hg monitoring systems)....... ............ ............ ............ ............... [bcheck]
RATA (flow) 1 2........................ ............ ............ ............ [bcheck] ............
RAA (sorbent trap systems; Hg)......... ............ ............ [bcheck] ............... ............
----------------------------------------------------------------------------------------------------------------
* For monitors on bypass stack/duct, ``daily'' means bypass operating days, only. ``Quarterly'' means once every
QA operating quarter. ``Semiannual'' means once every two QA operating quarters. ``Annual'' means once every
four QA operating quarters. For sorbent trap monitoring systems, the RAA is not required in a quarter in which
a full RATA is performed.
* * * * *
Figure 2 to Appendix B of Part 75.--Relative Accuracy Test Frequency
Incentive System
------------------------------------------------------------------------
Semiannual w
RATA (percent) Annual w
------------------------------------------------------------------------
SO2 or NOX y................ 7.5% < RA <= 10.0% RA <= 7.5% or
thn-eq> 15.0 ppm x. 12.0 ppm x
NOX-diluent................. 7.5% < RA <= 10.0% RA <= 7.5% or
thn-eq> 0.020. 0.015
Hg-diluent.................. .................... RA <= 20.0% or
1.1 lb/10 12
Flow........................ 7.5% < RA <= 10.0% RA <= 7.5%
or 1.5 fps x.
CO2 or O2................... 7.5% < RA <= 10.0% RA <= 7.5% or
thn-eq> 1.0% CO2/O2 0.7% CO2/O2 x
x.
Hg.......................... .................... RA <= 20.0% or
1.0 [mu]g/dscm x
Moisture.................... 7.5% < RA <= 10.0% RA <= 7.5% or
thn-eq> 1.5% H2O x. 1.0% H2O x
------------------------------------------------------------------------
w The deadline for the next RATA is the end of the second (if
semiannual) or fourth (if annual) successive QA operating quarter
following the quarter in which the CEMS was last tested. Exclude
calendar quarters with fewer than 168 unit operating hours (or, for
common stacks and bypass stacks, exclude quarters with fewer than 168
stack operating hours) in determining the RATA deadline. For SO2
monitors, QA operating quarters in which only very low sulfur fuel as
defined in Sec. 72.2, is combusted may also be excluded. However,
the exclusion of calendar quarters is limited as follows: the deadline
for the next RATA shall be no more than 8 calendar quarters after the
quarter in which a RATA was last performed.
x The difference between monitor and reference method mean values
applies to moisture monitors, CO2, and O2 monitors, low emitters of
SO2, NOX, or Hg, and low flow, only.
y A NOX concentration monitoring system used to determine NOX mass
emissions under Sec. 75.71.
z Including sorbent trap monitoring systems. Note that the RA
specifications for Hg concentration also apply to the quarterly RAA
tests of sorbent trap monitoring systems.
[[Page 12472]]
* * * * *
29. Appendix F to part 75 is amended by adding section 9 to read as
follows:
Appendix F to Part 75--Conversion Procedures
* * * * *
9. Procedures for Hg Mass Emissions
9.1 Use the procedures in this section to calculate the hourly
Hg mass emissions (in ounces) at each monitored location, for the
affected unit or group of units that discharge through a common
stack.
9.1.1 To determine the hourly Hg mass emissions when using a Hg
concentration monitoring system or a sorbent trap monitoring system
and a flow monitor, use the following equation:
[GRAPHIC] [TIFF OMITTED] TP10MR04.000
Where:
M(Hg)h = Hg mass emissions for the hour, rounded off to
one decimal place (ounces).
K = 9.98 x 10-10 (ounces/dscf / [mu]g/dscm).
C(Hg)h = Hourly Hg concentration, adjusted for bias,
where the bias-test procedures in appendix A to this part shows a
bias-adjustment factor is necessary ([mu]g/dscm). For sorbent trap
systems, the value of C(Hg)h will be the same for each
hour in the data collection period. For each pair of sorbent traps,
report the higher of the two measured Hg concentrations.
Qh = Hourly stack gas volumetric flow rate, adjusted for
bias, where the bias-test procedures in appendix A to this part
shows a bias-adjustment factor is necessary (scfh).
Bws = Moisture fraction of the stack gas, expressed as a
decimal (equal to percent H2O / 100).
th = Unit or stack operating time, as defined in Sec.
72.2 (hr).
9.1.2 If a Hg-diluent monitoring system is used to determine the
Hg mass emissions, first calculate the hourly Hg emission rate, in
units of lb/10 12 Btu, as follows:
(a) If the diluent gas (O2 or CO2) is
analyzed on a dry basis, use Equation F-5 or F-6 in this appendix,
with the following modifications. The value of ``K'' in these
equations shall be 6.24 x 10-5 (lb [middot] dscm [middot]
mmBtu / g [middot] dscf [middot] 10 12 Btu), and the term
``Ch'' shall be replaced by ``C(Hg)h'', the
hourly average Hg concentration measured by the Hg monitor, in units
of [mu]g/dscm.(b) When the diluent gas is analyzed on a wet basis,
the following equations in Method 19 in appendix A-7 to part 60 of
this chapter shall be used, with appropriate modification: Equation
19-5 (if O2 is the diluent gas) and Equation 19-9 (if
CO2 is the diluent gas). When using these equations,
replace the term ``Cd'' with the expression ``K
C(Hg)h'', where ``K'' is 6.24 x 10-5 (lb
[middot] dscm [middot] mmBtu/g [middot] dscf [middot] 10
12 Btu), ``C(Hg)h'' is the hourly average Hg
concentration measured by the Hg monitor, in units of [mu]g/dscm.
(c) Round off the calculated Hg emission rate to three decimal
places.
9.1.3 Using the Hg emission rate from section 9.1.2 of this
appendix, calculate the hourly Hg mass emissions using the following
equation:
[GRAPHIC] [TIFF OMITTED] TP10MR04.001
Where:
M(Hg)h = Hg mass emissions for the hour, rounded off to
one decimal place (ounces).
E(Hg)h = Hourly average Hg emission rate for the hour,
from section 9.1.2 of this appendix, adjusted for bias, where the
bias-test procedures in appendix A to this part shows a bias-
adjustment factor is necessary (lb/10 12 Btu).
HIh = Average heat input rate for the hour (mmBtu/hr).
Include bias-adjusted flow rate values, where the bias test
procedures in appendix A to this part shows a bias-adjustment factor
is necessary.
th = Unit or stack operating time, as defined in Sec.
72.2 (hr).
16 = Conversion factor between pounds and ounces.
10 6 = Conversion factor between million (106)
Btu and trillion (1012) Btu.
9.2 Use the following equation to calculate quarterly and year-
to-date Hg mass emissions in ounces:
[GRAPHIC] [TIFF OMITTED] TP10MR04.002
Where:
M(Hg)time period = Hg mass emissions for the given time
period i.e., quarter or year-to-date, rounded to the nearest tenth
(ounces).
M(Hg)h = Hg mass emissions for the hour, rounded to one
decimal place (ounces).
p = The number of hours in the given time period (quarter or year-
to-date).
9.3 If heat input rate monitoring is required, follow the
applicable procedures for heat input apportionment and summation
sections 5.3, 5.6 and 5.7 of this appendix.
[FR Doc. 04-4457 Filed 3-15-04; 8:45 am]
BILLING CODE 6560-50-P