[Federal Register Volume 70, Number 95 (Wednesday, May 18, 2005)]
[Rules and Regulations]
[Pages 28606-28700]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 05-8447]
[[Page 28605]]
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Part II
Environmental Protection Agency
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40 CFR Parts 60, 72, and 75
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Standards of Performance for New and Existing Stationary Sources:
Electric Utility Steam Generating Units; Final Rule
Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules
and Regulations
[[Page 28606]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 60, 72, and 75
[OAR-2002-0056; FRL-7888-1]
RIN 2060-AJ65
Standards of Performance for New and Existing Stationary Sources:
Electric Utility Steam Generating Units
AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule.
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SUMMARY: In this document, EPA is finalizing the Clean Air Mercury Rule
(CAMR) and establishing standards of performance for mercury (Hg) for
new and existing coal-fired electric utility steam generating units
(Utility Units), as defined in Clean Air Act (CAA) section 111. The
amendments to CAA section 111 rules would establish a mechanism by
which Hg emissions from new and existing coal-fired Utility Units are
capped at specified, nation-wide levels. A first phase cap of 38 tons
per year (tpy) becomes effective in 2010, and a second phase cap of 15
tpy becomes effective in 2018. Facilities must demonstrate compliance
with the standard by holding one ``allowance'' for each ounce of Hg
emitted in any given year. Allowances are readily transferrable among
all regulated facilities. 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.
The added benefit of the cap-and-trade approach is that it
dovetails well with the sulfur dioxide (SO2) and nitrogen
oxides (NOX) emission caps under the final Clean Air
Interstate Rule (CAIR) that was signed on March 10, 2005. CAIR
establishes a broadly-applicable cap-and-trade program that
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, especially
reductions of oxidized Hg, can and will be achieved by the air
pollution controls designed and installed to reduce SO2 and
NOX. 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.
The final rule also finalizes a performance specification (PS)
(Performance Specification 12A, ``Specification and Test Methods for
Total Vapor Phase Mercury Continuous Emission Monitoring Systems in
Stationary Sources'') and a test method (``Quality Assurance and
Operating Procedures for Sorbent Trap Monitoring Systems'').
The EPA is also taking final action to amend the definition of
``designated pollutant.'' The existing definition predates the Clean
Air Act Amendments of 1990 (the CAAA) and, as a result, refers to
section 112(b)(1)(A) which no longer exists. The EPA is also amending
the definition of ``designated pollutant'' so that it conforms to EPA's
interpretation of the provisions of CAA section 111(d)(1)(A), as
amended by the CAAA. That interpretation is explained in detail in a
separate Federal Register notice (70 FR 15994; March 29, 2005)
announcing EPA's revision of its December 2000 regulatory determination
and removing Utility Units from the 112(c) list of categories. For
these reasons, EPA has determined that it is appropriate to promulgate
the revised definition of ``designated pollutant'' without prior notice
and opportunity for comment.
DATES: The final rule is effective on July 18, 2005. The Incorporation
by Reference of certain publications listed in the final rule are
approved by the Director of the Office of the Federal Register as of
July 18, 2005.
ADDRESSES: Docket. EPA has established a docket for this action under
Docket ID No. OAR-2002-0056 and legacy Docket ID No. A-92-55. All
documents in the legacy docket are listed in the legacy docket index
available through the Air and Radiation Docket; all documents in the
EDOCKET are listed in the EDOCKET index at http://www.epa.gov/edocket.
Although listed in the indices, some information is not publicly
available, i.e., CBI or other information whose disclosure is
restricted by statute. Certain other material, such as copyrighted
material, is not placed on the EDOCKET Internet site and will be
publicly available only in hard-copy form. Publicly available docket
materials are available either electronically in EDOCKET or in hard
copy at the Air and Radiation Docket, EPA/DC, EPA West, Room B102, 1301
Constitution Ave., NW., Washington, DC. The 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 Public Reading Room is (202)
566-1744, and the telephone number for the Air and Radiation Docket is
(202) 566-1742.
FOR FURTHER INFORMATION CONTACT: For information concerning analyses
performed in developing the final rule, contact Mr. William Maxwell,
Combustion Group, Emission Standards Division (C439-01), EPA, Research
Triangle Park, North Carolina, 27711; telephone number (919) 541-5430;
fax number (919) 541-5450; electronic mail address:
[email protected].
SUPPLEMENTARY INFORMATION: Regulated Entities. Categories and entities
potentially regulated by the final rule include the following:
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NAICS code Examples of potentially
Category \1\ regulated entities
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Industry......................... 221112 Fossil fuel-fired
electric utility steam
generating units.
Federal government............... \2\ 221122 Fossil fuel-fired
electric utility steam
generating units owned
by the Federal
government.
State/local/Tribal government.... \2\ 221122 Fossil fuel-fired
921150 electric utility steam
generating units owned
by municipalities.
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 the
final rule. This table lists examples of the types of entities EPA is
now aware could potentially be regulated by the final rule. Other types
of entities not listed could also be affected. To determine whether
your facility, company, business, organization, etc., is regulated by
the final rule, you should examine the applicability criteria in 40 CFR
60.45a of the final new source performance standards (NSPS) amendments.
If you have questions regarding the applicability of the final rule to
a particular entity, consult your State or
[[Page 28607]]
local agency (or EPA Regional Office) described in the preceding FOR
FURTHER INFORMATION CONTACT section.
Worldwide Web (WWW). In addition to being available in the docket,
an electronic copy of today's document will also be available on the
WWW through EPA's Technology Transfer Network (TTN). Following
signature by the Acting Administrator, a copy of the final rule will be
posted on the TTN's policy and guidance page for newly proposed or
promulgated rules at http://www.epa.gov/ttn/oarpg. The TTN provides
information and technology exchange in various areas of air pollution
control.
Judicial Review. Under CAA section 307(b), judicial review of the
final NSPS is available only by filing a petition for review in the
U.S. Court of Appeals for the District of Columbia Circuit on or before
July 18, 2005. Under CAA section 307(D)(7)(B), only those objections to
the final rule which were raised with reasonable specificity during the
period for public comment may be raised during judicial review.
Moreover, under CAA section 307(b)(2), the requirements established by
the final rule may not be challenged separately in any civil or
criminal proceedings brought by EPA to enforce these requirements.
Outline. The information presented in this preamble is organized as
follows:
I. Background
A. What is the source of authority for development of the final
rule?
B. What is the regulatory background for the final rule?
C. What is the relationship between the final rule and the
section 112 delisting action?
D. What is the relationship between the final rule and other
combustion rules?
II. Revision of Regulatory Finding on the Emissions of Hazardous Air
Pollutants from Utility Units
III. Summary of the Final Rule Amendments
A. Who is subject to the final rule?
B. What are the primary sources of emissions, and what are the
emissions?
C. What is the affected source?
D. What are the emission limitations and work practice
standards?
E. What are the performance testing, initial compliance, and
continuous compliance requirements?
F. What are the notification, recordkeeping, and reporting
requirements?
IV. Significant Comments and Changes Since Proposal
A. Why is EPA not taking final action to regulate Ni emissions
from oil-fired units?
B. How did EPA select the regulatory approach for coal-fired
units for the final rule?
C. How did EPA determine the NSPS under CAA section 111(b) for
the final rule?
D. How did EPA determine the Hg cap-and-trade program under CAA
section 111(d) for the final rule?
E. CAMR Model Cap-and-trade Program
F. Standard of Performance Requirements
G. What are the performance testing and other compliance
provisions?
V. Summary of the Environmental, Energy, Cost, and Economic Impacts
A. What are the air quality impacts?
B. What are the non-air health, environmental, and energy
impacts?
C. What are the cost and economic impacts?
VI. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review
B. Paperwork Reduction Act
C. Regulatory Flexibility Act
D. Unfunded Mandates Reform Act
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation and Coordination with
Indian Tribal Governments
G. Executive Order 13045: Protection of Children from
Environmental Health and Safety Risks
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
I. National Technology Transfer and Advancement Act
J. Executive Order 12898: Federal Actions to Address
Environmental Justice in Minority Populations and Low-Income
Populations
K. Congressional Review Act
I. Background
A. What is the source of authority for development of the final rule?
CAA section 111 creates a program for the establishment of
``standards of performance.'' A ``standard of performance'' is ``a
standard for emissions of air pollutants which reflects the degree of
emission limitation achievable through the application of the best
system of emission reduction, which (taking into account the cost of
achieving such reduction, any non-air quality health and environmental
impacts and energy requirements), the Administrator determines has been
adequately demonstrated.'' (See CAA section 111(a)(1).)
For new sources, EPA must first establish a list of stationary
source categories, which, the Administrator has determined ``causes, or
contributes significantly to, air pollution which may reasonably be
anticipated to endanger public health or welfare.'' (See CAA section
110(b)(1)(A).) EPA must then set Federal standards of performance for
new sources within each listed source category. (See CAA section
111(b)(1)(B).) Like section 112(d) standards, the standards for new
sources under section 111(b) apply nationally and are effective upon
promulgation. (See CAA section 111(b)(1)(B).)
Existing sources are addressed under CAA section 111(d). EPA can
issue standards of performance for existing sources in a source
category only if it has established standards of performance for new
sources in that same category under section 111(b), and only for
certain pollutants. (See CAA section 111(d)(1).) Section 111(d)
authorizes EPA to promulgate standards of performance that States must
adopt through a State Implementation Plans (SIP)-like process, which
requires State rulemaking action followed by review and approval of
State plans by EPA. If a State fails to submit a satisfactory plan, EPA
has the authority to prescribe a plan for the State. (See CAA section
111(d)(2)(A).) Below in this document, we discuss in more detail (i)
the applicable standards of performance for the regulatory
requirements, (ii) the legal authority under CAA section 111(d) to
regulate Hg from coal-fired Utility Units, and (iii) the legal
authority to implement a cap-and-trade program for existing Utility
Units.
B. What is the regulatory background for the final rule?
1. What are the relevant Federal Register actions?
On December 20, 2000, EPA issued a finding pursuant to CAA section
112(n)(1)(A) that it was appropriate and necessary to regulate coal-
and oil-fired Utility Units under section 112. In making this finding,
EPA considered the Utility Study, which was completed and submitted to
Congress in February 1998.
In December 2000, EPA concluded that the positive appropriate and
necessary determination under section 112(n)(1)(A) constituted a
decision to list coal- and oil-fired Utility Units on the section
112(c) source category list. Relying on CAA section 112(e)(4), EPA
explained in its December 2000 finding that neither the appropriate and
necessary finding under section 112(n)(1)(A), nor the associated
listing were subject to judicial review at that time. EPA did not add
natural-gas fired units to the section 112(c) list in December 2000
because it did not make a positive appropriate and necessary finding
for such units.
On January 30, 2004, EPA published in the Federal Register a notice
of proposed rulemaking (NPR) entitled ``Proposed National Emissions
Standards for Hazardous Air Pollutants; and, in the Alternative,
Proposed Standards of Performance for New and Existing Stationary
Sources: Electric Utility Steam Generating Units.'' In that
[[Page 28608]]
rule, EPA proposed three alternative regulatory approaches. First, EPA
proposed to retain the December 2000 Finding and associated listing of
coal- and oil-fired Utility Units and to issue maximum achievable
control technology-based (MACT) national emission standards for
hazardous air pollutants (NESHAP) for such units. Second, EPA
alternatively proposed revising the Agency's December 2000 Finding,
removing coal- and oil-fired Utility Units from the section 112(c)
list,\1\ and issuing final standards of performance under CAA section
111 for new and existing coal-fired units that emit Hg and new and
existing oil-fired units that emit nickel (Ni). Finally, as a third
alternative, EPA proposed retaining the December 2000 finding and
regulating Hg emissions from Utility Units under CAA section
112(n)(1)(A).
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\1\ We did not propose revising the December 2000 finding for
gas-fired Utility Units because EPA continues to believe that
regualtion of such units under section 112 is not appropriate and
necessary. We therefore take no action today with regard to gas-
fired Utility Units.
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Shortly thereafter, on March 16, 2004, EPA published in the Federal
Register a supplemental notice of proposed rulemaking (SNPR) entitled
``Supplemental Notice of 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.'' In that notice, EPA proposed certain
additional regulatory text, which largely governed the proposed section
111 standards of performance for Hg, which included a cap-and-trade
program. The supplemental notice also proposed State plan approvability
criteria and a model cap-and-trade rule for Hg emissions from coal-
fired Utility Units. The Agency received thousands of comments on the
proposed rule and supplemental notice. Some of the more significant
comments relating to today's action are addressed in this preamble. We
respond to the other significant comments in the response to comments
document entitled Response to ``Significant Public Comments on the
Proposed Clean Air Mercury Rule,'' which is in the docket.
On December 1, 2004, EPA published in the Federal Register a notice
of data availability (NODA) entitled ``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: Notice of Data
Availability.'' EPA issued this notice: (1) To seek additional input on
certain new data and information concerning Hg that the Agency received
in response to the January 30, 2004 NPR and March 16, 2004 SNPR; and
(2) to seek input on a revised proposed benefits methodology for
assessing the benefits of Hg regulation. EPA conducts benefits analysis
for rulemakings consistent with the provisions of Executive Order (EO)
12866.
2. How did the public participate in developing the final rule?
Upon signature on December 15, 2003, the proposed rule was posted
on the Agency's Internet Web site for public review. Following
publication of the NPR in the Federal Register (69 FR 4652; January 30,
2004), a 60-day public comment period ensued. Concurrent public
hearings were held in Research Triangle Park, NC, Philadelphia, PA, and
Chicago, IL, on February 25 and 26, 2004, at which time any member of
the public could provide oral comment on the NPR. On March 16, 2004, a
SNPR was published in the Federal Register (69 FR 12398). On March 17,
2004, EPA announced that the public comment period on the NPR and SNPR
had been extended to April 30, 2004. A public hearing on the SNPR was
held in Denver, CO, on March 31, 2004, during which time members of the
public could provide oral comment on any aspect of the NPR or SNPR. On
May 5, 2004, EPA announced (69 FR 25052) that the public comment period
for the NPR and SNPR had been reopened and extended until June 29,
2004. On December 1, 2004, EPA published a NODA with a public comment
period until January 3, 2005 (69 FR 69864). In addition to the public
comment process, EPA met with a number of stakeholder groups and has
placed in the docket records of these meetings. Comments received after
the close of the public comment period on the NODA (January 3, 2005),
were not considered in the analyses. Approximately 500,000 public
comments were received during this period, indicating wide public
interest and access.
C. What is the relationship between the final rule and the section 112
delisting action?
In a separate Federal Register notice (70 FR 15994; March 29,
2005), EPA published a final Agency action which delists Utility Units
under section 112(n)(1)(A). In that action, EPA revised the regulatory
finding that it issued in December 2000 pursuant to CAA section
112(n)(1)(A), and based on that revision, removed coal- and oil-fired
electric utility steam generating units (coal- and oil-fired Utility
Units) from the CAA section 112(c) list. Section 112(n)(1)(A) of the
CAA is the threshold statutory provision underlying this action.
Congress enacted this special provision for Utility Units which gives
EPA considerable discretion in determining whether Utility Units should
be regulated under section 112. The provision requires EPA to conduct a
study to examine the hazards to public health that are reasonably
anticipated to occur as the result of hazardous air pollutant (HAP)
emissions from Utility Units after imposition of the requirements of
the CAA. The provision also provides that EPA shall regulate Utility
Units under section 112, but only if the Administrator determines that
such regulation is both ``appropriate'' and ``necessary'' considering,
among other things, the results of the study. EPA completed the study
in 1998 (Utility Study), and in December 2000 found that it was
``appropriate and necessary'' to regulate coal- and oil-fired Utility
Units under CAA section 112. That December 2000 finding focused
primarily on Hg emissions from coal-fired Utility Units. In January
2004, EPA proposed revising the December 2000 appropriate and necessary
finding and, based on that revision, removing coal- and oil-fired
Utility Units from the section 112(c) list.
In a separate Federal Register notice (70 FR 15994; March 29,
2005), we revised the December 2000 appropriate and necessary finding
and concluding that it is not appropriate and necessary to regulate
coal- and oil-fired Utility Units under section 112. We took this
action because we now believe that the December 2000 finding lacked
foundation and because recent information demonstrates that it is not
appropriate or necessary to regulate coal- and oil-fired Utility Units
under section 112. Based solely on the revised finding, we are removing
coal- and oil-fired Utility Units from the section 112(c) list and
instead establishing standards of performance for Hg for new and
existing coal-fired Utility Units, as defined in CAA section 111.
The reasons supporting today's action are described in detail in a
separate final Agency action published in the Federal Register (70 FR
15994; March 29, 2005).
D. What is the relationship between the final rule and other combustion
rules?
Revised NSPS for SO2, NOX, and particulate
matter (PM) were proposed under CAA section 111 for Utility Units (40
CFR part 60, subpart Da) and industrial boilers (IB) (40 CFR part 60,
subpart Db) on February 28, 2005 (70 FR
[[Page 28609]]
9706). EPA earlier promulgated NSPS for Utility Units (1979) and for IB
(1987). In addition, the EPA promulgated another combustion-related
standard under CAA section 112: Industrial, commercial, and
institutional boilers and process heaters (40 CFR part 63, subpart
DDDDD) on September 13, 2004 (69 FR 55218).
All of the rules pertain to sources that combust fossil fuels for
electrical power, process operations, or heating. The applicability of
these rules differ with respect to the size of the unit (megawatts
electric (MWe) or British thermal unit per hour (Btu/hr)) they
regulate, the boiler/furnace technology they employ, or the portion of
their electrical output (if any) for sale to any utility power
distribution systems.
Any combustion unit that produces steam to serve a generator that
produces electricity exclusively for industrial, commercial, or
institutional purposes is considered an IB unit. A fossil fuel-fired
combustion unit that serves a generator that produces electricity for
sale is not considered to be a Utility Unit under the final rule if its
size is less than or equal to 25 MWe. Also, a cogeneration facility
that sells electricity to any utility power distribution system equal
to more than one-third of their potential electric output capacity and
more than 25 MWe during any portion of a year is considered to be an
electric utility steam generating unit.
Because of the similarities in the design and operational
characteristics of the units that would be regulated by the different
combustion rules, there are situations where coal-fired units
potentially could be subject to multiple rules. An example of this
situation would be cogeneration units that are covered under the
proposed IB rule, potentially meeting the definition of a Utility Unit,
and vice versa. This might occur where a decision is made to increase/
decrease the proportion of production output being supplied to the
electric utility grid, thus causing the unit to exceed the IB/electric
utility cogeneration criteria (i.e. greater than one-third of its
potential output capacity and greater than 25 MWe). As discussed below,
EPA has clarified the definitions and applicability provisions to
lessen any confusion as to which rule a unit may be subject to.
II. Revision of Regulatory Finding on the Emissions of Hazardous Air
Pollutants from Utility Units
In a separately published Federal Register action (70 FR 15994;
March 29, 2005), EPA revised the regulatory finding that it issued in
December 2000 pursuant to CAA section 112(n)(1)(A), and based on that
revision, removed coal- and oil-fired electric utility steam generating
units (coal- and oil-fired Utility Units) from the CAA section 112(c)
source category list. Section 112(n)(1)(A) of the CAA is the threshold
statutory provision underlying the action. That provision requires EPA
to conduct a study to examine the hazards to public health that are
reasonably anticipated to occur as the result of HAP emissions from
Utility Units after imposition of the requirements of the CAA. The
provision also provides that EPA shall regulate Utility Units under CAA
section 112, but only if the Administrator determines that such
regulation is both appropriate and necessary considering, among other
things, the results of the study. EPA completed the Utility Study in
1998, and in December 2000 found that it was appropriate and necessary
to regulate coal- and oil-fired Utility Units under CAA section 112.
That December 2000 finding focused primarily on Hg emissions from coal-
fired Utility Units. In light of the finding, EPA in December 2000
announced its decision to list coal- and oil-fired Utility Units on the
CAA section 112(c) list of regulated source categories. In January
2004, EPA proposed revising the December 2000 appropriate and necessary
finding and, based on that revision, removing coal- and oil-fired
Utility Units from the CAA section 112(c) list.
By a separately published Federal Register action (70 FR 15994;
March 29, 2005), we revised the December 2000 appropriate and necessary
finding and concluded that it is neither appropriate nor necessary to
regulate coal- and oil-fired Utility Units under CAA section 112. We
took this action because we now believe that the December 2000 finding
lacked foundation and because recent information demonstrates that it
is not appropriate or necessary to regulate coal- and oil-fired Utility
Units under CAA section 112. Based solely on the revised finding, we
are removing coal- and oil-fired Utility Units from the CAA section
112(c) list. The reasons supporting today's action are described in
detail in the separately published Federal Register notice (70 FR
15994; March 29, 2005).
EPA revised its December 2000 determination and removed coal- and
oil-fired Utility Units from the CAA section 112(c) source category
list because we have concluded that utility HAP emissions remaining
after implementation of other requirements of the CAA, including in
particular the CAIR, do not cause hazards to public health that would
warrant regulation under CAA section 112.
The HAP of greatest concern from coal-fired utilities is Hg.
Although we believe that after implementation of CAIR, remaining
utility emissions will not pose hazards to public health, we do believe
that it is appropriate to establish national, uniform Hg emission
standards for new and modified coal-fired utilities, as defined
elsewhere in this preamble. Effective controls have been adequately
demonstrated to reduce utility emissions; such reductions will further
the goal of reducing the domestic and global Hg pool.
Under the structure of the CAA, once we establish NSPS for new
sources under section 111(b), we must, with respect to designated
pollutants, establish 111(d) standards for existing sources.
Specifically, section 111(d) provides that the Administrator ``shall
prescribe regulations which establish a procedure under which each
State shall submit * * * a plan which establishes standards of
performance for any existing source for any air pollutant * * * to
which a standard of performance under this section would apply if such
existing source were a new source.'' Thus, because we deem it
appropriate to establish NSPS for Hg emissions from new sources, we are
obligated to establish NSPS Hg standards for existing sources as well.
III. Summary of the Final Rule Amendments
A. Who is subject to the final rule?
EPA is finalizing applicability provisions for 40 CFR part 60,
subparts Da and HHHH that are consistent with historical applicability
and definition determinations under the CAA section 111 and Acid Rain
programs. EPA realizes that these definitions are somewhat different
because of differences in the underlying statutory authority. EPA
believes that it is appropriate to finalize the applicability and
definitions of the revised subpart Da NSPS consistent with the
historical interpretations. Similarly, EPA believes that it is
appropriate to finalize the applicability and definitions of subpart
HHHH consistent with those of the Acid Rain and CAIR programs because
of the similarities in their trading regimes.
The 40 CFR part 60, subpart Da NSPS apply to Utility Units capable
of firing more than 73 megawatts (MW) (250 million Btu/hr; MMBtu/hr)
heat input of fossil fuel. The current NSPS also apply to industrial
cogeneration facilities that sell more than 25 MW of electrical output
and more than one-third of their potential output capacity to any
utility power distribution system. Utility Units subject to revised
subpart Da are also
[[Page 28610]]
subject to 40 CFR part 60, subpart HHHH.
The following units in a State shall be Hg Budget units (i.e.,
units that are subject to the Hg Budget Trading Program), and any
source that includes one or more such units shall be a Hg Budget
source, subject to the requirements of subpart HHHH:
(a) Except as provided in paragraph (b), a stationary, fossil fuel-
fired boiler or stationary, fossil fuel-fired combustion turbine
serving at any time, since the start-up of a unit's combustion chamber,
a generator with nameplate capacity of more than 25 MWe producing
electricity for sale.
(b) For a unit that qualifies as a cogeneration unit starting on
the date the unit first produces electricity, a cogeneration unit
serving at any time a generator with nameplate capacity of more than 25
MWe and supplying in any calendar year more than one-third of the
unit's potential electric output capacity or 219,000 MWh, whichever is
greater, to any utility power distribution system for sale. If a unit
qualifies as a cogeneration unit starting on the date the unit first
produces electricity but subsequently no longer qualifies as a
cogeneration unit, the unit shall be subject to paragraph (a) of this
section starting on the day on which the unit first no longer qualifies
as a cogeneration unit.
The Hg provisions of 40 CFR part 60, subparts Da and HHHH apply
only to coal-fired Utility Units (i.e., units where any amount of coal
or coal-derived fuel is used at any time). This is similar to the
definition that is used in the Acid Rain Program to identify coal-fired
units.
B. What are the primary sources of emissions, and what are the
emissions?
The final rule amendments add Hg to the list of pollutants covered
under 40 CFR part 60, subpart Da, by establishing emission limits for
new sources and guidelines for existing sources. New sources (and
existing subpart Da facilities), however, remain subject to the
applicable existing subpart Da emission limits for NOX,
SO2, and PM.
C. What is the affected source?
Only those coal-fired Utility Units for which construction,
modification, or reconstruction is commenced after January 30, 2004,
will be affected by the new-source provisions of the final rule
amendments under CAA section 111(b). Coal-fired Utility Units existing
on January 30, 2004, will be affected facilities for purposes of the
CAA section 111(d) guidelines finalized in the final rule.
D. What are the emission limitations and work practice standards?
The following standards of performance for Hg are being finalized
in the final rule for new coal-fired 40 CFR part 60, subpart Da units:
Bituminous units: 0.0026 nanograms per joule (ng/J) (21 x
10-6 pounds per megawatt-hour (lb/MWh));
Subbituminous units:
Wet FGD--0.0053 ng/J (42 x 10-6 lb/MWh);
Dry FGD--0.0098 ng/J (78 x 10-6 lb/MWh);
Lignite units: 0.0183 ng/J (145 x 10-6 lb/MWh);
Coal refuse units: 0.00018 ng/J (1.4 x 10-6 lb/MWh);
Integrated gasification combined cycle (IGCC) units: 0.0025 ng/J (20 x
10-6 lb/MWh).
All of these standards are based on gross energy output.
In addition, to complying with these standards, new units, along
with existing coal-fired Utility Units will be subject to the cap-and-
trade provisions being finalized in the final rule. The specifics of
the cap are described below.
Compliance with the final standards of performance for Hg will be
on a 12-month rolling average basis, as explained below. This
compliance period is appropriate given the nature of the health hazard
presented by Hg.
E. What are the performance testing, initial compliance, and continuous
compliance requirements?
Under 40 CFR part 60, subpart Da, new or reconstructed units must
commence their initial performance test by the applicable date in 40
CFR 60.8(a). Because compliance with the Hg emission limits in 40 CFR
60.45a is on a 12-month rolling average basis, the initial performance
test consists of 12 months of data collection with certified continuous
monitoring systems, to determine the average Hg emission rate. New and
existing units under 40 CFR part 60, subpart HHHH must certify the
required continuous monitoring systems and begin reporting Hg mass
emissions data by the applicable compliance date in 40 CFR 60.4170(b).
Under 40 CFR 60.49a(s), the owner/operator is required to prepare a
unit-specific monitoring plan and submit the plan to the Administrator
for approval, no less than 45 days before commencing the certification
tests of the continuous monitoring systems. The final rule amendments
require that the plan address certain aspects with regard to the
monitoring system; installation, performance and equipment
specifications; performance evaluations; operation and maintenance
procedures; quality assurance (QA) techniques; and recordkeeping and
reporting procedures. The final amendments require all continuous
monitoring systems to be certified prior to the commencement of the
initial performance test.
Mercury Emission Limits. Compliance with the final standard of
performance for Hg will be determined based on a rolling 12-month
average calculation. The rolling average is weighted according to the
number of hours of valid Hg emissions data collected each month, unless
insufficient valid data are collected in the month, as explained below.
The Hg emissions are determined by continuously collecting Hg emission
data from each affected unit by installing and operating a continuous
emission monitoring system (CEMS) or an appropriate long-term method
(e.g., sorbent trap) that can collect an uninterrupted, continuous
sample of the Hg in the flue gases emitted from the unit. The final
rule amendments will allow the owner/operator to use any CEMS that
meets the requirements in Performance Specification 12A (PS-12A),
``Specifications and Test Procedures for Total Vapor-phase Mercury
Continuous Monitoring Systems in Stationary Sources.'' Alternatively, a
Hg concentration CEMS that meets the requirements of 40 CFR part 75, or
a sorbent trap monitoring system that meets the requirements of 40 CFR
75.15 and 40 CFR part 75, appendix K, may be used. Note that EPA has
revised and renamed proposed Method 324, ``Determination of Vapor Phase
Flue Gas Mercury Emissions from Stationary Sources Using Dry Sorbent
Trap Sampling'' as 40 CFR part 75, appendix K).
For on-going quality control (QC) of the Hg CEMS, the final rule
requires the calibration drift and quarterly accuracy assessment
procedures in 40 CFR part 60, appendix F, to be implemented. The
quarterly accuracy tests consist of a relative accuracy test audit
(RATA) and three measurement error tests (as described in PS 12A),
using mercuric chloride (HgCl2) standards. In lieu of
implementing the 40 CFR part 60, appendix F procedures, the owner or
operator may QA the data from the Hg CEMS according to 40 CFR part 75,
appendix B. For sorbent trap monitoring systems, and annual RATA is
required, and the on-going QA procedures of 40 CFR part 75, appendix K,
must be met.
The final rule requires valid Hg mass emissions data to be obtained
for a minimum of 75 percent of the unit operating hours in each month.
If this
[[Page 28611]]
requirement is not met, the Hg data for the month are discarded. In
each 12-month cycle, if there are any months in which the data capture
requirement is not met, data substitution is required. For the first
such occurrence, the mean Hg emission rate for the last 12 months is
reported, and for any subsequent occurrences, the maximum emission rate
from the past 12 months is reported. For any month in which a
substitute Hg emission rate is reported, the substitute emission rate
is weighted according to the number of unit operating hours in that
month when the 12-month rolling average is calculated.
For new cogeneration units, steam is also generated for process
use. The energy content of this process steam must also be considered
in determining compliance with the output-based standard. Therefore,
the owner/operator of a new cogeneration unit will be required to
calculate emission rates based on electrical output to the grid plus
half the equivalent electrical output energy in the unit's process
steam. The procedure for determining these Hg emission rates is
described in 40 CFR 60.50a(g), and is consistent with those currently
used in 40 CFR part 60, subpart Da.
The owner/operator of a new coal-fired unit that burns a blend of
fuels will develop a unit-specific Hg emission limitation; the unit-
specific Hg emission rate will be used for the portion of the
compliance period in which the unit burned the blend of fuels. The
procedure for determining the emission limitations is outlined in 40
CFR 60.45a(a)(5)(i). The owner/operator of an existing coal-fired unit
that burns a blend of fuels will have to meet the limitations
applicable under its unit-specific Hg allocation as outlined elsewhere
in the final rule.
F. What are the notification, recordkeeping, and reporting
requirements?
The final rule requires the owner or operator to maintain records
of all information needed to demonstrate compliance with the applicable
Hg emission limit, including the results of performance tests, data
from the continuous monitoring systems, fuel analyses, calculations
used to assess compliance, and any other information specified in 40
CFR 60.7 (General Provisions).
Mercury compliance reports are required semiannually, under 40 CFR
60.51. Each compliance report must include the following information
for each month of the reporting period: (1) The number of unit
operating hours; (2) the number of unit operating hours with valid Hg
emissions data; (3) the calculated monthly Hg emission rate; (4) the
number of hours (if any) excluded from the emission calculations due to
startup, shutdown and malfunction; (5) the 12-month rolling average Hg
emission rate; and (6) the 40 CFR part 60, appendix F data assessment
report (DAR), or equivalent summary of QA test results if 40 CFR part
75 QA procedures are implemented.
IV. Significant Comments and Changes Since Proposal
A. Why is EPA not taking final action to regulate Ni emissions from
oil-fired units?
In the January 30, 2004 NPR, EPA proposed to regulate Ni emissions
from oil-fired units based on information collected and reported in the
Utility Study. During the ensuing public comment period on the January
30, 2004 NPR, the March 2004 SNPR, and the December 2004 NODA, EPA
received new information indicating that there were fewer oil-fired
units in operation and that Ni emissions had diminished since the
Utility Study. Accordingly, in the final rule, EPA is not taking final
action on the proposal to regulate Ni emissions from oil-fired units.
B. How did EPA select the regulatory approach for coal-fired units for
the final rule?
1. Applicability
EPA is maintaining the discrete applicability definitions of
``electric utility steam generating unit'' that have historically been
used under the CAA section 111 NSPS and the CAA section 401 Acid Rain
programs.
As defined in 40 CFR 60.41a, an ``electric utility steam generating
unit'' means
any steam electric generating unit that is constructed for the
purpose of supplying 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. Any steam supplied to a steam
distribution system for the purpose of providing steam to a steam-
electric generator that would produce electrical energy for sale is
also considered in determining the electrical energy output capacity
of the affected facility.
In the NPR, EPA proposed to modify the definition of an ``electric
utility steam generating unit'' to mean
any fossil fuel-fired combustion unit of more than 25 megawatts
electric (MWe) that serves a generator that produces electricity for
sale. A unit that cogenerates steam and electricity and supplies
more than one-third of its potential electric output capacity and
more than 25 MWe output to any utility power distribution system for
sale is also considered an electric utility steam generating unit.
This proposed change in the definition was made as a part of the
proposed CAA section 112 rulemaking alternative; however, it was EPA's
intent that this change also apply to the CAA section 111 rulemaking
alternative and, therefore, EPA is finalizing it as part of the section
111 rule today.
Only Utility Units that are fired by coal in any amount, or
combinations of fuels that include coal, are subject to the final rule.
Integrated gasification combined cycle units are also subject to the
final rule.
An affected source under NSPS is the equipment or collection of
equipment to which the NSPS rule limitations or control technology is
applicable. For the final rule, the affected source will be the group
of coal-fired units at a facility (a contiguous plant site where one or
more Utility Units are located). Each unit will consist of the
combination of a furnace firing a boiler used to produce steam, which
is in turn used for a steam-electric generator that produces electrical
energy for sale. This definition of affected source will include a wide
range of regulated units with varying process configurations and
emission profile characteristics.
EPA received comment requesting clarification of the applicability
definition relating to whether a unit would be classified as a Utility
Unit or an IB. For the purposes of 40 CFR part 60, subpart Da, EPA
believes that the definition being finalized today in 40 CFR part 60,
subpart Da clearly defines two categories of new sources--Utility Units
and non-Utility Units (which could include IB units, etc.). That is,
all three conditions must be met in order for a unit to be classified
as a Utility Unit: (1) Must sell more than 25 MWe to any utility power
distribution system; (2) any individual boiler must be capable of
combusting more than 73 MW (250 MMBtu/hr) heat input (which equates to
25 MWe on an output basis); and (3) if the unit is a cogeneration unit,
it must sell more than one-third of its potential electric output
capacity. The Agency's historical interpretation of the 40 CFR part 60,
subpart Da definition has been that a boiler meeting the capacity
definition (i.e., greater than 250 MMBtu/hr) but connected to an
electrical generator with a generation capacity of 25 MWe or less would
still be classified as an ``electric utility steam generating unit''
under 40 CFR part 60, subpart Da. However, one or more new boilers with
heat input capacities less than 250 MMBtu/hr each but connected to an
electrical generator with a
[[Page 28612]]
generation capacity of greater than 25 MWe would not be considered
Utility Units under 40 CFR part 60, subpart Da because they
individually do not meet the definition (they would be considered IB).
Under the final 40 CFR part 60, subpart HHHH rule, EPA is
continuing the definition of an Utility Unit used in the Acid Rain and
CAIR trading programs. A coal-fired Utility Unit is a unit serving at
any time, since the start-up of a unit's combustion chamber, a
generator with nameplate capacity of more than 25 MWe producing
electricity for sale. For a unit that qualifies as a cogeneration unit
during the 12-month period starting on the date the unit first produces
electricity and continues to qualify as a cogeneration unit, a
cogeneration unit serving at any time a generator with nameplate
capacity of more than 25 MWe and supplying in any calendar year more
than one-third of the unit's potential electric output capacity or
219,000 MWh, whichever is greater, to any utility power distribution
system for sale. If a unit qualifies as a cogeneration unit during the
12-month period starting on the date the unit first produces
electricity but subsequently no longer qualifies as a cogeneration
unit, the unit shall be subject to paragraph (a) of this definition
starting on the day on which the unit first no longer qualifies as a
cogeneration unit. These criteria are similar to the definition in the
NPR and SNPR with the clarification that the criteria be determined on
an annual basis. These criteria are the same used in the CAIR and are
similar to those used in the Acid Rain Program to determine whether a
cogeneration unit is a Utility Unit and the NOX SIP Call to
determine whether a cogeneration unit is an Utility Unit or a non-
Utility Unit.
2. Subcategorization
Under CAA section 111(b)(2), the Administrator has the discretion
to ``* * * distinguish among classes, types, and sizes within
categories of new sources * * *'' in establishing standards when
differences between given types of sources within a category lead to
corresponding differences in the nature of emissions and the technical
feasibility of applying emission control techniques. At proposal, EPA
examined a number of options for subcategorizing coal-fired Utility
Units, including by coal rank and by process type. Based on the
information available, EPA proposed to use five subcategories for
establishing Hg limits based on a combination of coal rank and process
type in the final rule (bituminous coal, subbituminous coal, lignite
coal, coal refuse, and IGCC). EPA is today finalizing these five
subcategories.
EPA received numerous comments both in support of and in opposition
to the proposed subcategorization approach for both new and existing
Utility Units. Those commenters opposed to the proposed approach
suggested several alternative approaches, including no
subcategorization, combining bituminous and subbituminous coal ranks in
one subcategory, a separate subcategory for Gulf Coast lignite, and a
separate subcategory for fluidized bed combustion (FBC) units, among
others. Other commenters indicated that any subcategorization approach
should be ``fuel neutral,'' i.e., not disadvantage any rank of coal or
lead to fuel switching, and/or should not result in the loss of
viability of any coal rank.
Those commenters opposed to subcategorization generally argued that
subcategorization can only be done on three criteria: Class, type, and
size of sources and contended that the fact that coal rank is one of
the characteristics of a coal-fired boiler does not mean it can be used
for subcategorization. The commenters stated that EPA's reliance on
coal rank is misplaced because many coal-fired units blend or fire two
or more ranks of coal in the same boiler, and EPA itself states that
coal blending is possible and not uncommon. The commenters stated that
EPA had also provided unsupported claims that fuel switching would
require significant modification or retooling of a unit. The commenters
cited case law to support their contention that EPA's proposed
subcategorization is not permitted and stated that EPA's justification
for rejecting a no subcategorization option is factually and legally
indefensible.
A similar argument was presented by those commenters suggesting a
single subcategory for bituminous and subbituminous coals. That is,
given the extent of coal blending, particularly with respect to these
two coal ranks, a single subcategory was appropriate. Further, the
commenters argued that the proposed emission limits for the two
subcategories disadvantaged bituminous coal.
Commenters representing producers and users of Gulf Coast lignite
suggested that a separate subcategory should be established for this
coal because of its significantly higher Hg content, even when compared
to Fort Union lignite. Gulf Coast lignite, therefore, is more difficult
to control.
Several commenters suggested that the American Society of Testing
and Materials (ASTM) classification methodology for ranking coals is an
inappropriate basis upon which to base subcategorization. This claim
was made primarily because of the overlaps in the ASTM classification
methodology and the fact that some Western coal seams are alleged to
provide both bituminous and subbituminous coal ranks. Reliance on the
ASTM methodology would create problems for the users of this coal in
determining which subcategory they were in.
Several commenters indicated that a separate subcategory for FBC
units, is appropriate because FBC units use a fundamentally different
combustion process than pulverized-coal (PC) units, making them a
different type of source.
Commenters concerned that the nation's fuel supply not be
jeopardized stated that the final rule must be consistent with the need
for reliable and affordable electric power, including affordable use of
all coal ranks and options for efficient on-site power generation such
as combined heat and power (CHP). The commenters stated that the final
rule must facilitate--not discourage--the availability of an adequate
and diverse fuel supply for the future, including all coal ranks,
natural gas, nuclear energy, hydroelectric, and renewable sources.
According to several commenters, the final rule must not aggravate the
already precarious natural gas supply which is currently inadequate.
EPA continues to believe that it has the statutory authority to
subcategorize based on coal rank and process type, as appropriate for a
given standard. As initially structured, 40 CFR part 60, subpart Da
subcategorized based on the sulfur content of the coal (essentially
based on coal rank) for SO2 emission limits and based on
coal rank for NOX emission limits. This approach was
selected because of the differences in the relative ability of the
respective control technologies to effect emissions reductions on the
various coal ranks. Although EPA has recently proposed (February 28,
2005; 70 FR 9706) to change the format of the NOX emission
limits and to establish common SO2 emission limits
regardless of coal rank, we believe that the conditions existing when
we proposed 40 CFR 60, subpart Da in 1978 (e.g., the inability of the
technologies to control SO2 and NOX equally from
all coal ranks) still exist for Hg and justify the use of
subcategorization by coal rank for the Hg emission limits. At some
point in the future, the performance of control technologies on Hg
emissions could advance to the point that the rank of coal being fired
is irrelevant to the level of Hg control that can be achieved (similar
to the point reached by controls
[[Page 28613]]
for SO2 and NOX emissions). If that occurs, EPA
may consider adjusting the approach to Hg controls appropriately.
EPA believes that there are sufficient differences in the design
and operation of utility boilers utilizing the different coal ranks to
justify subcategorization by major coal rank. As documented in the
record, utility boilers vary in size depending on the rank of coal
burned (i.e., boilers designed to fire lignite coal are larger than
those designed to fire subbituminous coal which, in turn, are larger
than those designed to fire bituminous coal). Boilers designed to burn
one fuel (e.g., lignite) cannot randomly or arbitrarily change fuels
without extensive testing and tuning of both the boiler and the control
device. Further, if a different rank of coal is burned in a boiler
designed for another rank, either in total or through blending, the
practice is only done with ranks that have similar characteristics to
those for which the boiler was originally designed. To do otherwise
entails a loss of efficiency and/or significant increases in
maintenance costs. That is, the ASTM classification system is
structured on a continuum based on a number of characteristics (e.g.,
heat content or Btu value, fixed carbon, volatile matter, agglomerating
vs. non-agglomerating) and provides basic information regarding
combustion characteristics. Because more than one characteristic is
used, the possibility exists for numerous situations where a coal could
be ``classified'' in one rank based on one characteristic but in
another rank based on another characteristic. Ranking is based on an
evaluation of all characteristics. Therefore, it is possible that (for
example) a non-agglomerating subbituminous coal with a heating value of
8,300 Btu/lb (ASTM classification III.3--``Subbituminous C coal'')
could be co-fired with, or substituted for, a non-agglomerating lignite
coal with heating value of 8,300 Btu/lb (ASTM classification IV.1--
``Lignite A coal''). This does not, however, mean that it is possible
for a boiler designed to burn the Lignite A coal to burn an
agglomerating coal with a heating value of 13,000 Btu/lb (e.g., ASTM
classification II.5--``High volatile C bituminous coal''). Further, it
does not mean that the substituted coal would exhibit the same
``controllability'' with respect to emissions reductions as the
original coal, regardless of its compatibility with the boiler. The
fact that a number of Utility Units co-fire different ranks of coal
does not negate the overall differences in the ranks that preclude
universal coal rank switching, particularly when the design coal ranks
are not adjacent on the ASTM classification continuum.
Although other classification approaches have been suggested, the
ASTM classification system remains the one most recognized and utilized
by the industry and the one which the EPA believes is most suitable for
use as a basis for subcategorization. Further, EPA is perplexed by the
comments indicating that Utility Units do not know the coal rank that
they are firing and would incur additional costs to determine this for
the purpose of establishing their subcategory. Electric utilities are
currently required by law to report to the U.S. Department of Energy,
Energy Information Administration (DOE/EIA) on one or more of six
different forms, the rank of coal burned in each Utility Unit. EPA is
not suggesting that these utilities do anything different in
establishing their subcategory and respective emission limit. Utility
Units that blend coals from different ranks would need to follow the
specified procedures for establishing the appropriate emission limit
for blended coals. EPA, therefore, believes that, at this time, coal
rank is an appropriate and justifiable basis on which to subcategorize
for the purposes of the final rule.
EPA continues to believe that there is insufficient evidence
available to justify separate subcategories for Gulf Coast and Fort
Union lignites. The reanalysis of the data in support of the revised
NSPS Hg emission limits, discussed later in this preamble, incorporated
data from units firing both types of lignite, further lessening the
necessity of additional subcategorization. EPA will continue to
evaluate the Hg emission data that become available, including that
generated through the studies on emerging Hg control technologies by
the DOE, and reassess issues of further subcategorizing lignites during
the normal 8-year NSPS review cycle.
With regard to FBC units, EPA agrees that such units operate and
are designed differently than conventional PC boilers. However, with
the exception of FBC units firing coal refuse, there was no clear
indication from the available data that such units influenced the
ultimate Hg control. That is, in some cases, FBC units were better than
most with respect to their Hg emissions; in other cases, FBC units were
worse than most. Therefore, EPA concluded that it was the coal rank,
rather than the process type (e.g., FBC, PC) that should govern in any
determination relating to subcategorization.
EPA's modeling has shown minimal coal switching as a result of the
final CAMR and CAIR actions. We believe that this rebuts the
commenters' suggestions that the final rule will cause one or another
coal rank to be ``advantaged'' or ``disadvantaged'' with respect to
other coal ranks. Further, we do not believe that the final rule will
have a negative impact on the nation's energy security, employment
rates, or energy reliability.
New units designed to burn bituminous coals will still not be able
to burn lignite coals (for example) and, thus, EPA believes that the
need for subcategorization remains, even for new units.
C. How did EPA determine the NSPS under CAA section 111(b) for the
final rule?
1. Criteria Under CAA Section 111
CAA section 111 creates a program for the establishment of
``standards of performance.'' A ``standard of performance'' is ``a
standard for emissions of air pollutants which reflects the degree of
emission limitation achievable through the application of the best
system of emission reduction, which (taking into the cost of achieving
such reduction, any non-air quality health and environmental impacts
and energy requirements), the Administrator determines has been
adequately demonstrated.'' (See CAA section 111(a)(1).)
For new sources, EPA must first establish a list of stationary
source categories which the Administrator has determined ``causes, or
contributes significantly to, air pollution which may reasonably be
anticipated to endanger public health or welfare.'' (See CAA section
111(b)(1)(A).) EPA must then set Federal standards of performance for
new sources within each listed source category. (See CAA section
111(b)(1)(B).) Like CAA section 112(d) standards, the standards for new
sources under section 111(b) apply nationally and are effective upon
promulgation. (See CAA section 111(b)(1)(B).)
Section 111(b) covers any category of sources that causes or
contributes to air pollution that may reasonably be anticipated to
endanger public health or welfare and provides EPA authority to
regulate new sources of such air pollution. EPA included Utility Units
on the section 111(b) list of stationary sources in 1979 and has issued
final standards of performance for new Utility Units for pollutants,
such as NOX, PM, and SO2. (See 44 FR 33580; June
11, 1979; 40 CFR part 60, subpart Da.) Nothing in the language of
section 111(b) precludes EPA from issuing additional standards of
performance for
[[Page 28614]]
other pollutants, including HAP, emitted from new Utility Units.
Moreover, nothing in CAA section 112(n)(1)(A) suggests that Congress
sought to preclude EPA from regulating Utility Units under CAA section
111(b). Indeed, section 112(n)(1)(A) provides to the contrary, in that
it calls for an analysis of utility HAP emissions ``after imposition of
the requirements'' of the CAA, which we have reasonably interpreted to
mean those authorities that EPA reasonably anticipates will be
implemented and will reduce utility HAP emissions.
2. Mercury Control Technologies
At proposal, EPA stated that available information indicates that
Hg emissions from coal-fired Utility Units are minimized in some cases
through the use of PM controls (e.g., fabric filter or electrostatic
precipitator (ESP)) coupled with a flue gas desulfurization (FGD)
system. For bituminous-fired units, use of a selective catalytic
reduction (SCR) or selective non-catalytic reduction (SNCR) system in
conjunction with one of these systems may further enhance Hg removal.
This SCR-induced enhanced Hg removal appears to be absent for
subbituminous- and lignite-fired units.
The EPA believes the best potential way of reducing Hg emissions
from IGCC units, on the other hand, is to remove Hg from the synthetic
gas (syngas) before combustion. An existing industrial IGCC unit has
demonstrated a process, using sulfur-impregnated activated carbon (AC)
beds, that has proven to yield 90 to 95 percent Hg removal from the
coal syngas. Available information indicates that this technology could
be adapted to the electric utility IGCC units, and EPA believes this to
be a viable option for new IGCC units.
In selecting a regulatory approach for formulating emission
standards to limit Hg emissions from new coal-fired Utility Units, the
performance of the control technologies discussed on Hg above were
considered. After considering the available information, EPA has
determined that the technical basis (i.e., the best system of emission
reduction which the Administrator determines has been adequately
demonstrated, or best demonstrated technology, BDT) selected for
establishing Hg emission limits for new sources is the use of effective
PM controls (e.g., fabric filter or ESP) and wet or dry FGD systems on
subbituminous-, lignite-, and coal refuse-fired units; effective PM
controls, wet or dry FGD systems, and SCR or SNCR on bituminous-fired
units; and AC beds for IGCC units.
EPA received several public comments that disagreed with the EPA's
conclusion at proposal that Hg-specific controls for Utility Units,
including activated carbon injection (ACI), will not be commercially
available on a wide scale until 2010 or later. Arguments stated by
these commenters included the following assertions: (a) Mercury control
technologies are available now and EPA disregarded studies on emerging
Hg control technologies by the DOE, the industry, and others. (b) The
EPA's own numbers and other studies indicate that coal-fired plants can
achieve 90 percent reduction regardless of the type of plant or coal.
(c) Field testing of ACI has shown 90 percent capture of Hg. Units
equipped with FGD units and fabric filters can obtain near 90 percent
removal of Hg. (d) Studies indicate that the cost of Hg controls would
be comparable to the cost of controls for other pollutants and EPA
disregarded these studies and the emerging state-of-the-art Hg control
technologies. (e) Permits have been issued that will rely on sorbent
injection technologies such as ACI (e.g., MidAmerican Energy, Council
Bluffs Unit 4, issued by IA; and Wisconsin Public Service Corporation,
Weston Unit 4, issued by WI). These permits show that Hg removal
technologies capable of achieving more than 80 percent control are
available.
EPA agrees, based on the limited test data available, that some
coal-fired units have exhibited greater than 90 percent Hg reductions
during short-term sorbent injection studies. However, not all units
have been able to achieve this level of control, even with similar
control technologies installed and no units have been able to achieve
this level of control for an extended period of time. EPA disagrees
with the commenters' assessment, however, regarding the extent to which
Hg-specific control technologies, including ACI, are currently
available and on the time necessary for them to become commercially
available. Although we do believe that these technologies have been
currently demonstrated to be capable of achieving significant
reductions in Hg emissions, we do not believe that they are available
now for wide-spread or long-term usage. We have been following the
studies of such technologies closely and have discussed their degree of
development with vendors, the industry, and the DOE. With the exception
of one test that has lasted approximately 1 year, no Utility Unit has
operated a Hg-specific control technology full-scale for longer than
approximately a month. Further, the technologies have not been fully
evaluated on any coal ranks for an extended period of time and have not
even been evaluated under short-term conditions for some coal ranks
(e.g., Gulf Coast lignite). In addition, other aspects of the use of
Hg-specific control technologies (e.g., balance of plant, waste issues,
atmospheric concerns) have not been fully addressed. Studies continue
to (1) evaluate the impact of using both ACI and enhanced ACI (e.g.,
corrosion) on the coal-fired facility as a whole; (2) assess the impact
of the ACI or enhanced ACI on the reuse and disposal of fly ash; and
(3) evaluate the other atmospheric emissions and the impacts that may
result from use of ACI or enhanced ACI (e.g., brominated dioxins
emitted either directly or formed following emission to the
atmosphere).
As discussed in the EPA Office of Research and Development's (ORD)
revised White Paper ``Control of Mercury Emissions from Coal Fired
Electric Utility Boilers: An Update'' (OAR-2002-0056), since the
release of the earlier White Paper ``Control of Mercury Emissions from
Coal-fired Electric Utility Boilers'' (OAR-2002-0056), additional data,
mostly from short-term tests, have become available on Hg control
approaches for Utility Units. Also, as noted above, the DOE and EPA
have underway broad and aggressive research program, which will yield
experience and data in the next few years. Accordingly, EPA continues
to believe that ACI and enhanced multipollutant controls have been
demonstrated to effectively remove Hg and will be available after 2010
for commercial application on most or all key combinations of coal rank
and control technology to provide Hg removal levels between 60 and 90
percent on individual Utility Units. Considering the progress made with
halogenated AC sorbents and other chemical injection approaches to
date, we now believe that optimized multipollutant controls may be
available in the 2010 to 2015 timeframe for commercial application on
most, if not all, key combinations of coal rank and control technology
to provide Hg removal levels between 90 and 95 percent. Such optimized
controls could include use of sorbent (ACI or halogenated ACI) with
enhanced SCR and/or enhanced FGD systems. These controls provide
justification for a 2018 cap at a level below what is projected to be
achieved from SO2 and NOX reduction levels alone.
Although EPA is optimistic that such controls may be
[[Page 28615]]
available for use on some scale prior to 2018, it does not believe that
such controls can be installed and operated on a national scale before
that date.
Based on these tests, on-going studies, and discussions, we do not
believe that the Hg-specific technologies have demonstrated an ability
to consistently reduce Hg emissions by 90 percent (or any other level)
at the present time. We believe that the cap-and-trade approach
selected for the final regulation is the best method for encouraging
the continued development of these technologies. Further, although not
ready for use in establishing a nationwide emission regulation at this
time, EPA believes that installation of Hg-specific control
technologies, including ACI, on a limited number of units is possible
well in advance of the Phase II cap. The economic incentives inherent
in the two-phase cap-and-trade program finalized today will serve to
advance the technologies such that they are widely available for use in
complying with the Phase II cap.
3. Emissions Limitations
EPA established the proposed emission limits by direct transfer
from the proposed new-source CAA section 112 emission limits. During
the public comment period, it was pointed out by a number of commenters
that under CAA section 111, NSPS should ``reflect the degree of
emission limitation and the percentage reduction achievable through
application of the best technological system of continuous emission
reduction * * * (taking into consideration the cost of achieving such
emission reduction, any non-air quality health and environmental impact
and energy requirements)'' rather than ``not be less stringent than the
emission control that is achieved in practice by the best controlled
similar source'' under CAA section 112. The commenters pointed out that
emission limits under both CAA sections begin with an assessment of
what limit is achievable in practice with the best available controls,
but the NSPS goes on to consider cost, energy use, and non-air impacts.
Accordingly, it is inappropriate and inconsistent with the CAA for the
EPA to establish an NSPS requirement based on an analysis undertaken
pursuant to the requirements of CAA section 112 which ignores costs at
what is referred to the floor level of control. Commenters further
noted that the proposed emission limits would preclude new coal-fired
units from being built and offered approved permit levels as evidence
that the proposed limits were unachievable.
EPA agrees with the commenters who indicated that the NSPS limits
were not established in a manner consistent with the requirements of
CAA section 111. Therefore, we re-analyzed the information collection
request (ICR) data collected in 1999 and examined the Hg limits in
recently issued permits. Based on this refined analysis, we arrived at
the following NSPS Hg emission limits for the five subcategories:
Bituminous units: 0.0026 ng/J (21 x 10-\6\ lb/MWh);
Subbituminous units:
--Wet FGD units: 0.0053 ng/J (42 x 10-\6\ lb/MWh);
--Dry FGD units: 0.0098 ng/J (78 x 10-\6\ lb/MWh);
Lignite units: 0.0183 ng/J (145 x 10-\6\ lb/MWh);
Coal refuse units: 0.00018 ng/J (1.4 x 10-\6\ lb/MWh);
IGCC units: 0.0025 ng/J (20 x 10-\6\ lb/MWh).
Documentation for this re-analysis may be found in the e-docket (OAR-
2002-0056).
To establish the revised new-source limits, EPA re-examined the
1999 ICR data which includes an estimate of the Hg removal efficiency
for the suite of emission controls in use on each unit tested. The EPA
focused primarily on the 1999 ICR data because it is the only test data
for a large number of Utility Units employing a variety of control
technologies currently available to the Agency and because there is
very limited permit data for new or projected facilities from which to
determine existing Hg emission limits. (The EPA has historically relied
on permit data in establishing NSPS limits because it believes that
such limits reasonably reflect the actual performance of the unit.) We
analyzed the performance of currently installed control technologies in
the respective subcategories in an effort to identify a best adequately
demonstrated system of emission reduction, also referred to as BDT, for
each subcategory. To do this, we determined the combination of control
technologies that a new unit would install under the current NSPS to
comply with the emissions standards for PM, SO2, and
NOX. Based on the available data, units using these
combinations of controls had the highest reported control efficiency
for Hg emissions. Thus, we determined that BDT for each subcategory of
units is a combination of controls that would generally be installed to
control PM and SO2 under the NSPS. For bituminous units, BDT
was determined to be the combination of a fabric filter and a FGD (wet
or dry) system. However, recent test data reports show that a
bituminous coal based system including a SCR, ESP and wet FGD may also
be capable of meeting the performance limit set for bituminous coal-
fired Utility Units, and this information was considered in setting the
new source limits. For subbituminous units, BDT was determined to be
dependent on water availability. For subbituminous units located in the
western U.S. that may face potential water restriction and, thus, do
not have the option of using a wet FGD system for SO2
control, BDT is a combination of either a fabric filter with a spray
dryer absorber (SDA) system or an ESP with a SDA system. For
subbituminous units that do not face such potential water restrictions,
BDT is a fabric filter in combination with a wet FGD system. For
lignite units, BDT is either a fabric filter and SDA system or an ESP
with a wet FGD system.
To determine the appropriate achievable Hg emission level for each
coal type, a statistical analysis was conducted. Specifically, the Hg
emissions limitation achievable for each coal type was determined based
on the highest reported annual average Hg fuel content for the coal
rank being controlled by the statistically-calculated control
efficiency for the BDT determined for that fuel type. The control
efficiency for BDT was calculated by determining the 90th percentile
confidence level using the one-sided z-statistics test (i.e., the Hg
removal efficiency, using BDT, estimated to be achieved 90 percent of
the time). The data used consisted of stack emission measurements
(pounds Hg per trillion Btu (lb Hg/TBtu)) for each unit, the average
fuel Hg content for the fuel being burned by that unit during the test
(parts per million (ppm)), and the highest average annual fuel Hg
content reported for any unit in the coal rank. Because the Hg
emissions from any control system is a linear function of the inlet Hg
(i.e., Hg fuel content), assuming a constant control efficiency, the
reported highest annual average inlet Hg was adjusted to determine the
potential maximum Hg emissions that would be emitted if BDT was
employed. The calculated 90th percentile confidence limit control
reduction for each subcategory, based on the calculated highest annual
average uncontrolled Hg emissions, in lb Hg/TBtu, for the subcategory
was determined to be the new source emission limit. Finally, the new
source limit for IGCC units and its justification
[[Page 28616]]
remains unchanged from the limit proposed in January 2004 (69 FR 4652).
EPA also evaluated recent available permit Hg levels for comparison
with the limits presented above. EPA does not believe that the use of
permit Hg limits is appropriate for independently establishing NSPS
emission limits because of the limited number of permits issued with Hg
emission levels and the limited experience of both State permitting
authorities and the industry itself with establishing appropriate
permit conditions. However, comparison of the available permit limits
with those developed by EPA is a valid ``reality check'' on the
appropriateness of EPA's limits. Available permits on bituminous-fired
units have Hg emission limits ranging from approximately 20 x
10-\6\ lb/MWh to 39 x 10-\6\ lb/MWh; those for
subbituminous-fired units range from 11 x 10-\6\ lb/MWh to
126 x 10-\6\ lb/MWh. Considering the limited number of
permits and the limited experience in developing appropriate Hg limits
for those permits, EPA believes that its final NSPS Hg emission limits
are in reasonable agreement with these permits. Insufficient permit
information is available to do a similar comparison for lignite- and
coal refuse-fired units, but we have used the same analytic procedure
for these subcategories.
Further, EPA concurs with those commenters who indicated that we
had overstated the variability in the context of the proposed CAA
section 111 NSPS limits by using both a rigorous statistical analysis
and a 12-month rolling average for compliance. Therefore, for the final
rule, while we have retained the 12-month rolling average for
compliance, we have used the annual average fuel Hg content in the ICR
data to establish the NSPS limits. Given the favorable comparison with
the available permit data, we believe that variability has been
adequately addressed.
Although EPA has re-analyzed the available data and revised its
NSPS Hg emission limits, we continue to believe that these limits are
of short-term value only. That is, the Hg cap being finalized today
will be a greater long-term factor in constraining Hg emissions from
new coal-fired Utility Units than will the new-source emission limits
being issued today. In addition, the new source review (NSR) provisions
provide an additional constraint on new-source emissions, further
diminishing the importance of the revised new-source Hg emission
limits. Essentially, the new source limits become a ``backstop'' for
the trading program and other NSR requirements. Further, it is not our
intention to exclude any type of domestic coal from the market. If
information becomes available in the future that we feel adversely
impacts the coals or the fuel market, we will review and reconsider
these limits.
As required by CAA section 111(a)(1), EPA has considered the cost
of achieving the reductions in Hg emissions required by the new-source
standards, the non-air quality health and environmental impacts arising
from the implementation of the new-source standards and the energy
requirements associated with the new-source standards and determined
that they are all reasonable. (The costs of complying with CAMR as a
whole are discussed briefly below, and in more detail in the two air
dockets for the CAMR rule: Docket ID No. OAR-2002-0056 and Docket ID
No. A-92-55. The non-air quality health and environmental impacts
arising from the implementation of CAMR, as well as the energy
requirements associated with CAMR, are discussed briefly below, and in
more detail in Docket ID No. OAR-2002-0056 and Docket ID No. A-92-55.)
D. How did EPA determine the Hg cap-and-trade program under CAA section
111(d) for the final rule?
1. Criteria Under CAA Section 111 for Standards of Performance for
Existing Sources and Authority for Cap-and-Trade Under CAA Section
111(d)
CAA section 111(d)(1) authorizes EPA to promulgate regulations that
establish a SIP-like procedure under which each State submits to EPA a
plan that, under subparagraph (A), ``establishes standards of
performance for any existing source'' for certain air pollutants, and
which, under subparagraph (B), ``provides for the implementation and
enforcement of such standards of performance.'' Paragraph (1)
continues, ``Regulations of the Administrator under this paragraph
shall permit the State in applying a standard of performance to any
particular source under a plan submitted under this paragraph to take
into consideration, among other factors, the remaining useful life of
the existing source to which such standard applies.'' CAA section
111(a) defines, ``(f)or purposes of * * * section (111),'' the term
``standard of performance'' to mean
a standard for emissions of air pollutants which reflects the degree
of emission limitation achievable through the application of the
best system of emission reduction which (taking into account the
cost of achieving such reduction and any non-air quality health and
environmental impact and energy requirements) the Administrator
determines has been adequately demonstrated.
Taken together, these provisions authorize EPA to promulgate a
``standard of performance'' that States must, through a SIP-like
system, apply to existing sources. A ``standard of performance'' is
defined as a rule that reflects emission limits to the degree
achievable through ``the best system of emission reduction'' that EPA
``determines has been adequately demonstrated,'' considering costs and
other factors.
A cap-and-trade program reduces the overall amount of emissions by
requiring sources to hold allowances to cover their emissions on a one-
for-one basis; by limiting overall allowances so that they cannot
exceed specified levels (the ``cap''); and by reducing the cap to less
than the amount of emissions actually emitted, or allowed to be
emitted, at the start of the program. In addition, the cap may be
reduced further over time. Authorizing the allowances to be traded
maximizes the cost-effectiveness of the emissions reductions in
accordance with market forces. Sources have an incentive to endeavor to
reduce their emissions cost-effectively; if they can reduce emissions
below the number of allowances they receive, they may then sell their
excess allowances on the open market. On the other hand, sources have
an incentive to not put on controls that cost more than the allowances
they may buy on the open market.
The term ``standard of performance'' is not explicitly defined to
include or exclude an emissions cap and allowance trading program. In
the final rule, EPA interprets the term ``standard of performance,'' as
applied to existing sources, to include a cap-and-trade program. This
interpretation is supported by a careful reading of the section 111(a)
definition of the term, quoted above: A requirement for a cap-and-trade
program (i) constitutes a ``standard for emissions of air pollutants''
(i.e., a rule for air emissions), (ii) ``which reflects the degree of
emission limitation achievable'' (i.e., which requires an amount of
emissions reductions that can be achieved), (iii) ``through application
of (a) * * * system of emission reduction'' (i.e., in this case, a cap-
and-trade program that caps allowances at a level lower than current
emissions).\2\
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\2\ The legislative history of the term, ``standard of
performance,'' does not address an allowance/trading system, but
does indicate that Congress intended that existing sources be
accorded flexibility in meeting the standards. See ``Clean Air Act
Amendments of 1977,'' Committee on Interstate and Foreign Commerce,
H.R. Rep. No. 95-294 at 195, reprinted in 4 ``A Legislative History
of the Clean Air Act Amendments of 1977,'' Congressional Research
Service, 2662. The EPA interprets this legislative history as
generally supportive of interpreting ``standard of performance'' to
include an allowance/trading program because such a program accords
flexibility to sources.
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[[Page 28617]]
Nor do any other provisions of section 111(d) indicate that the
term ``standard of performance'' may not be defined to include a cap-
and-trade program. Section 111(d)(1)(B) refers to the ``implementation
and enforcement of such standards of performance,'' and section
111(d)(1) refers to the State ``in applying a standard of performance
to any particular source,'' but all of these references readily
accommodate a cap-and-trade program.
Although section 111(a) defines ``standard of performance'' for
purposes of section 111, section 302(l) defines the same term, ``(w)hen
used in this Act,'' to mean ``a requirement of continuous emission
reduction, including any requirement relating to the operation or
maintenance of a source to assure continuous emission reduction.'' The
term ``continuous'' is not defined in the CAA.
Even if the 302(l) definition applied to the term ``standard of
performance'' as used in section 111(d)(1), EPA believes that a cap-
and-trade program meets the definition. A cap-and-trade program with an
overall cap set below current emissions is a ``requirement of * * *
emission reduction.'' Moreover, it is a requirement of ``continuous''
emissions reductions because all of a source's emissions must be
covered by allowances sufficient to cover those emissions. That is,
there is never a time when sources may emit without needing allowances
to cover those emissions.\3\
---------------------------------------------------------------------------
\3\ This interpretation of the term ``continuous'' is consistent
with the legislative history of that term. See H.R. Rep. No. 95-294
at 92, reprinted in 4 ``A Legislative History of the Clean Air Act
Amendments of 1977,'' Congressional Research Service, 2559.
---------------------------------------------------------------------------
We note that EPA has on one prior occasion authorized emissions
trading under section 111(d). (The Emission Guidelines and Compliance
Times for Large Municipal Waste Combustors that are Constructed on or
Before September 20, 1994; 40 CFR part 60, subpart Cb.) This provision
allows for a NOX trading program implemented by individual
States. Section 60.33b(C)(2) states,
A State plan may establish a program to allow owners or operators of
municipal waste combustor plants to engage in trading of nitrogen
oxides emission credits. A trading program must be approved by the
Administrator before implementation.
The final rule is wholly consistent with this prior CAA section 111(d)
trading provision.
Having interpreted the term ``standard of performance'' to include
a cap-and-trade program, EPA must next ``determine'' that such a system
is ``the best system of emissions reductions which (taking into account
the cost of achieving such reduction and any non-air quality health and
environmental impact and energy requirements) * * * has been adequately
demonstrated.'' (See CAA section 111(a)(1).) EPA has determined that a
cap-and-trade program based on control technology available in the
relevant timeframe is the best system for reducing Hg emissions from
existing coal-fired Utility Units.
Since the passage of the 1990 CAAA, EPA has had significant
experience with the cap-and-trade program for utilities. The 1990 CAAA
provided, in title IV, for the Acid Rain program, a national cap-and-
trade program that covers SO2 emissions from utilities.
Title IV requires sources to hold allowances for each ton of
SO2 emissions, on a one-for-one basis. EPA allocates the
allowances for annual periods, in amounts initially determined by the
statute, that decrease further at a statutorily specified time. This
program has resulted in an annual reduction in SO2 emissions
from utilities from 15.9 million tons in 1990 (the year the CAAA were
enacted) to 10.2 million tons in 2002 (the most recent year for which
data is available). Emissions in 2002 were 9 percent lower than 2000
levels and 41 percent lower than 1980, despite a significant increase
in electrical generation. As discussed elsewhere, at full
implementation after 2010, emissions will be limited to 8.95 million
tons, a 50 percent reduction from 1980 levels. The Acid Rain program
allowed sources to trade allowances, thereby maximizing overall cost-
effectiveness.
In addition, in the 1998 NOX SIP Call rulemaking, EPA
promulgated a NOX reduction requirement that affects 21
States and the District of Columbia (``Finding of Significant
Contribution and Rulemaking for Certain States in the Ozone Transport
Assessment Group Region for Purposes of Reducing Regional Transport of
Ozone; Rule,'' 63 FR 57,356 (October 27, 1998)). All of the affected
jurisdictions are implementing the requirements through a cap-and-trade
program for NOX emissions primarily from utilities.\4\ These
programs are contained in SIP that EPA has approved, and EPA is
administering the trading programs. However, for most States, the
requirements did not need to be implemented until May 2004.
---------------------------------------------------------------------------
\4\ Non-electricity generating units are also included in the
States' programs.
---------------------------------------------------------------------------
The success of the Acid Rain cap-and-trade program for utility
SO2 emissions, which EPA duplicated in large measure with
the NOX SIP Call cap-and-trade program for, primarily,
utility NOX emissiofrom utilities qualifies as the ``best
system of emission reductions'' that ``has been adequately
demonstrated.'' A market system that employs a fixed tonnage limitation
(or cap) for Hg sources from the power sector provides the greatest
certainty that a specific level of emissions will be attained and
maintained because a predetermined level of reductions is ensured. The
EPA will administer a Hg trading program and will require the use of
monitoring to allow both EPA and sources to track progress, ensure
compliance, and provide credibility to the trading component of the
program.
2. What Is Justification for the National Hg Budget?
The EPA believes that a carefully designed ``multi-pollutant''
approach, a program designed to control NOX, SO2,
and Hg at the same time (i.e., CAIR implemented with CAMR), is the most
effective way to reduce emissions from the power sector. One key
feature of such an approach is the interrelationship of the timing and
cap levels for NOX, SO2, and Hg. Our analyses
show that the use of FGD (to reduce SO2 emissions) and SCR
(to reduce NOX) also has the effect of controlling Hg
emissions at the same time. We have designed the CAIR and CAMR approach
to take advantage of this so-called Hg ``co-benefit.'' We believe,
based on the results of sophisticated economic and environmental
modeling analyses, that the Phase I Hg cap should be set at a level
that reflects these co-benefits, and that additional controls designed
specifically for Hg should not be required until after 2010.
Furthermore, a multipollutant approach that focuses first on
SO2 and NOX reductions will also achieve
significant reductions in oxidized Hg. As explained elsewhere in this
document, reductions in this Hg species are the most beneficial to
reductions in U.S. Hg deposition.
A Phase I cap based on ``co-benefits'' fulfills EPA's obligation to
set a standard of performance based on the best system of emissions
reduction that has been adequately demonstrated. Both DOE and ORD
research currently indicate that Hg-specific air pollution control
technology, most notably sorbent injection, may one day allow
facilities to reliably reduce Hg emissions to levels significantly
below the ``co-benefits'' levels achieved through application of
SO2 and NOX control technologies. However, Hg-
specific technologies such as ACI have not been
[[Page 28618]]
demonstrated in practice on full-scale power plants for extended
periods of time, nor are they considered commercially available at this
time. Current information on these technologies, as outlined in the
revised ORD White Paper, ``Control of Mercury Emissions from Coal Fired
Electric Utility Boilers: An Update,'' (OAR-2002-0056) is only adequate
for us to conclude that such technologies are adequately demonstrated
for use in the 2010 to 2018 time-frame to allow for compliance with the
CAMR Phase II Hg cap. Therefore, for purposes of setting the 2010 Hg
cap, we conclude that Hg reductions achieved as a ``co-benefit'' of
controlling SO2 and NOX under CAIR should dictate
the appropriate cap level. We find that requiring SO2 and
NOX controls beyond those needed to meet the requirements of
CAIR solely for purposes of further reducing Hg emissions by 2010 is
not reasonable because the incremental cost effectiveness of such a
requirement would be extraordinarily high. Furthermore, our analysis of
engineering, financial, and other factors lead us to conclude under
CAIR that a two-phased schedule was needed to allow the implementation
of as much of the controls as feasible by an early date, with a later
time for the remaining controls (see further discussion of this point
below).
a. CAIR Phase I Requirements. The CAIR-CAMR approach, which does
not impose any Phase I Hg reduction requirements beyond those required
to control SO2 and NOX emissions under Phase I of
CAIR, sets the Phase I Hg emissions cap at 38 tpy. Thus, a cap of 38
tons reflects the co-benefits level and is established as a fixed cap
in the final rule.
In the final CAIR, EPA evaluated the amounts of SO2 and
NOX emissions in upwind States that contribute significantly
to downwind fine particle (PM2.5) nonattainment, and the
amounts of NOX emissions in upwind States that contribute
significantly to downwind ozone nonattainment. That is, EPA determined
the amounts of emissions that must be eliminated to help downwind
States achieve attainment, by applying highly cost-effective control
measures to Utility Units and determining the emissions reductions that
would result.
From past experience in examining multi-pollutant emissions trading
programs for SO2 and NOX, EPA recognized that the
air pollution control retrofits that result from a program to achieve
highly cost-effective reductions are quite significant and can not be
immediately installed. Such retrofits require a large pool of
specialized labor resources, in particular, boilermakers, the
availability of which will be a major limiting factor in the amount and
timing of reductions.
EPA also recognized that the regulated industry will need to secure
large amounts of capital to meet the control requirements while
managing an already large debt load, and is facing other large capital
requirements to improve the transmission system. Furthermore, allowing
pollution control retrofits to be installed over time enables the
industry to take advantage of planned outages at power plants
(unplanned outages can lead to lost revenue and adversely impact
consumers) and to enable project management to learn from early
installations how to deal with some of the engineering challenges that
some plants/facilities/units pose, especially for the smaller units
that often present space limitations. In addition, such phased
installation of controls also minimizes any potential impact on the
power grid and its stability and reliability.
In the final CAIR, EPA finalized a two-phased schedule for
implementing the CAIR annual emission reduction requirements. The first
phase includes two separate compliance deadlines: Implementation of
NOX reductions are required by January 1, 2009 (covering
2009-2014) and that for SO2 reductions by January 1, 2010
(covering 2010-2014). The EPA based its final rule, among other things,
on its analysis of engineering, financial, and other factors that
affect the timing for installing the emission controls that would be
most cost-effective--and are, therefore, the most likely to be
adopted--for States to meet the CAIR requirements. Those air pollution
controls are primarily expected to be retrofitted FGD systems
(scrubbers) for SO2 and SCR systems for NOX on
coal-fired power plants.
The EPA's projections showed a significant number of affected
sources installing these controls. The final two-phased schedule under
CAIR allows the implementation of as much of the controls as feasible
by an early date, with a later time for the remaining controls. The EPA
has performed several analyses to verify the adequacy of the available
boilermaker labor for the installation of CAIR's Phase I controls.
These analyses were not based just on using EPA's assumptions for the
key factors affecting the boilermaker availability, but also on the
assumptions suggested by commenters for these factors to determine the
robustness of our key conclusions. See final CAIR preamble for further
discussion of this analysis and see CAMR docket for documents
supporting this analysis.
b. Utility Mercury Emission Reductions Expected as Co-Benefits From
CAIR. The final CAIR requires annual SO2 and NOX
reductions in 23 States and the District of Columbia, and also requires
ozone season NOX reductions in 25 States and the District of
Columbia. Many of the CAIR States are affected by both the annual
SO2 and NOX reduction requirements and the ozone
season NOX requirements. CAIR was designed to achieve
significant emissions reductions of SO2 and NOX
in a highly cost-effective manner to reduce the transport of fine
particles that have been found to contribute to nonattainment. EPA
analysis has found that the most efficient method to achieve the
emissions reduction targets is through a cap-and-trade system on the
power sector that States have the option of adopting. In fact, States
may choose not to participate in the optional cap-and-trade program and
may choose to obtain equivalent emissions reductions from other
sectors. However, EPA believes that a region-wide cap-and-trade system
for the power sector is the best approach for reducing emissions. The
power sector accounted for 67 percent of nationwide SO2
emissions and 22 percent of nationwide NOX emissions in
2002.
EPA expects that States will choose to implement the final CAIR
program in much the same way they chose to implement their requirements
under the NOX SIP Call. As noted above, under the
NOX SIP Call, EPA gave States ozone season NOX
reduction requirements and the option of participating in cap-and-trade
program. In the final rulemaking, EPA analysis indicated that the most
cost-efficient method to achieve reductions targets would be through a
cap-and-trade program. Each affected State, in its approved SIP, chose
to control emissions from Utility Units and to participate in the cap-
and-trade program.
Therefore, EPA anticipates that States will comply with CAIR by
controlling Utility Unit SO2 and NOX emissions.
Further, EPA anticipates that States will implement those reductions
through the cap-and-trade approach, because the power sector represents
the majority of national SO2 emissions and the majority of
stationary NOX emissions, and represents highly cost-
effective sources of reductions of SO2 and NOX
(for further discussion of cost-effectiveness, see final CAIR
preamble). EPA modeled a region-wide cap-and-trade system for the power
sector in the States covered by CAIR, and this modeling projected that
most reductions in NOX and SO2
[[Page 28619]]
would come through the installation of scrubbers, for SO2
control, and SCR, for NOX control (see Regulatory Impact
Analysis (RIA) for CAIR and CAMR in docket). Scrubbers and SCR are
proven technologies for controlling SO2 and NOX
emissions and sources have installed them to comply with the Acid Rain
trading program and the NOX SIP Call trading program. EPA's
modeling also projected that the installation of these controls would
also achieve Hg emissions reductions as a co-benefit.
EPA projections of Hg co-benefits are based on 1999 Hg ICR emission
test data and other more recent testing conducted by EPA, DOE, and
industry participants (for further discussion see Control of Emissions
from Coal-Fired Electric Utility Boilers: An Update, EPA/Office of
Research and Development, March 2005, in the docket). That emissions
testing has provided a better understanding of Hg emissions from
Utility Units and their capture in pollution control devices. Mercury
speciates into three basic forms, ionic, elemental, and particulate
(particulate represents a small portion of total emissions). Ionic, or
non-elemental, Hg compounds are the most important from a near-field
deposition stand-point. In general, ionic Hg compounds are more readily
controlled (because they tend to be water soluble) than is elemental Hg
and the presence of chlorine compounds (which tend to be higher for
bituminous coals) results in increased ionic Hg. Overall the 1999 Hg
ICR data revealed higher levels of Hg capture for bituminous coal-fired
plants as compared to subbituminous and lignite coal-fired plants and a
significant capture of ionic Hg in wet-FGD scrubbers. Additional Hg
testing indicates that for bituminous coals SCR has the ability to
convert elemental Hg to ionic Hg and, thus allow easier capture in a
wet-FGD scrubber. This understanding of Hg capture was incorporated
into EPA modeling assumptions and is the basis for our projections of
Hg co-benefits from installation of scrubbers and SCR under CAIR.
Given the history of the Acid Rain and NOX SIP Call
trading programs, EPA anticipates that reductions in SO2
emissions will begin to occur before 2010 (limited to a degree by the
time and resources needed to install control technologies) because of
the ability to bank SO2 emission allowances. Companies have
an incentive to achieve greater and faster SO2 reductions
than needed to meet the current Acid Rain cap because the excess
allowances they generate can be ``banked'' and either later sold on the
market or used to demonstrate compliance in 2010 and beyond at the
facility that generated the excess allowances. Based on the analysis of
CAIR, EPA's modeling projects that Hg emissions would be 38.0 tons (12
tons of non-elemental Hg) in 2010, 34.4 tons in 2015 (10 tons of non-
elemental Hg), and 34.0 tons in 2020 (9 tons of non-elemental Hg),
about a 20 and 30 percent reduction (in 2010 and 2015, respectively)
from a 1999 baseline of 48 tons. With respect to oxidized Hg, emissions
in 2020 are 7.9 tons compared to 20.6 tons in 2001. This 62 percent
drop in oxidized Hg emissions is particularly important because this
species of Hg deposits more readily. For further discussion of EPA
modeling results and projected emissions see chapter 8 of the RIA.
c. Availability of Hg Technology. Additionally, EPA is setting a Hg
emissions cap of 15 tpy in 2018 from coal-fired Utility Units. This cap
reflects a level of Hg emissions reductions that exceeds the level that
would be achieved solely as a co-benefit of controlling SO2
and NOX under CAIR. We conclude that this approach is
warranted because we find Hg-specific air pollution control
technologies such as ACI are adequately demonstrated for use
sufficiently before 2018 to allow for their deployment across the field
of units to comply with the Phase II cap in 2018. This conclusion
relies on the fact that the current-day pilot scale ACI projects at
power plants should yield information that ought to be usable in
implementing similar pilot scale projects at other facilities. Data
from all of these pilot studies ultimately should allow companies to
design full scale applications that should provide reasonable assurance
that emissions limitations can be reliably achieved over extended
compliance periods. We do not believe that such full scale technologies
can be developed and widely implemented within the next 5 years;
however, it is reasonable to assume that this can be accomplished over
the next 13 years.
d. CAMR Reductions Requirements in 2018. As discussed above, EPA is
setting a cap of 15 tons in 2018 for coal-fired Utility Units. EPA
projected future Hg emissions from the power generation sector using
the Integrated Planning Model (IPM). The EPA uses IPM to analyze the
projected impact of environmental policies on the electric power sector
in the 48 contiguous States and the District of Columbia. IPM is a
multi-regional, dynamic, deterministic linear programming model of the
U.S. electric power sector. The EPA used IPM to project both the
national level and the unit level of utility unit Hg emissions under
different control scenarios. The EPA also used IPM to project the costs
of those controls.
In these IPM runs, EPA assumed that States would implement the Hg
requirements through the Hg cap-and-trade program that EPA is
establishing in the final rule. The cap-and-trade program is
implemented in two phases, with a hard cap of 38 tons in 2010 (set at
the co-benefits reduction under CAIR) and 15 tons in 2018. EPA modeling
of CAA section 111 projects banking of allowances due to excess Hg
reductions in the 2010 to 2017 timeframe for compliance with the cap in
2018 and beyond timeframe. A cap-and-trade program assures that those
reductions will be achieved with the least cost. For that reason, EPA
believes it reasonable to assume that States will adopt the program
even though they are not required to do so. See 69 FR 4652, 4700-4703
for a detailed discussion of the benefits of the cap-and-trade
approach.
As discussed above, under the CAIR scenario modeled by EPA,
SO2 and NOX emission reductions (and Hg co-
benefit reductions) are projected to result from the installation of
additional FGD and additional SCR units on existing coal-fired
generation capacity. Under the CAMR scenario modeled by EPA, units are
projected to install SCR and scrubbers to meet their SO2 and
NOX requirements and take additional steps to address the
remaining Hg reduction requirements under CAA section 111, including
adding Hg-specific control technologies (model applies ACI), additional
scrubbers and SCR, dispatch changes, and coal switching. Many of these
reductions are projected to result from large units installing controls
and selling excess allowances. Under the cap-and-trade approach we are
projecting that Hg reductions result from units that are most cost
effective to control, which enables those units that are not cost
effective to install controls to use other approaches for compliance
including buying allowances, switching fuels, or making dispatch
changes.
Based on the analysis of CAMR, EPA's modeling projects that Hg
emissions would be 31.3 tons in 2010, 27.9 tons in 2015, and 24.3 tons
in 2020, about a 35 percent reduction in 2010, about 42 percent
reduction in 2015, and about 50 percent reduction in 2020 from a 1999
baseline of 48 tons. For further discussion of EPA modeling results and
projected emissions see chapter 8 of the RIA. EPA is not requiring
further reductions by 2015, beyond the CAIR Phase I cap co-benefits,
and, therefore, we are not adjusting Hg allowances downward beginning
in 2015, rather
[[Page 28620]]
adjusting allowances in 2018. EPA maintains that it is not necessary
for the 2015 Hg cap to mirror the Hg co-benefits achieved in CAIR Phase
II cap because: (1) These co-benefits would result automatically from
the need to meet SO2 and NOX caps; the market
will assure that the Hg reductions will occur; and (2) in 2018, the
lower cap takes into account the reduced Hg emissions resulting from
CAIR Phase II implementation. As we can see from the CAMR analysis,
2015 Hg emissions are projected to be substantially below the co-
benefits projections under CAIR (34 tons in 2015). Thus, EPA maintains
that it is not necessary to have the 2015 Hg cap mirror the Hg co-
benefits achieved in CAIR Phase II cap because the 2018 cap ensures
those reductions.
As discussed in detail in the separate Federal Register notice (70
FR 15994; March 29, 2005) announcing EPA's revision of its December
2000 regulatory determination and removing coal- and oil-fired Utility
Units from the CAA section 112(c) list, EPA believes that the term
``standard of performance'' as used in CAA section 111 can include
market-based programs such a cap-and-trade program. The EPA also
believes that in the context of a cap-and-trade program, the phrase
``best system of emission reduction which (taking into account the cost
of achieving such reduction and any non-air quality health and
environmental impacts and energy requirements) the Administrator
determines has been adequately demonstrated'' refers to the combination
of the cap-and-trade mechanism and the technology needed to achieve the
chosen cap level. The EPA further believes that a particular technology
can be adequately demonstrated to achieve a specified level of
emissions reduction at one point in time, but, for a number of possible
reasons, not be capable of achieving that level of reductions on a
broad scale until a later point in time. For example, EPA might
conclude that a particular technology is capable of achieving
reductions in the emission of specified pollutants in the range of 90
to 95 percent, while at the same time concluding that the technology is
not currently commercially available and, therefore, not susceptible to
widespread use. As a result, it would be inappropriate for EPA to
establish a cap based on the use of such controls and require
compliance with that cap in the near term, but reasonable to establish
a cap on that basis and require compliance with that cap at a later
point in time when the necessary technology becomes widely available.
CAA section 111 authorizes EPA to promulgate standards of
performance based on systems of emission reduction that have been
``adequately demonstrated.'' Traditionally EPA has set its section 111
standards based on a determination that particular control technologies
are ``adequately demonstrated.'' In the final rule, EPA has determined
that the technologies necessary to achieve the emission cap limits for
2010 have been adequately demonstrated, and that the technologies
necessary to achieve the 2018 caps have been adequately demonstrated to
be available to achieve compliance with those limits by 2018.\5\
---------------------------------------------------------------------------
\5\ Even assuming, arguendo, that the term ``standard of
performance'' prohibited an emissions cap and allowance trading
program, the regulatory approach being employed in the final rule
and the technologies on which EPA has based its cap calculations are
consistent with and permitted by CAA section 111.
---------------------------------------------------------------------------
In Portland Cement Association v. EPA (486 F.2d 375) (DC Cir.
1973), the Court rejected the argument that the words ``adequately
demonstrated'' in CAA section 111 meant that the relevant technology
already must be in existence and that plants now in existence be able
to presently meet the proposed standards. Rather, the CAA's requirement
that the degree of emission limitation be ``adequately demonstrated''
means that a plant now in existence must be able to meet the presently-
effective standards for existing units, but that insofar as new plants
and future requirements are concerned, section 111 authorizes EPA to
``look toward what may fairly be projected for the regulated future,
rather than the state-of-the-art at present.'' The court said:
The Administrator may make a projection based on existing
technology, though that projection is subject to the restraints of
reasonableness and cannot be based on ``crystal ball'' inquiry. 478
F.2d at 629. As there, the question of availability is partially
dependent on ``lead time,'' the time in which the technology will
have to be available. Since the standards here put into effect will
control new plants immediately, as opposed to one or two years in
the future, the latitude of projection is correspondingly narrowed.
If actual tests are not relied on, but instead a prediction is made,
``its validity as applied to this case rests on the reliability of
[the] prediction and the nature of [the] assumptions.'' (citation
omitted)
See also Lignite Energy Council v. EPA, 198 F.3d 930 (DC Cir. 1999)
(section 111 ``looks toward what may fairly be projected for the
regulated future, rather than the state of the art at present'')
(quoting Portland Cement). These cases address CAA section 111(b)
standards for new sources, where achievement of the standards is
mandated on a short-term basis. We believe that EPA standards set under
the authority of CAA section 111(d), where the compliance deadlines are
not so immediate, afford EPA significant flexibility, commensurate with
the amount of lead-time being given to affected sources. The cases make
clear that while a determination about a technology or performance
standard's achievability may not be based on ``mere speculation or
conjecture,'' a technology or standard that may not necessarily be
considered ``adequately demonstrated'' at present nonetheless can be
considered ``adequately demonstrated'' for a compliance date in the
future. We have explained in today's action why we believe both the
2010 and 2018 emissions caps can be met. Since we believe that Hg-
specific technologies capable of meeting the requirements of the 2018
emission limits will be available for broad commercial deployment by
2018, we believe those technologies are ``adequately demonstrated'' for
the 2018 emission caps.
Here, EPA has concluded that Hg-specific controls, such as ACI,
have been adequately demonstrated as being effective in substantially
reducing Hg emissions, but are not currently available for commercial
application on a broad scale. As a result, EPA cannot establish a Hg
emission cap based on the widespread use of Hg-specific controls and
require compliance with that cap in the near term. The EPA has,
therefore, set the level of the 2010 cap on Hg emissions on the basis
of the reductions in Hg emissions achievable as co-benefits of efforts
to reduce emissions of SO2 and NOX in accordance
with CAIR. The EPA believes that establishing the Phase I cap on the
basis of these co-benefits fulfills its obligation to set a standard of
performance which is both based on the best system of emissions
reductions that has been adequately demonstrated and achievable in the
designated timeframe.
As stated above, EPA has determined that Hg-specific controls have
been adequately demonstrated as being effective in substantially
reducing Hg emissions, but that such controls are not currently
available for commercial application on a broad scale and, therefore,
cannot serve as the basis for the 2010 Hg emissions cap. EPA believes,
however, based on currently available information (ORD revised white
paper ``Control of Mercury Emissions from Coal Fired Electric Utility
Boilers: An Update,'' and DOE white paper ``Mercury Control
Technologies,'' both of which may be found in the OAR-2002-0056), that
such controls will be commercially
[[Page 28621]]
available sometime after 2010 and can be installed and operational on a
nation-wide basis by 2018. The EPA has, therefore, established a Phase
II Hg emissions cap based on the reductions in Hg emissions founded in
the CAIR program and reductions that can be reasonably obtained through
the use of Hg-specific controls. This cap is effective in 2018. That
is, the 2018 cap is based on the level of Hg emissions reductions that
will be achievable by the combined use of co-benefit (CAIR) and Hg-
specific controls. The Phase II cap is timed such that these
technologies can be installed and operational on a nationwide basis,
i.e., until the technology becomes generally available.
The need to achieve Hg reductions beyond those secured through the
CAIR co-benefits program are wholly consistent with the Agency's
mission to leverage the monies spent domestically on global reductions
of anthropogenic Hg emissions. As explained elsewhere in this preamble
and the supporting docket, in order to significantly impact nationwide
Hg deposition and, thus, human exposure to methylmercury (MeHg), the
U.S. must be a leader in incentivizing global Hg emissions reductions.
To that end, the Phase II cap serves as a driver for continued research
and development of Hg-specific control technologies, while providing a
global market for the application of such equipment, which ultimately
may serve to significantly reduce the global pool of Hg emissions. The
timing of the Phase II cap is such that new technologies can be
developed, installed, demonstrated and commercially deployed with
little impact to the stability of the power grid.
EPA is today finalizing a NSPS for Hg for coal-fired Utility Units
under CAA section 111 in lieu of a MACT standard for Hg. As set forth
in greater detail below and in the related final rule, the Agency has
determined that it is not ``necessary and appropriate'' to establish a
MACT standard under CAA section 112 for electric utility steam
generating units since utility HAP emissions remaining after
implementation of other requirements of the CAA do not pose hazards to
public health. For this reason, it is not necessary for the Agency to
undertake any further analysis of Hg emissions from existing units in
order to establish a MACT floor, as this information is irrelevant to
the development of the NSPS. Nor is it necessary to conduct an
additional cost-benefit analysis of potential MACT standards since the
Agency has concluded, as a matter of law and policy, that a MACT
standard is not appropriate or necessary.
e. Cost-effectiveness of the Hg Cap in 2018. As discussed above
under CAMR, EPA projected future Hg emissions and the cost of those
controls from the power generation sector using the IPM. In these IPM
runs, EPA assumed that States would implement the Hg requirements
through the Hg cap-and-trade program that EPA is establishing in the
final rule.
The 15-ton cap in 2018 is supported by cost considerations and the
sophisticated economic modeling completed in support of the CAIR and
CAMR regulations. These cost considerations include establishing a cap
level that does not have significant impacts on energy supply and the
cost of energy to the consumer. This modeling shows that the 15-ton
Phase II cap will, in fact, require Hg-specific controls to be
installed on certain Utility Units; however, such controls should not
have any significant impact on power availability, reliability, or
pricing to consumers. Moreover, our models predict that a 15-ton cap
would not cause any significant shift in the fuels currently utilized
by power plants or in the source of these fuels. For further discussion
of EPA modeling results and projected costs see Chapter 8 of the RIA.
3. State and Indian Country Emissions Reductions Requirements
The EPA below also outlines a method for apportioning the nation-
wide budget to individual States and to coal-fired Utility Units
located in Indian country. The EPA maintains that the emission budget
provides an efficient method for achieving necessary reductions in Hg
emissions (as described in earlier sections of this preamble), while
providing substantial flexibility in implementing the program.
a. Geographic Scope of Trading Program. The final rule will apply
to all coal-fired Utility Units located in all 50 States of the U.S.,
as well as those located in Indian country. (As used herein, the term
``Indian country'' generally refers to all areas within Indian
reservations, dependent Indian communities, and Indian allotments. The
EPA or, in appropriate circumstances, an individual Tribe generally
will be responsible for implementing a trading program in Indian
country.) As discussed further below, each State has been assigned a
Statewide emissions budget for Hg. Each of these States must submit a
State Plan revision detailing the controls that will be implemented to
meet its specified budget for reductions from coal-fired Utility Units.
States are not required to adopt and implement the proposed emission
trading rule, but they are required to be in compliance with their
statewide Hg emission budget. Should some States choose to achieve the
mandated reductions by using an approach other than the proposed
emissions trading rule, the geographic scope of the trading program
would not be nationwide. Mercury emission budgets have also been
assigned to coal-fired Utility Units that will be affected by the final
rule which are located in Indian country. The EPA generally will
implement the emission trading rule for coal-fired Utility Units
located in Indian country unless a Tribe seeks and obtains Treatment-
as-a-State (TAS) status and submits a Tribal implementation plan (TIP)
to implement the allocated Hg emissions budget. Eligible Tribes which
choose to do so will be responsible for submitting a TIP analogous to
the State plans discussed throughout this preamble, and, like States,
can chose to adopt the Model Cap-and-Trade Rule described elsewhere in
this action.
b. State and Indian Country Emission Budgets. Each of the States
and the District of Columbia covered by the final rule has been
assigned a State emissions budget for Hg. A Hg emissions budget has
also been assigned to each coal-fired Utility Unit located in Indian
country. As discussed in detail below, these budgets were developed by
totaling unit-level emissions reductions requirements for coal-fired
electricity generating devices. States have the flexibility to meet
these State budgets by participating in a trading program or
establishing another methodology for Hg emissions reductions from coal-
fired electric generating units, as discussed elsewhere in this action.
States have the ability to require reductions beyond those required by
the State budget. Tribes which choose to seek and obtain TAS status for
that purpose, have the same flexibility in developing an appropriate
TIP. The State Hg emission budgets are a permanent cap regardless of
growth in the electric sector and, therefore, States have the
responsibility of incorporating new units in their Hg emission budgets.
Similarly, the Hg emission budgets allocated to coal-fired Utility
Units located in Indian country act as a permanent cap and EPA or a
Tribe which has obtained TAS status and is implementing an approved TIP
has responsibility for incorporating new units into the allocated Hg
emission budget.
As proposed in the NPR and SNPR, EPA is finalizing a formula for
determining the total amount of emissions for the Budget Trading
Program for each specific State or coal-fired Utility Unit located in
Indian country using that same mechanism,
[[Page 28622]]
finalizing the amount of emissions for the Program within each State
for 2010 and 2018. That formula is the sum of the weighted shares for
each affected Utility Unit in the State or Indian country, based on the
proportionate share of their baseline heat input, adjusted to reflect
the ranks of coal combusted by the unit during the baseline period, to
total heat input of all affected units. As discussed further below, EPA
is finalizing adjustment factors of 1 for bituminous, 1.25 for
subbituminous, and 3 for lignite coals.
As discussed elsewhere in this preamble, new sources will comply
with NSPS for Hg. In addition, as proposed in the NPR and SNPR, new
sources will be covered under the Hg cap of the trading program, and
will be required to hold allowances equal to their emissions. As
discussed under the model cap-and-trade program, EPA is also finalizing
the allocation methodology in the model cap-and-trade program a
mechanism whereby these new sources do not receive an adjustment to
their allocated share of the allowances (that reflects the rank of coal
combusted).
c. Rationale for Unit-level Allowances. Different ranks of coal may
achieve different Hg reductions depending on the control equipment
installed at the unit. In order to develop State and Indian country
emissions budgets from unit allocations, EPA proposed that allowances
would be distributed to States based on their share of total heat
input. These allocations were then adjusted to reflect the concern that
the installation of PM, NOX, and SO2 control
equipment on different coal ranks results in different Hg removal.
In the NPR and SNPR, for purposes of this hypothetical allocation
of allowances, EPA proposed that 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.
Alternatively, for purposes of this hypothetical calculation of State
budgets, EPA took comment on using adjustment factors based on the MACT
emission rates proposed in the NPR and the proportionate share of their
baseline heat input to total heat input of all affected units.
Several commenters supported the proposed adjustment factors of 1
for bituminous, 1.25 for subbituminous, and 3 for lignite coals. Many
commenters supported revisions to the adjustment factors, including a
factor of 1.5 for subbituminous. Several other commenters supported the
use of no adjustment factors. Although supporting the use of
multipliers for the coal ranks, some commenters argued that EPA should
provide more scientific basis for the adjustment factors and
recommended at minimum using adjustment factors based on the MACT
approach.
For the final rule, EPA is finalizing adjustment factors of 1 for
bituminous, 1.25 for subbituminous, and 3 for lignite coals based on
the expectation that Hg in the coal ranks reacts differently to
NOX and SO2 control equipment and that the heat
input of the different coal ranks varies. The conclusion that Hg in
each of the coals reacts differently to NOX and
SO2 control equipment was based on information collected in
the ICR as well as more recent data collected by EPA, DOE, and industry
sources. This information, which was collected from units of various
coal ranks and control equipment configuration, indicated differing
levels of Hg removal. The test data indicated that installation of PM,
NOX, and SO2 controls on plants burning
bituminous coals resulted in greater Hg reduction on average than
plants burning subbituminous coals or lignite coals. Likewise, the test
data indicated that installation of PM, NOX, and
SO2 controls on plants burning subbituminous coals resulted
in somewhat greater Hg removal than plants burning lignite coals. On
average, units burning lignite coal showed the least Hg removal of the
three coal ranks. Further discussion of these adjustment factors can be
found in the docket (see ``Technical Support Document for the Clean Air
Mercury Rule Notice of Final Rulemaking, State, and Indian Country
Emissions Budgets,'' EPA, March 2005).
These adjustment factors are considered to be reasonable based on
the test data currently available. Although, we realize that these
factors do not in all cases accurately predict relative rates of Hg
emissions from Utility Units with NOX and SO2
controls, the values we have assigned to the factors will succeed in
equitably distributing allowances to the States and Tribes on the basis
of the affected industry within their borders. As discussed in the
model cap-and-trade program, EPA is finalizing under the example
allocation methodology that allocations by States to new sources will
not be adjusted by coal type.
d. Distribution of State and Indian Country Budgets. The trading
program establishes a cap on Hg emissions for affected electric
generating units of 38 tpy starting in 2010 and 15 tpy in 2018. The
unit-level emission allocations are the basis for establishing State
and Indian country emission budgets with the State budgets equaling the
total of the individual unit emission limits in a given State (see
Table 1 of this preamble). Similarly, sufficient allowances have been
allocated to coal-fired Utility Units located in Indian country to
cover the individual unit emission limits for those units. States also
have the flexibility to not participate in the trading program or
require more stringent Hg emissions reductions. States that do not
participate in the trading program can establish their own methodology
for meeting State Hg budgets by obtaining reductions from affected
Utility Units. As proposed in the NPR and SNPR, EPA is finalizing the
requirement that new coal-fired Utility Units will be subject to the
State Hg emission cap. State budgets remain the same after the
inclusion of new units and States have the responsibility of addressing
new units in their respective emission budgets. Similarly, the budgets
for coal-fired Utility Units located in Indian country will remain the
same after the inclusion of new units and EPA or a Tribe with an
approved TIP, as appropriate, has responsibility for addressing new
units in the respective emission budget.
EPA received comments from Tribes noting that only States currently
receive allowances under the proposal, despite unit allocations being
made to sources located in Indian country, and requesting that Tribes
be accommodated into the cap-and-trade program. Because under CAA
authority eligible Tribes may be treated in the same manner as States
for CAA programs for reservations and for other areas within their
jurisdiction, EPA agrees with the commenters that these Tribal sources
need to be included in the cap-and-trade program, and the final CAMR
establishes budgets for existing coal-fired sources located in Indian
country.
In the final rule, EPA is establishing a Tribal budget for three
existing coal-fired Utility Units in Indian country. These are Navajo
Generating Station (Salt River Project; Page, AZ), Bonanza Power Plant
(Deseret Generation and Transmission Cooperative; Vernal, UT), and Four
Corners Power Plant (Salt River Project/Arizona Public Service;
Fruitland, NM). Navajo Generating Station and Four Corners Power Plant
are on lands belonging to Navajo Nation, and Bonanza Power Plant is
located on the Uintah and Ouray Reservation of the Ute Indian Tribe.
Therefore, in addition to the 50 State budgets, the final rule also
contains a budget for these Utility Units. The budget for units located
in Indian country was calculated using the
[[Page 28623]]
same methodology as State budgets. In the proposed rule, these three
units in Indian country were erroneously included in the State budgets
for Arizona, Utah, and New Mexico. The emissions budgets for the final
rule for Arizona, Utah, and New Mexico are adjusted to reflect the
movement of these sources to the Indian country emission budget.
For areas of Indian country that do not currently have any coal-
fired electricity generation, EPA intends to address any future planned
construction of coal-fired Utility Units in those areas on a case-by-
case basis, by working with the relevant Tribal government to regulate
the Utility Units through either a TIP, if an eligible Tribe chooses to
submit one, or Federal implementation plan (FIP). This is the same
approach that is taken in the CAIR. EPA does not believe there is
sufficient information to design allocation provisions for new
generation which locates in Indian country at this time. Therefore,
rather than create a Federal allowance set-aside for Tribes, the EPA
will work with Tribes and potentially affected States to address
concerns regarding the equity of allowance allocations on a case-by-
case basis as the need arises. The EPA may choose to revisit this issue
through a separate rulemaking in the future.
In the SNPR, because three States and the District of Columbia have
no coal-fired Utility Units, EPA proposed Hg emission budgets of zero
tons for three States (Idaho, Rhode Island, and Vermont) and the
District of Columbia. EPA did not receive adverse comments from these
States on their proposed budgets and is finalizing Hg emission budgets
of zero tons for three States (Idaho, Rhode Island, and Vermont) and
the District of Columbia. If these States or the District of Columbia
participate in the CAMR trading program, new coal-fired Utility Units
will be required to hold allowances equal to their emissions. As
participants in the cap-and-trade program, these sources could buy
allowances and meet their requirements. This is similar to situation
that new units face under the existing Acid Rain Program. The final
State and Indian country Hg emission budgets are presented in Table 1
of this preamble.
Table 1.--State Hg Emission Budgets
------------------------------------------------------------------------
Budget (tons)
---------------------------------
State 2018 and
2010-2017 thereafter
------------------------------------------------------------------------
Alaska................................ 0.005 0.002
Alabama............................... 1.289 0.509
Arkansas.............................. 0.516 0.204
Arizona............................... 0.454 0.179
California............................ 0.041 0.016
Colorado.............................. 0.706 0.279
Connecticut........................... 0.053 0.021
Delaware.............................. 0.072 0.028
District of Columbia.................. 0 0
Florida............................... 1.233 0.487
Georgia............................... 1.227 0.484
Hawaii................................ 0.024 0.009
Idaho................................. 0 0
Iowa.................................. 0.727 0.287
Illinois.............................. 1.594 0.629
Indiana............................... 2.098 0.828
Kansas................................ 0.723 0.285
Kentucky.............................. 1.525 0.602
Louisiana............................. 0.601 0.237
Massachusetts......................... 0.172 0.068
Maryland.............................. 0.49 0.193
Maine................................. 0.001 0.001
Michigan.............................. 1.303 0.514
Minnesota............................. 0.695 0.274
Missouri.............................. 1.393 0.55
Mississippi........................... 0.291 0.115
Montana............................... 0.378 0.149
Navajo Nation Indian Country.......... 0.601 0.237
North Carolina........................ 1.133 0.447
North Dakota.......................... 1.564 0.617
Nebraska.............................. 0.421 0.166
New Hampshire......................... 0.063 0.025
New Jersey............................ 0.153 0.06
New Mexico............................ 0.299 0.118
Nevada................................ 0.285 0.112
New York.............................. 0.393 0.155
Ohio.................................. 2.057 0.812
Oklahoma.............................. 0.721 0.285
Oregon................................ 0.076 0.03
Pennsylvania.......................... 1.78 0.702
Rhode Island.......................... 0 0
South Carolina........................ 0.58 0.229
South Dakota.......................... 0.072 0.029
Tennessee............................. 0.944 0.373
Texas................................. 4.657 1.838
Utah.................................. 0.506 0.2
[[Page 28624]]
Ute Indian Tribe Reservation Indian 0.06 0.024
Country..............................
Virginia.............................. 0.592 0.234
Vermont............................... 0 0
Washington............................ 0.198 0.078
Wisconsin............................. 0.89 0.351
West Virginia......................... 1.394 0.55
Wyoming............................... 0.952 0.376
------------------------------------------------------------------------
As required by CAA section 111(a)(1), EPA has considered the cost
of achieving the reductions in Hg emissions mandated by the section
111(d) requirements for existing Utility Units, the non-air quality
health and environmental impacts arising from the implementation of
those requirements and the energy requirements associated with those
requirements and determined that they are all reasonable. (The costs of
complying with CAMR as a whole are discussed briefly below, and in more
detail in the two air dockets for the CAMR rule: Docket ID No. OAR-
2002-0056 and Docket ID No. A-92-55. The non-air quality health and
environmental impacts arising from the implementation of CAMR, as well
as the energy requirements associated with CAMR, are discussed briefly
below, and in more detail in Docket ID No. OAR-2002-0056 and Docket ID
No. A-92-55.)
E. CAMR Model Cap-and-Trade Program
1. What Is the Overall Structure of the Model Hg Cap-and-Trade Program?
EPA is finalizing model rules for the CAMR Hg trading program that
States can use to meet the emission reduction requirements in the CAMR.
These rules are designed to be referenced by States in State
rulemaking. State use of the model cap-and-trade rules helps to ensure
consistency between the State programs, which is necessary for the
market aspects of the trading program to function properly. Although
not as effective as a legislated program such as the President's Clear
Skies legislation, this does allow the CAMR program to build on the
successful Acid Rain Program. Consistency in the CAMR requirements from
State-to-State benefits the affected sources, as well as EPA which
administers the program on behalf of States.
This section focuses on the structure which adds a model rule for
the CAMR in 40 CFR part 60, subpart HHHH. Commenters (who supported the
cap-an-trade approach) generally supported the proposed structure of
the model rule. The final rule adopts the basic structure of this model
rule. Later sections of the rule discuss specific aspects of the model
rule that have been modified or maintained in response to comment.
The model rules rely on the detailed unit-level emissions
monitoring and reporting procedures of 40 CFR part 75 and consistent
allowance management practices. (Note that full CAMR-related State Plan
requirements, i.e., 40 CFR part 60, are discussed elsewhere in this
action.) Additionally, a discussion of the final revisions to parts 72
through 77 in order to, among other things, facilitate the interaction
of the title IV Acid Rain Program's SO2 cap-and-trade
provisions and those of the CAMR Hg trading program is provided
elsewhere in this action.
a. Road Map of Model Cap-and-trade Rule. The following is a brief
``road map'' to the final CAMR cap-and-trade program and is provided as
a convenience to the reader. Please refer to the detailed discussions
of the CAMR programmatic elements throughout the final rule for further
information on each aspect.
State Participation:
States may elect to participate in an EPA-managed cap-and-
trade program for coal-fired Utility Units greater than 25 MW. To
participate, a State must adopt the model cap-and-trade rules finalized
in this section of the final rule with flexibility to modify sections
regarding source Hg allocations.
For States that elect not to participate in an EPA-managed
cap-and-trade program, their respective State Hg budgets will serve as
a firm cap.
Emission Allowances:
The CAMR cap-and-trade program will rely upon CAMR annual
Hg allowances allocated by the States.
Allocation of Allowances to Sources:
Hg allowances will be allocated based upon the States
chosen allocation methodology. EPA's model Hg rule has provided an
example allocation, complete with regulatory text, that may be used by
States or replaced by text that implements a States alternative
allocation methodology.
Emission Monitoring and Reporting by Sources:
Sources monitor and report their emissions using 40 CFR
part 75.
Source information management, emissions data reporting,
and allowance trading is done through on-line systems similar to those
currently used for the Acid Rain SO2 and NOX SIP
Call programs.
Compliance and Penalties:
For the Hg cap-and-trade program, any source found to have
excess emissions must: (1) Surrender allowances sufficient to offset
the excess emissions; and, (2) surrender allowances from the next
control period equal to three times the excess emissions.
b. Comments Regarding the Use of a Cap-and-Trade Approach and the
Proposed Structure. As discussed elsewhere in this action, many
commenters did not support the cap-and-trade approach. For the many
commenters, however, that did support the cap-and-trade approach, they
also supported EPA's overall framework of the model rule to achieve the
mandated emissions reductions. Many commenters supported States having
the flexibility to achieve emissions reductions however they chose,
including developing their own cap-and-trade program or choosing not to
participate. Other commenters did not support giving the States
flexibility to participate in the program and supported requiring their
participation, including imposing a uniform national allocation scheme.
(Note that comments on specific mechanisms within the cap-and-trade
program are discussed in the topic-specific sections that follow.)
[[Page 28625]]
2. What is the Process for States to Adopt the Model Cap-and-Trade
Program, and How Will it Interact With Existing Programs?
a. Adopting the Hg Model Cap-and-Trade Program. States may choose
to participate in the EPA-administered cap-and-trade program, which is
a fully approvable control strategy for achieving all of the emissions
reductions required under the final rule in a more cost-effective
manner than other control strategies. States may simply reference the
model rules in their State rules and, thereby, comply with the
requirements for Statewide budget demonstrations detailed elsewhere in
this action. Specifically, States can adopt the Hg cap-and-trade
program whether by incorporating by reference the CAMR cap-and-trade
rule (40 CFR part 60, subpart HHHH) or codifying the provisions of the
CAMR cap-and-trade rule, in order to participate in the EPA-
administered Hg cap-and-trade program.
As proposed, EPA is requiring States that wish to participate in
the EPA-managed cap-and-trade program to use the model rule to ensure
that all participating sources, regardless of which State they are
located, are subject to the same trading and allowance holding
requirements. Further, requiring States to use the complete model rule
provides for accurate, certain, and consistent quantification of
emissions. Because emissions quantification is the basis for applying
the emissions authorization provided by each allowance and emissions
authorizations (in the form of allowances) are the valuable commodity
traded in the market, the emissions quantification requirements of the
model rule are necessary to maintain the integrity of the cap-and-trade
approach of the program and therefore to ensure that the environmental
goals of the program are met.
b. Flexibility in Adopting Hg Model Cap-and-trade Rule. It is
important to have consistency on a State-to-State basis with the basic
requirements of the cap-and-trade approach when implementing a multi-
State cap-and-trade program. Such consistency ensures the: Preservation
of the integrity of the cap-and-trade approach so that the required
emissions reductions are achieved; smooth and efficient operation of
the trading market and infrastructure across all States so that
compliance and administrative costs are minimized; and equitable
treatment of owners and operators of regulated sources. However, EPA
believes that some differences are possible without jeopardizing the
environmental and other goals of the program. Therefore, the final rule
allows States to modify the model rule language to best suit their
unique circumstances with regard to allocation methodologies.
States may develop their own Hg allocations methodologies, provided
allocation information is submitted to EPA in the required timeframe.
(Unit-level allocations and the related comments are discussed in
greater detail elsewhere in this action. This includes a discussion of
the provisions establishing the advance notice States must provide for
unit-by-unit allocations.)
3. What Sources Are Affected Under the Model Cap-and-Trade Rule?
In the January 2004 NPR, EPA proposed a method for developing
budgets that assumed reductions only from coal-fired Utility Units.
Utility Units were defined as: Coal-fired, non-cogeneration electric
utility steam generating units serving a generator with a nameplate
capacity of greater than 25 MWe; and coal-fired cogeneration electric
utility steam generating units meeting certain criteria (referred to as
the ``one-third potential electric output capacity criteria''). In the
SNPR, EPA proposed a model cap-and-trade rule that applied to the same
categories of sources. We are finalizing the nameplate capacity cut-off
that we proposed in the NPR for developing budgets and that we proposed
in the SNPR for the applicability of the model trading rules. We are
also finalizing the ``fossil fuel-fired'' definition and the one-third
electric output capacity criteria that were proposed. The actual rule
language in the SNPR describing the sources to which the model rules
apply is being slightly revised to be clearer in response to some
comments that the proposed language was not clear.
a. 25 MW Cut-off. EPA is retaining the 25 MW cut-off for Utility
Units for budget and model rule purposes. EPA believes it is reasonable
to assume no further control of air emissions from smaller Utility
Units. Available air emissions data indicate that the collective
emissions from small Utility Units are relatively small and that
further regulating their emissions would be burdensome, to both the
regulated community and regulators, given the relatively large number
of such units. For example, Hg emissions from Utility Units of 25 MWe
or less in the U.S. represent about 1 percent of Hg emissions from
Utility Units, respectively. Consequently, EPA believes that
administrative actions to control this large group with small emissions
would be inordinate and, thus does not believe these small units should
be included. This approach of using a 25 MWe cut-off for Utility Units
is consistent with existing SO2 and NOX cap-and-
trade programs such as the NOX SIP Call (where existing and
new Utility Units at or under this cut-off are, for similar reasons,
not required to be included) and the Acid Rain Program (where this cut-
off is applied to existing units and to new units combusting clean
fuel).
b. Definition of Coal-fired. EPA is finalizing the proposed
definition of coal-fired, i.e., where any amount of coal or coal-
derived fuel is used at any time. This is similar to the definition
that is used in the Acid Rain Program to identify coal-fired units. EPA
did not receive comments on this definition except that one commenter
stated that coal refuse-fired plants should not be subject to CAMR. EPA
points out that coal refuse is already subject to other Utility Unit
programs, such as the Acid Rain program, the NSPS program (40 CFR part
60, subpart Da), and the CAIR program. Consequently, EPA rejects the
commenter's request to not be included in the CAMR program.
c. Exemption for Cogeneration Units. As proposed, EPA is finalizing
an exemption from the model cap-and-trade program for cogeneration
units, i.e., units having equipment used to produce electricity and
useful thermal energy for industrial, commercial, heating, or cooling
purposes through sequential use of energy and meeting certain operating
standards (discussed below). EPA is adopting, with some clarifications,
the proposed definition of cogeneration unit and the proposed criteria
for determining which cogeneration units qualify for the exemption from
the model cap-and-trade programs.
(1) One-third Potential Electric Output Capacity. EPA is finalizing
the one-third potential electric output capacity criteria in the NPR
and SNPR with some clarifications. Under the final rule, the following
cogeneration units are Utility Units: Any cogeneration unit serving a
generator with a nameplate capacity of greater than 25 MWe and
supplying in any calendar year more than one-third of the unit's
potential electric output capacity or 219,000 MWH, which ever is
greater, to any utility power distribution system for sale. These
criteria are similar to the definition in the proposals with the
clarification that the criteria be applied on an annual basis. These
criteria are the same used in the CAIR and are similar to those used in
the Acid Rain
[[Page 28626]]
Program to determine whether a cogeneration unit is a Utility Unit and
the NOX SIP Call to determine whether a cogeneration unit is
an Utility Unit or a non-Utility Unit. The primary difference between
the proposed criteria and the one-third potential electric criteria for
the Acid Rain and NOX SIP Call programs is that these
programs applied the criteria to the initial operation of the unit and
then to 3-year rolling average periods while the final CAMR criteria
are applied to each individual year starting with the commencement of
operation. EPA believes that using an individual year approach will
streamline the application and administration of this exemption.
Some commenters supported that the one-third criteria be applied on
annual basis and supported that the criteria be consistent with CAIR
and the Acid Rain program. Several commenters suggested exempting all
cogeneration units instead of using the proposed criteria and cite the
high efficiency of cogeneration as a reason for a complete exemption.
EPA believes it is important to include in the CAMR program all units,
including cogeneration units, that are substantially in the business of
selling electricity. The proposed one-third potential electric output
criteria described above are intended to do that.
Inclusion of all units substantially in the electricity sales
business minimizes the potential for shifting utilization, and
emissions, from regulated to unregulated units in that business and
thereby freeing up allowances, with the result that total emissions
from generation of electricity for sale exceed the CAMR emission cap.
The fact that units in the electricity sales business are generally
interconnected through their access to the grid significantly increases
the potential for utilization shifting.
(2) Clarifying ``For Sale.'' Several commenters requested EPA
confirm that, for purposes of applying the one-third potential electric
output criteria, simultaneous purchases and sales of electricity are to
be measured on a ``net'' basis, as is done in the Acid Rain Program.
EPA confirms that, for purposes of applying the one-third potential
electric output criteria in the CAMR program and the model cap-and-
trade rules, the only electricity that counts as a sale is electricity
produced by a unit that actually flows to a utility power distribution
system from the unit. Electricity that is produced by the unit and used
on-site by the electricity-consuming component of the facility will not
count, including cogenerated electricity that is simultaneously
purchased by the utility and sold back to such facility under purchase
and sale agreements under the Public Utilities Regulatory Policy Act of
1978 (PURPA). However, electric purchases and sales that are not
simultaneous will not be netted; the one-third potential electric
output criteria will be applied on a gross basis, except for
simultaneous purchase and sales. This is consistent with the approach
taken in the Acid Rain Program.
(3) Multiple Cogeneration Units. Some commenters suggested
aggregating multiple cogeneration units that are connected to a utility
distribution system through a single point when applying the one-third
potential electric output capacity criteria. According to the
commenters, facilities may have some cogeneration units over the size
threshold for inclusion in the rule, while others may be below it.
These commenters suggested that it is not feasible to determine which
unit is producing the electricity exported to the outside grid. EPA
proposed to determine whether a unit is affected by the CAMR on an
individual-unit basis. This unit-based approach is consistent with both
the Acid Rain Program and the NOX SIP Call. EPA considers
this approach to be feasible based on experience from these existing
programs, including for sources with multiple cogeneration units. EPA
is unaware of any instances of cogeneration unit owners being unable to
determine how to apply the one-third potential electric output capacity
criteria where there are multiple cogeneration units at a source.
In a case where there are multiple cogeneration units with only one
connection to a utility power distribution system, the electricity
supplied to the utility distribution system can be apportioned among
the units in order to apply the one-third potential electric output
capacity criteria. A reasonable basis for such apportionment must be
developed based on the particular circumstances. The most accurate way
of apportioning the electricity supplied to the utility power
distribution system seems to be apportionment based on the amount of
electricity produced by each unit during the relevant period of time.
(4) Proposed Low-emitter Exclusion. In the January 30, 2004 NPR,
EPA took comment on the possibility of excluding from the Phase II cap
units with low Hg emissions rates (e.g., emitting less than 25 pounds
per year (lb/yr)). In the final rule, EPA is not finalizing a low-
emitter exclusion. In proposing the possible low-emitter exclusion, EPA
was concerned about the final rule's impact on small business entities.
EPA also indicated concern about units with low Hg emissions rate
because the new, Hg-specific control technologies that we expect to be
developed prior to the Phase II cap deadline may not practicably apply
to such units. The 1999 ICR data indicated that the 396 smallest
emitting coal-fired units account for less than 5 percent of total Hg
emissions. EPA also indicated in the proposal that there is reason to
believe that the 15 ton Phase II cap can be achieved in a cost-
effective manner, even if the lowest emitting 396 units are excluded
from coverage under this cap.
Several commenters supported the provision excluding low-emitting
units from the cap-and-trade program, while other commenters expressed
opposition to the provision. Several commenters further suggested that,
if the Agency excludes these units in a cap-and-trade program, the
overall Hg emissions cap should not be reduced by the amounts that
these sources emit (i.e., the 2018 cap should remain 15 tons even if
these sources are excluded from the program). Some commenters supported
other options for the exclusion, including an exclusion that started in
Phase I, an exclusion based on 50 lb/yr, and an exclusion based on 100
to 140 MWe size cut-off.
As stated earlier, the low-emitter exclusion was proposed to
address small business entities. Small business entities, however, are
not necessarily small emission emitters. Of the 396 units with
estimated Hg emissions under 25 lb in 1999, most (about 95 percent) are
not owned by small entities and a significant amount (about 10 percent)
are large-capacity units (i.e., greater than 250 MWe). In addition,
removing low-emitters from the trading program could increase costs,
because a significant amount of the 396 units are large-capacity units
that might be expected to be net sellers of allowances because they are
already achieving emissions reductions. Therefore, EPA maintains that
the low-emitter exclusion may not be the best way to address small
entity burden. For the final rule, EPA is not finalizing a low-emitter
exclusion and EPA recommends States address small entities through the
allocation process. For example, States could provide a minimum Phase
II allocation for small entities (e.g., allocation based on projected
2010 unit emissions). EPA also maintains that the cap-and-trade program
and the 25 MWe size cut-off minimizes the burden for small business
entities by ensuring that compliance is met in a least-cost fashion.
[[Page 28627]]
4. How Are Emission Allowances Allocated to Sources?
It is important to ensure that: The integrity of the cap-and-trade
approach is preserved so that the required emissions reductions are
achieved; the compliance and administrative costs are minimized; and
source owners and operators are equitably treated. Accordingly, EPA
believes that some limited differences, such as allowance allocation
methodologies are possible without jeopardizing the environmental and
other goals of the cap-and-trade program.
a. Allocation of Hg Allowances. Each State participating in the
EPA-administered cap-and-trade programs must develop a method for
allocating (i.e., distributing) an amount of allowances authorizing the
emissions tonnage of the State's CAMR budget. Each State has the
flexibility to allocate its allowances however they choose, so long as
certain timing requirements are met.
b. Required Aspects of a State Hg Allocation Approach. Although it
is EPA's intent to provide States with as much flexibility as possible
in developing allocation approach, there are some aspects of State
allocations that must be consistent for all States. All State
allocation systems are required to include specific provisions that
establish when States notify EPA and sources of the unit-by-unit
allocations. These provisions establish a deadline for each State to
submit to EPA its unit-by-unit allocations for processing into the
electronic allowance tracking system. Because the Administrator will
then expeditiously record the submitted allowance allocations, sources
will thereby be notified of, and have access to, allocations with a
minimum lead time (about 3 years) before the allowances can be used to
meet the Hg emission limit.
The final rule finalizes the proposal to require States to submit
unit-by-unit allocations of allowances for existing units for a given
year no less than 3 years prior to the allowance vintage year; this
approach was supported by commenters. Requiring States to submit
allocations and thereby provide a minimum lead time before the
allowances can be used to meet the Hg emission limit ensures that an
affected source, regardless of the State in which the unit is located,
will have sufficient time to plan for compliance and implement their
compliance planning. Allocating allowances less than 3 years in advance
of the compliance year may reduce a CAMR unit's ability to plan for and
implement compliance and, consequently, increase compliance costs. For
example, shorter lead time will reduce the period for buying or selling
allowances and could prevent sources from participating in allowance
futures markets, a mechanism for hedging risk and lowering costs.
Further, requiring a uniform, minimum lead-time for submission of
allocations allows EPA to perform its allocation-recordation activities
in a coordinated and efficient manner in order to complete
expeditiously the recordation and thereby promote a fair and
competitive allowance market across the region.
c. Flexibility and Options for a State Hg Allowance Allocations
Approach. Allowance allocation decisions in a cap-and-trade program
raise essentially distributional issues, as economic forces are
expected to result in economically least-cost and environmentally
similar outcomes regardless of the manner in which allowances are
initially distributed. Consequently, States are given latitude in
developing their Hg allocation approach. Hg allocation methodology
elements for which States will have flexibility include:
The cost of the allowance distribution (e.g., free
distribution or auction);
The frequency of allocations (e.g., permanent or
periodically updated);
The basis for distributing the allowances (e.g., heat-
input or power output); and,
The use of allowance set-asides and their size, if used
(e.g., new unit set-asides or set asides for energy efficiency, for
development of IGCC generation, for renewables, or for small units).
Some commenters have argued against giving States flexibility in
determining allocations, citing concerns about complexity of operating
in different markets and about the robustness of the trading system.
EPA maintains that offering such flexibility, as it did in the
NOX SIP call, does not compromise the effectiveness of the
trading program while maintaining the principle of federalism.
A number of commenters have argued against allowing (or requiring)
the use of allowance auctions, while others did not believe that EPA
should recommend auctions. For the final rule, although there are some
clear potential benefits to using auctions for allocating allowances
(as noted in the SNPR), EPA believes that the decision regarding
utilizing auctions rightly belongs to the States and Tribes. EPA is not
requiring, restricting, or barring State use of auctions for allocating
allowances.
A number of commenters supported allowing the use of allowance set-
asides for various purposes. In the final rule, EPA is leaving the
decision on using set-asides up to the States, so that States may craft
their allocation approach to meet their State-specific policy goals.
d. Example Allowance Hg Allocation Methodology. In the SNPR, EPA
included an example (offered for informational guidance) of an
allocation methodology that includes allowances for new generation and
is administratively straightforward. EPA is including in today's
preamble, this ``modified output'' example allocations approach, as was
outlined in the SNPR.
EPA maintains that the choice of allocation methodology does not
affect the achievement of the specific environmental goals of the CAMR
program. This methodology is offered simply as an example, and
individual States retain full latitude to make their own choices
regarding what type of allocation method to adopt for Hg allowances and
are not bound in any way to adopt the EPA's example.
This example method involves input-based allocations for existing
coal units (with different ratios based on coal type), with updating to
take into account new generation on a modified-output basis. It also
utilizes a new source set-aside for new units that have not yet
established baseline data to be used for updating. Providing allowances
for new sources would address a number of commenter concerns about the
negative effect of new units not having access to allowances.
As discussed in the methodology for determining State budgets, many
comments were received on the use of coal adjustment factors for the
allocation process. In the NPR and SNPR, EPA proposed that if States
want to have allocations reflect the difficulty of controlling Hg, they
might consider multiplying the baseline heat input data by ratios based
on coal type, similar to the methodology used to establish the State Hg
budgets in the final rule. In the final rule for the purposes of
establishing State budgets, EPA is using the coal adjustment factors of
1.0 for bituminous coals, 1.25 for subbituminous coals and 3.0 for
lignite coals. In this example allocation methodology for States, EPA
is also using these adjustment factors.
Under the example method, allocations are made from the State's Hg
budget for the first five control periods (2010 through 2014) of the
model cap-and-trade program for existing sources on the basis of
historic baseline heat input. EPA proposed January 1, 2001 as the cut-
off on-line date for considering units as existing units. The cut-off
on-line date was selected so that any unit
[[Page 28628]]
meeting the cut-off date would have at least 5 years of operating data,
i.e., data for 2000 through 2004. EPA is concerned with ensuring that
particular units are not disadvantaged in their allocations by having
insufficient operating data on which to base the allocations. EPA
believes that a 5-year window, starting from commencement of operation,
gives units adequate time to collect sufficient data to provide a fair
assessment of their operations. Annual operating data is now available
for 2003. EPA is finalizing January 1, 2001 as the cut-off on-line date
for considering units as existing units because units meeting the cut-
off date will have at least 5 years of operating data (i.e., data for
2000 through 2004).
The allowances for 2015 and later will be allocated from the
State's Hg budget annually, 6 years in advance, taking into account
output data from new units with established baselines (modified by the
heat input conversion factor to yield heat input numbers). As new units
enter into service and establish a baseline, they are allocated
allowances in proportion to their share of the total calculated heat
input (which is existing unit heat input plus new units' modified
output). Allowances allocated to existing units slowly decline as their
share of total calculated heat input decreases with the entry of new
units. After 5 years of operation, a new unit will have an adequate
operating baseline of output data to be incorporated into the
calculations for allocations to all affected units. The average of the
highest 3 years from these 5 years will be multiplied by the heat-input
conversion factor to calculate the heat input value that will be used
to determine the new unit's allocation from the pool of allowances for
all sources.
Under the EPA example method, existing units as a group will not
update their heat input. This will eliminate the potential for a
generation subsidy (and efficiency loss) as well as any potential
incentive for less efficient existing units to generate more. This
methodology will also be easier to implement because it will not
require the updating of existing units' baseline data. Retired units
will continue to receive allowances indefinitely, thereby creating an
incentive to retire less efficient units instead of continuing to
operate them in order to maintain the allowance allocations.
Moreover, new units as a group will only update their heat input
numbers once--for the initial 5-year baseline period after they start
operating. This will reduce any potential generation subsidy and be
easier to implement, because it will not require the collection and
processing of data needed for regular updating.
The EPA believes that allocating to existing units based on a
baseline of historic heat input data (rather than output data) is
desirable, because accurate protocols currently exist for monitoring
this data and reporting it to EPA, and several years of certified data
are available for most of the affected sources. EPA expects that any
problems with standardizing and collecting output data, to the extent
that they exist, can be resolved in time for their use for new unit
calculations. Given that units keep track of electricity output for
commercial purposes, this is not likely to be a significant problem.
In its example, EPA is allocating to existing units by heat input
and including adjustments by coal type (1.0 for bituminous coals, 1.25
for subbituminous coals, and 3.0 for lignite coals). However, EPA is
not finalizing adjustments by coal type with the modified output
approach, because we do not want to favor any particular new coal
generation. Allocating to new (not existing) sources on the basis of
input would serve to subsidize less-efficient new generation. For a
given amount of generation, more efficient units will have the lower
fuel input or heat input. Allocating to new units based on heat input
could encourage the building of less efficient units because they would
get more allowances than an equivalent efficient, lower heat-input
unit. The modified output approach, as described below, will encourage
new, clean generation and will not reward less efficient new units.
Under the example method, allowances will be allocated to new units
with an appropriate baseline on a ``modified output'' basis. The new
unit's modified output will be calculated by multiplying its gross
output by a heat rate conversion factor of 7,900 Btu per kilowatt-hour
(Btu/kWh). The 7,900 Btu/kWh value for the conversion factor is an
average of heat-rates for new pulverized coal plants and new IGCC coal
plants (based upon assumptions in EIA's Annual Energy Outlook (AEO)
2004. See Energy Information Administration, ``Annual Energy Outlook
2004, with Projections to 2025,'' January 2004. Assumptions for DOE's
National Energy Modeling System (NEMS) model can be found at http://www.eia.doe.gov/oiaf/archive/aeo04/assumption/tbl38.html). A single
conversion rate will create consistent and level incentives for
efficient generation, rather than favoring new units with higher heat
rates.
For new cogeneration units, their share of the allowances will be
calculated by converting the available thermal output (Btu) of useable
steam from a boiler or useable heat from a heat exchanger to an
equivalent heat input by dividing the total thermal output (Btu) by a
general boiler/heat exchanger efficiency of 80 percent.
Steam and heat output, like electrical output, is a useable form of
energy that can be utilized to power other processes. Because it would
be nearly impossible to adequately define the efficiency in converting
steam energy into the final product for all of the various processes,
this approach focuses on the efficiency of a cogeneration unit in
capturing energy in the form of steam or heat from the fuel input.
Commenters expressed concern about a single conversion factor,
arguing for different factors for different coals and technologies. EPA
maintains that providing each new source an equal amount of allowances
per MWh of output is an equitable approach. Because electricity output
is the ultimate product being produced by electric generating unit, a
single conversion factor based on output ensures that all sources will
be treated equally. Higher conversion factors for less efficient
technologies will effectively provide greater amounts of allowances
(and thus a greater subsidy) to such less efficient units for each MWh
they generate. This will serve to provide greater relative incentives
to build new less efficient technologies rather than efficient
technology. It should also be noted that, because all allocations are
proportionally reduced after a new source is integrated into the
market, higher conversion factors also lower allocations to existing
sources.
Today's example method includes a new source set-aside equal to 5
percent of the State's emission budget for the years 2010 to 2014 and 3
percent of the State's emission budget for the subsequent years. In the
SNPR, EPA proposed a level 2 percent set-aside for all years.
Commenters supported a new source set-aside and one commenter
pointed to EIA forecasts for coal to grow by 112 gigawatts (GW) by
2025. EPA economic modeling projects growth in coal by 2020. In order
to estimate the need for allocations for new units, EPA considered
projected growth in coal generation and the resulting Hg emissions
portion of the Hg national cap. EPA believes the example new source
set-aside would provide for that growth.
Individual States using a version of the example method may want to
adjust
[[Page 28629]]
this initial 5-year set-aside amount to a number higher or lower than 5
percent to the extent that they expect to have more or less new
generation going on-line during the 2001 to 2013 period. They may also
want to adjust the subsequent set-aside amount to a number higher or
lower than 2 percent to the extent that they expect more or less new
generation going on-line after 2004. States may also want to set this
percentage a little higher than the expected need, because, in the
event that the amount of the set-aside exceeds the need for new unit
allowances, the State may want to provide that any unused set-aside
allowances will be redistributed to existing units in proportion to
their existing allocations.
For the example method, EPA is assuming that new units will begin
receiving allowances from the State- or Indian country-established set-
aside for the control period immediately following the control period
in which the new unit commences commercial operation, based on the
unit's emissions for the preceding control period. For instance, a
source might be required to hold allowances during its start-up year,
but will not receive an allocation for that year.
States will allocate allowances from the set-aside to all new units
in any given year as a group. If there are more allowances requested
than in the set-aside, allowances will be distributed on a pro-rata
basis. Allowance allocations for a given new unit in following years
will continue to be based on the prior year's emissions until the new
unit establishes a baseline, is treated as an existing unit, and is
allocated allowances through the State's updating process. This will
enable new units to have a good sense of the amount of allowances they
will likely receive--in proportion to their emissions for the previous
year. This methodology will not provide allowances to a unit in its
first year of operation; however it is a methodology that is
straightforward, reasonable to implement, and predictable.
Although EPA is offering an example allocation method with
accompanying regulatory language, EPA reiterates that it recognizes
States' flexibility in choosing their NOX allocations
method. Several commenters, for instance, have noted their desire for
full output-based allocations (in contrast to the hybrid approach in
the example above). In the past, the EPA had sponsored a work-group to
assist States wishing to adopt output-based NOX allocations
for the NOX SIP Call. Documents from meetings of this group
and the resulting guidance report (found at http://www.epa.gov/airmarkets/fednox/workgrp.html) together with additional resources such
as the EPA-sponsored report ``Output-Based Regulations: A Handbook for
Air Regulators'' (found at http://www.epa.gov/cleanenergy/pdf/output_rpt.pdf) can help States, should they choose to adopt any output-based
elements in their allocation plans.
As an another alternative example, States could decide to include
elements of auctions into their allowance allocation programs.\6\ An
example of an approach where CAMR allowances could be distributed to
sources through a combination of an auction and a free allocation is
provided below.
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\6\ Auctions could provide States with a less distortionary
source of revenue.
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During the first year of the trading program, 94 percent of the Hg
allowances could, for example, be allocated to affected units with an
auction held for the remaining 1 percent of the Hg allowances.\7\ Each
subsequent year, an additional 1 percent of the allowances (for the
first 20 years of the program), and then an additional 2.5 percent
thereafter, could be auctioned until eventually all the allowances are
auctioned. With such a system, for the first 20 years of the trading
programs, the majority of allowances could be distributed for free via
the allocation. Allowances allocated for these earlier years are
generally more valuable than allowances allocated for later years
because of the time value of money. Thus, most emitting units could
receive relatively more allowances in the early years of the program,
when they would be facing the higher expenses of taking action to
control their emissions.
---------------------------------------------------------------------------
\7\ 5 percent of the allowances will go to a new source set-
aside.
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Auctions could be designed by the State to promote an efficient
distribution of allowances and a competitive market. Allowances could
be offered for sale before or during the year for which such allowances
may be used to meet the requirement to hold allowances. States will
decide on the frequency and timing of auctions. Each auction could be
open to any person, who could submit bids according to auction
procedures, a bidding schedule, a bidding means, and by fulfilling
requirements for financial guarantees as specified by the State.
Winning bids, and required payments, for allowances could be determined
in accordance with the State program and ownership of allowances will
be recorded in the EPA Allowance Tracking System after the required
payment is received.
The auction could be a multiple-round auction. Interested bidders
could submit before the auction, one or more initial bids to purchase a
specified quantity of Hg allowances at a reserve price specified by the
State, specifying the appropriate account in the Allowance Tracking
System in which such allowances will be recorded. Each bid could be
guaranteed by a certified check, a funds transfer, or, in a form
acceptable to the State, a letter of credit for such quantity
multiplied by the reserve price. For each round of the auction, the
State would announce current round reserve prices for Hg and determine
whether the sum of the acceptable bids exceeds the quantity of such
allowances available for auction. If the sum of the acceptable bids for
Hg allowances exceeds the quantity of such allowances the State would
increase the reserve price for the next round. After the auction, the
State will publish the names of winning and losing bidders, their
quantities awarded, and the final prices. The State will return payment
to unsuccessful bidders and add any unsold allowances to the next
relevant auction.
In summary, the final rule provides, for States participating in
the EPA-administered CAMR cap-and-trade program, the flexibility to
determine their own methods for allocating Hg allowances to their
sources. Specifically, such States will have flexibility concerning the
cost of the allowance distribution, the frequency of allocations, the
basis for distributing the allowances, and the use and size of
allowance set-asides.
5. What Mechanisms Affect the Trading of Emission Allowances?
a. Banking. (1) The CAMR NPR and SNPR Proposal for the Model Rule
and Input from Commenters. Banking is the retention of unused
allowances from one calendar year for use in a later calendar year.
Banking allows sources to make reductions beyond required levels and
``bank'' the unused allowances for use later. Generally, banking has
several advantages: (a) Banking results in early reductions as
companies over-control their emissions; it is very unlikely that
significant levels of early reductions would occur without banking. (b)
Banked allowances can be used at any time so, they provide flexibility
for companies to respond to growth and changing marketplace conditions
over time. (c) Banking can result in emissions above the cap level in
the later years of the compliance period, however, because the cap is
permanent banking does not result in an increase in cumulative
emissions. This is an important trade-off for getting early reductions.
[[Page 28630]]
The January 30, 2004 NPR and March 16, 2004 SNPR proposed that the
Hg cap-and-trade program allow banking after the start of the Hg
trading program, and that use of banked allowances be allowed without
restrictions.
Comments Regarding Unrestricted Banking After the Start of the Hg
Cap-and-Trade Program. Many commenters supported EPA's proposal to
allow unrestricted banking and the use of banked Hg allowances.
Further, they agreed that banking with no restrictions on use will
encourage early emissions reductions, stimulate the trading market,
encourage efficient pollution control, and provide flexibility to
affected sources in meeting environmental objectives. A few commenters
opposed EPA's proposal of banking without restriction after the start
of the Hg cap-and-trade program. These commmenters generally pointed
out that allowing unrestricted banking delays the achievement of the
Phase II cap.
(2) The Final Hg Model Rule and Banking. Banking of allowances
provides flexibility to sources, encourages earlier or greater
reductions than required, stimulates the market, and encourages
efficiency. EPA has acknowledged that allowing unrestricted banking
after the start of the program will result in the Phase II cap being
achieved over a longer timeframe but it will also yield greater
cumulative reductions early in the program than would be required by
the program cap. Furthermore, banking does not reduce the overall
reduction requirement, and will not affect cumulative Hg reductions
over the full course of the program. EPA is finalizing that banking
will be allowed without restriction after the start of the Hg cap-and-
trade program.
b. Hg Safety Valve Mechanism. (1) The CAMR NPR and SNPR Proposal
for the Safety Valve and Input from Commenters. In the January 30, 2004
NPR and March 16, 2004 SNPR, EPA proposed a safety valve provision that
set the maximum cost purchasers must pay for Hg emissions allowances.
This provision was intended to address 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. 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.
EPA proposed a price of $2,187.50 for a Hg allowance (covering one
ounce) and that this price would be annually adjusted for inflation.
EPA also proposed that the permitting authority deduct corresponding
allowances from future allowance budgets. EPA noted that 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.
Comments regarding the need for safety valve. Many commenters
supported the inclusion of a safety valve to reduce market uncertainty
and guarantee a maximum price at which emissions allowances can be
purchased. These commenters generally cited uncertainty pertaining to
technology availability and cost as the reason for their support. Other
commenters suggested that the safety valve provision should be
eliminated. Some of these commenters noted that EPA's cost analysis of
the cap-and-trade program was projecting that a safety valve price of
$2,187.50/ounce would be triggered, delaying achievement of the cap.
Other commenters noted that the safety valve provision could contribute
to Hg ``hot spots,'' and that the provision is counter to market-based
approach.
(2) The Final Hg Model Rule and the Safety Valve. EPA will not
include a Hg safety valve mechanism in the final rule. EPA maintains
that the safety valve mechanism is not necessary to address market
volatility associated with Hg reduction requirements under CAMR.
EPA maintains that the design of the CAMR trading program, a two-
phased approach of 38 tpy in 2010 and 15 tpy in 2018, reduces the
likelihood of extreme market volatility that the safety valve was
intended to mitigate. The program includes a cap in the first phase
based on the Hg co-benefit reductions expected under the CAIR program
for SO2 and NOX. In addition, the program
provides lead time for compliance for each phase and allows banking of
allowances in the first phase, which provides flexibility in achieving
emissions reductions under the second phase. EPA experience with the
Acid Rain program and the NOX Budget Program indicates that
market volatility has not been a significant factor in these trading
programs, and that it has been greater during the early years of the
programs. EPA believes that setting the Phase I Hg cap at CAIR co-
benefits should limit market volatility caused by uncertainty early in
the program.
EPA also maintains that the timelines and caps of the CAMR trading
program achieve emissions reductions without unacceptable costs. The
Phase I cap of the program is based on co-benefit reduction expected
under the CAIR program, and the Phase II cap represents a level of
reductions that EPA has determined can be achieved without very high
marginal costs, especially given recent advancements in the area of Hg
control technology. EPA's economic modeling of the CAMR program (see
chapter 8 of the RIA) projects that in the first phase of the program,
the marginal cost of control remains under $35,000 per lb (the proposed
safety valve price). Although in the second phase of the CAMR program,
economic modeling projects marginal costs above this level, the
modeling assumes no improvements in the cost of Hg control technology
over time. Given that this is the first time Hg from coal-fired
utilities is being addressed by Federal regulation, and given the
current level of research and demonstration of Hg control technologies,
control cost are expected to improve over time. Because of the
uncertainty around Hg control technologies like ACI, EPA has
conservatively included no cost improvement in its basic modeling
assumptions. Given the development in advanced sorbents for ACI, EPA
examined the impact of Hg technology improvements by providing a lower
cost Hg control option in future years. That modeling projected Hg
marginal costs below $35,000/lb.
6. What Are the Source-Level Emissions Monitoring and Reporting
Requirements?
The final rule adds subpart I to 40 CFR part 75. Subpart I
specifies the basic emission monitoring requirements necessary to
administer a Hg trading program for new and existing Utility Units. The
final rule also revises the regulatory language at several places in 40
CFR parts 72 and 75, to include specific Hg monitoring definitions and
provisions, in support of 40 CFR part 75, subpart I. Affected units
will be required to comply with these Hg monitoring provisions, if and
when 40 CFR part 75, subpart I is adopted by State or Tribal agencies
as part of a Hg
[[Page 28631]]
cap-and-trade program. The changes to 40 CFR part 75 are discussed in
greater detail elsewhere in this action.
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.
Those flexibilities result in substantial cost savings to the industry.
Given the variability in the unit type, manner of operation, and
fuel mix among coal-fired Utility Units, 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 final rule allows two methodologies for
continuously monitoring Hg emissions: (1) Hg 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 Hg emissions trading program is implemented.
In the SNPR, EPA solicited comment on two alternative approaches
for the continuous monitoring of Hg emissions. In the first
alternative, most sources would be required to use CEMS, with low-
emitting sources having Hg mass emissions at or below a specified
threshold value being allowed to use sorbent trap monitoring systems.
In the second proposed alternative, all sources would be allowed to use
either CEMS or sorbent trap monitoring systems. However, the sorbent
trap systems would be subject to QA procedures comparable to those
required for a CEMS, and the QA procedures would be more stringent for
units with Hg mass emissions above a specified threshold value. The
final rule adopts a modification of the second proposed alternative.
Sorbent trap monitoring systems may be used ``across the board,''
provided that rigorous QA procedures are implemented. These QA
requirements, which are found in 40 CFR 75.15 and in 40 CFR part 75,
appendices B and K, are based on input from commenters and from EPA's
own research. The proposed rule would have required quarterly relative
accuracy audits for many of the sorbent trap systems. The final rule
replaces this proposed requirement with alternative procedures that are
more suitable for sorbent trap systems.
For affected sources with Hg emissions at or below a specified
threshold value, 40 CFR 75.81(b) of the final rule provides additional
regulatory flexibility by allowing default Hg concentrations obtained
from periodic Hg emission testing to be used to quantify Hg mass
emissions, instead of continuously monitoring the Hg concentration. The
use of this low mass emitter option is restricted to sources that emit
no more than 29 lb (464 ounce) of Hg per year. The rationale for this
threshold is given elsewhere in this action.
The amendments to 40 CFR part 75 set forth the specific monitoring
and reporting requirements for Hg mass emissions and include the
additional provisions necessary for a cap-and-trade program. The
provisions of 40 CFR part 75 are used in both the Acid Rain and the
NOX Budget Trading programs, and most sources affected by
the final rule are already meeting the requirements of 40 CFR part 75
for one or both of those programs.
The final rule requires the measurement of total vapor phase Hg,
but does not require separate monitoring of speciated Hg emissions
(i.e., elemental and ionized Hg). As stated elsewhere in this action,
EPA does not believe that utility-attributable hot spots will be an
issue after implementation of CAIR and CAMR. Nevertheless, we are
committed to monitoring closely the effects of utility emissions. We
commit to, and retain authority to, address the situation
appropriately. As part of this commitment, the Agency believes that it
is important to understand and monitor the speciation profile of Hg
emissions. However, the Agency does not believe that speciating Hg
monitors are appropriate at this time. For this reason, the Agency
considers separate monitoring of these emissions as a need to be
addressed. However, at least two current monitoring technologies can
accurately monitor speciated Hg emissions. The Agency will continue to
test speciated Hg monitoring technologies. If these technologies are
adequately demonstrated, the Agency may consider a proposed rulemaking
to reflect changes in the monitoring requirements within 4 to 5 years
after program implementation, which should provide enough lead time for
development and installation of these monitoring systems.
In order to ensure program integrity, the model trading rule
requires States to include year-round 40 CFR part 75 monitoring and
reporting for Hg for all sources. Deadlines for monitor certification
and other details are specified in the model rule. EPA believes that if
these provisions are implemented, emissions will be accurately and
consistently monitored and reported from unit-to-unit and from State-
to-State.
As is required for the Acid Rain program and the NOX
Budget Trading program, Hg emissions data will 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 found this
centralized reporting requirement necessary to ensure consistent
review, checking, and posting of the emissions and monitoring data from
all affected sources, which contributes to the integrity and efficiency
of the trading program.
Finally, consistent with the current requirements in 40 CFR part 75
for the Acid Rain and the NOX SIP Call programs, the final
rule allows sources, under 40 CFR 60.4175 of 40 CFR part 60, subpart
HHHH, and under 40 CFR 75.80(h) of 40 CFR part 75, subpart I, to
petition for an alternative to any of the specified monitoring
requirements in the final rule. This provision also provides sources
with the flexibility to petition to use an alternative monitoring
system under 40 CFR part 75, subpart E as long as the requirements of
40 CFR 75.66 are met.
7. Are There Additional Changes to the Proposed Model Cap-and-Trade
Rule Reflected in the Regulatory Language?
The final rule includes some minor changes to the model rule's
regulatory text that improve the implementability of the rules or
clarify aspects of the rules identified by EPA or commenters. (Note
that elsewhere in this action are highlighted the more significant
modifications included in the final model rules.)
These include:
The definition of ``nameplate capacity'' is clarified;
The language on closing of general accounts is clarified;
Another example of where today's final model trading rules
incorporate relatively minor changes from the proposed model trading
rules involves the provisions in the standard requirements concerning
liability under the trading programs. The proposed Hg model trading
rule includes, under the standard requirements in the 40 CFR
60.4154(d)(3) provision stating that any person who knowingly violates
the Hg trading programs or knowingly makes a false material statement
under the trading programs will be subject to
[[Page 28632]]
enforcement action under applicable State or Federal law. The final Hg
model trading rule excludes this provision for the following reasons.
First, the proposed rule provision is unnecessary because, even in its
absence, applicable State or Federal law authorizes enforcement actions
and penalties in the case of knowing violations or knowing submission
of false statements. Moreover, the proposed rule provision is
incomplete. It does not purport to cover, and has no impact on,
liability for violations that are not knowingly committed or false
submissions that are not knowingly made. Applicable State and Federal
law already authorizes enforcement actions and penalties, under
appropriate circumstances, for non-knowing violations or false
submissions. Because the proposed rule provision is unnecessary and
incomplete, the final model Hg trading rule does not include this
provision. However, EPA emphasizes that, on its face, the provision
that was proposed, but eliminated in the final rule, in no way limits
liability, or the ability of the State or EPA to take enforcement
action, to only knowing violations or knowing false submissions.
F. Standard of Performance Requirements
1. Introduction
As proposed in the NPR and SNPR, and finalized today, under CAA
section 111, each State is required to submit a State Plan
demonstrating that each State will meet the assigned Statewide Hg
emission budget. Each State Plan should include fully-adopted State
rules for the Hg 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. This section also describes the actions the
Agency intends to take if a State fails to submit a satisfactory plan.
In addition, this section sets forth the criteria for States to receive
approvability of trading rule within a State Plan.
2. Performance Standard Approvability Criteria
As discussed in the NPR and SNPR, CAA sections 111(a) and (d)(1)
authorize EPA to promulgate a ``standard of performance'' that States
must apply to existing sources through a State plan. As also discussed
in the NPR and elsewhere in the final rule, 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 Statewide emissions from affected new and
existing sources to the amount of the budget. Consistent with CAIR, EPA
is finalizing 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). Regardless of State participation
in the national cap-and-trade program, 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 is finalizing that all regulatory
requirements be in the form of a maximum level of emissions (i.e., a
cap) for the sources.
As proposed in the SNPR, EPA is finalizing 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 CAIR.
Moreover, States remain authorized to require emissions reductions
beyond those required by the State budget, and nothing in the final
rule will preclude the States from requiring such stricter controls and
still being eligible to participate in the Hg Budget Trading Program.
In addition, as proposed in the SNPR, EPA finalizes today that
sources will be required to comply with the 40 CFR part 75
requirements. 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 final rule, EPA will prescribe a Federal plan for that State,
under CAA section 111(d)(2)(A). EPA proposes today's model rule as that
Federal plan.
3. Approvability of Trading Rule Within a State Plan
a. Necessary Common Components of Trading Rule. As discussed in the
SNPR and for the final rule, 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 will 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 flexibility while still
ensuring the environmental results and administrative feasibility of
the program. EPA finalizes 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. Additionally, States may incorporate a mechanism for
implementing more stringent controls at the State level within their
allowance allocation methodology.
[[Page 28633]]
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. 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.
b. Revisions to Regulations. As proposed in the SNPR, the final
rule finalizes 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 CAA section 111(d) may include an allowance program of
the type described today.
G. What Are the Performance Testing and Other Compliance Provisions?
1. Summary of Major Comments and Responses
a. Use of Sorbent Trap Monitoring Systems. EPA proposed two
alternatives for the use of sorbent trap monitoring systems.
Alternative 1 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 ounce (9 lb) or less, for the same 3 calendar years
used to allocate the Hg allowances. The threshold value of 9 lb/yr year
was based on 1999 data gathered by EPA under an ICR that appeared in
the Federal Register on April 9, 1998. Based solely on the 1999 ICR
data, 228 of the 1,120 coal-fired Utility 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. EPA also took comment on three other threshold
values, i.e., 29 lb/yr, 46 lb/yr, and 76 lb/yr, representing,
respectively, 435, 565, and 724 of the 1,120 units in the database.
Alternative 2 would allow any source to use either CEMS or
sorbent traps. For sources with annual Hg emissions below a specified
threshold value (we took comment on four values, i.e., 9 lb/yr, 29 lb/
yr, 46 lb/yr, or 76 lb/yr), the QA requirements for sorbent trap
monitoring systems would consist of the procedures in proposed Method
324 of 40 CFR part 63 plus an annual RATA. For sources with annual Hg
emissions above the specified threshold, quarterly relative accuracy
(RA) testing (i.e., a full 9-run RATA once a year and 3-run RAs in the
other three quarters of the year) would be required in addition to the
proposed Method 324 procedures.
EPA also requested comment on the appropriateness of proposed QA
procedures for sorbent trap monitoring systems. Numerous commenters
expressed concern that EPA's proposal was unfairly and unjustifiably
biased against the sorbent trap method. The commenters did not support
Alternative 1, because it restricts the use of sorbent traps
to low emitting units. Commenters were generally more receptive to
Alternative 2, except for the proposed QA/QC procedures for
sorbent trap systems (most notably the quarterly RA testing), which
they found to be inappropriate, overly burdensome, costly, and time-
consuming. Several commenters stated that EPA has no justification for
restricting the use of the sorbent trap method because it has been
shown during EPA-sponsored Hg monitoring demonstrations that the method
can achieve accuracies comparable, and in some cases better than those
achieved by Hg CEMS. Other commenters recommended that the type of QA/
QC procedures prescribed for sorbent trap systems should be more
specific to the sorbent trap technology and should be more clearly
defined. Finally, a number of commenters objected to the proposal to
report the higher of the two Hg concentrations from the paired sorbent
traps, and recommended that the results be averaged instead.
The final rule adopts under 40 CFR 75.81(a) a modified version of
Alternative 2, which allows the use of sorbent trap systems
for any affected unit, provided that rigorous, application-specific QA
procedures are implemented. The operational and QA/QC procedures for
sorbent trap systems are found in 40 CFR 75.15 and in 40 CFR part 75,
appendices B and K of the final rule. EPA also has incorporated the
recommendation of the commenters to use the average of the Hg
concentrations measured by the paired sorbent traps. And in cases where
one of the traps is accidentally lost, damaged, or broken, the owner or
operator would be permitted to report the results of the analysis of
the other trap, if valid.
Recent field test data from several different test sites indicate
that sorbent trap systems can be as accurate as Hg CEMS. Recent field
tests have answered questions regarding which substances in the flue
gas can interfere with accurate vapor phase Hg monitoring by sorbent
traps. Sorbent trap technology also has evolved, with the addition of a
third segment that enables the individual traps to be subject to
enhanced QA procedures. And the Agency has been working with industry
and equipment manufacturer representatives to develop new QA procedures
that are more relevant to the operation of a sorbent trap system. These
improved QA procedures are included in the final rule. In view of this,
EPA believes that it is appropriate to extend the use of sorbent trap
systems to all affected units.
EPA notes that although the restrictions on the use of sorbent
traps have been removed, there are some inherent risks associated with
the use of this monitoring approach. For instance, because sorbent
traps may contain several days of accumulated Hg mass, the potential
exists for long missing data periods, if the traps should be broken,
compromised, or lost during transit or analysis, or if they fail to
meet the QC criteria. Also, when a RATA of a sorbent trap system is
performed, the results of the test cannot be known until the contents
of the traps have been analyzed. If the results of the analysis are
unsatisfactory, the RATA may have to be repeated. This also may result
in a long missing data period. However, EPA believes that these
undesirable outcomes can be minimized by following the proper handling,
chain of custody, and laboratory certification procedures in the final
rule. The use of redundant backup monitoring systems can also help to
reduce the amount of missing data substitution.
2. Compliance Flexibility for Low Emitters
The SNPR did not contain any special monitoring provisions for
units with low mass emissions (LME). All affected units would be
required to continuously monitor the Hg concentration, using either
CEMS or sorbent trap monitoring systems.
Numerous commenters requested that EPA provide a less rigorous,
cost-effective monitoring option for low emitting units. Affected units
could meet a low emitter criterion based on a
[[Page 28634]]
combination of unit size, operating time, and/or control device
operation. Any marginal decrease in accuracy from less rigorous
monitoring would have a minimal impact overall, because these units
represent only a small percentage of the nationwide Hg mass emissions.
Consistent with the LME provisions in 40 CFR 75.19 for
SO2 and NOX, 40 CFR 75.81(b) through (g) of the
final rule provide a less rigorous monitoring option for low Hg
emitters. These provisions allow sources with estimated annual
emissions of 29 lb/yr (464 ounce/yr) or less, representing about 5
percent of the nationwide Hg mass emissions, to use periodic emission
testing to quantify their Hg emissions, rather than continuously
monitoring the Hg concentration. For units with Hg emissions of 9 lb/yr
(144 ounce/yr) or less, annual emission testing is required. For units
with Hg emissions greater than 144 ounce/yr but less than or equal to
464 ounce/yr, semiannual testing is required. For reporting purposes,
the owner or operator is required to use either the highest Hg
concentration from the most recent emission testing or 0.50 micrograms
per standard cubic meter ([mu]g/scm), whichever is greater. If, at the
end of a particular calendar year, the reported annual Hg mass
emissions for a unit exceed 464 ounce, the unit is disqualified as a
low mass emitter and the owner or operator must install and certify a
Hg CEMS or sorbent trap monitoring system within 180 days of the end of
that year. The final rule also contains special low mass emitter
provisions for common stack and multiple stack exhaust configurations.
The Agency believes that a low mass emitter provision can be
beneficial to both EPA and industry. It is cost-effective for industry,
in that it allows periodic stack testing to be used to estimate Hg
emissions instead of requiring CEMS. In the context of a cap-and-trade
program, a low emitter provision can provide environmental benefit,
because it requires conservatively high default emission factors to be
used for reporting, as explained in the paragraphs below. Also,
allowing a subset of the affected units to use less rigorous monitoring
reduces the administrative burden of program implementation, allowing
EPA to focus its attention on the higher-emitting sources.
Selecting an appropriate low emitter cutoff point is of critical
importance. On the one hand, if the cutoff point is too low (i.e., too
exclusive) this would not be cost-effective for the regulated sources
and would greatly increase the burden on the regulatory agencies to
implement and maintain the program. On the other hand, if the cutoff
point is too high (i.e., too inclusive), this would create inequities
in the trading market.
Over the years, EPA has used a de minimis concept to either exempt
low-emitting sources from monitoring or to allow these sources to use
less rigorous, lower cost techniques to monitor emissions instead of
installing CEMS:
In the preamble of the 1993 Acid Rain Program final rule
(see 58 FR 3593, January 11, 1993), EPA's Acid Rain Division (now the
Clean Air Markets Division, CAMD) first used the de minimis concept to
exempt certain new Utility Units from the Acid Rain Program (i.e.,
units <= 25 MW that burn only fuels with a sulfur content <= 0.05
percent by weight);
EPA also allows gas-fired and oil-fired peaking units to
use the less costly methodology in 40 CFR part 75, appendix E to
estimate NOX emissions instead of using CEMS, because the
Agency's analyses indicated that projected NOX emissions
from these units represent less than 1 percent of the total
NOX emissions from Acid Rain Program units.
In 1998, EPA promulgated LME provisions in 40 CFR 75.19
for SO2 and NOX (see 63 FR 57484, October 27,
1998). These provisions require the use of conservatively high default
emission rates to quantify SO2 and NOX emissions.
EPA determined the appropriate SO2 and NOX mass
emissions thresholds or ``cutoff points'' for unit to qualify as a low
mass emissions methodology, considering inventory and regulatory
changes that had taken place since the original 1993 Acid Rain
rulemaking. The selected threshold values were based on a de minimis
concept, i.e., the SO2 and NOX emissions from the
units that could potentially qualify to use the LME methodology
represented less than or equal to 1 percent of the emissions from all
affected units.
In 1999, EPA obtained Hg mass emissions estimates for the 1,120
utility units affected by the SNPR, as the result of an ICR that
appeared in the Federal Register on April 9, 1998. These data show that
if a low Hg mass emission threshold of 9 lb/yr were selected, 228
units, representing 1 percent of the total annual Hg emissions from
coal-fired electric utility units in the U.S., could potentially
qualify to use the low emitter option. However, EPA's analysis also
indicated that by raising the cutoff point to 29 lb/yr, almost twice
the number of units (435), representing just 5 percent of the total
annual Hg emissions, could potentially qualify as low emitters.
Therefore, EPA has decided to adopt the 29 lb/yr as the qualifying low
mass emission threshold for Hg.
Although the 5 percent threshold represents a departure from the
traditional de minimis value of 1 percent, the Agency believes that
allowing units with Hg emissions of 29 lbs/yr or less to use the low
mass emitter option is a better choice, for both economic and
environmental reasons. For continuous monitoring methodologies, the
annualized cost per unit will be about $89,500 for testing,
maintenance, and operation. For sorbent trap methodologies, the
annualized cost per unit will be about $113,000 for testing,
maintenance, and operation. For a unit that emits between 9 lb/yr and
29 lb/yr of Hg, if the owner or operator elects to use the low emitter
option, the final rule would require two stack tests per year (at
$5,500 each), and an estimated $1,500 annual cost for technical
calculation, labor, and other associated costs, for a total annual
expenditure per unit of around $12,500. Therefore, for the
approximately 207 units with Hg mass emissions between 9 and 29 lb/yr,
the potential savings associated with the implementation of the low
emitter option could be as high as: $89,500 - $12,500 = $77,000 x 207
units = $15,939,000/yr if LME is used instead of Hg CEMS.
Alternatively, if LME is used instead of sorbent traps, the potential
savings could be even higher: $113,000-$12,500 = $100,500 x 207 units =
$20,803,500/yr. This is achieved without losing the environmental
integrity of the program or compromising the cap, because the default
Hg concentration values used for reporting are conservatively high, and
for units with FGD systems or add-on Hg emission controls, the rule
requires the maximum potential concentration (MPC) to be reported when
the controls are not operating properly.
As a further justification of the 5 percent low emitter threshold
for Hg, EPA notes that there are two important differences between the
Hg LME provisions in 40 CFR 75.81 and the LME provisions in 40 CFR
75.19 for SO2 and NOX (which are based on a 1
percent threshold). First, under 40 CFR 75.19, default emission rates
are used exclusively, and there is no real-time continuous monitoring
of the SO2 or NOX emissions. However, under 40
CFR 75.81, the stack gas volumetric flow rate, which is used in the
hourly Hg mass emission calculations, is continuously monitored.
Second, the LME provisions in 40 CFR 75.19 allow sources to either use
generic default NOX emission rates without performing any
emission testing, or, if you test for NOX, you are only
required to determine
[[Page 28635]]
a new default emission rate once every 5 years. Under 40 CFR 75.81,
emission testing is required initially to qualify as a low emitter, and
retesting is required either semiannually or annually thereafter,
depending on the annual emission level.
3. Missing Data
To address missing data from Hg CEMS, EPA proposed to add a new
section to the rule, 40 CFR 75.38, which would require the same initial
and standard missing data routines that are used for SO2
monitors to be applied to Hg CEMS. That is, until 720 hours of quality-
assured Hg data have been collected following initial certification,
the substitute data value for any period of missing data would be the
average of the Hg concentrations recorded before and after the missing
data period. Thereafter, the percent monitor data availability (PMA)
would be calculated hour-by-hour, and the familiar four-tiered standard
missing data procedures of 40 CFR 75.33(b) would be applied. Using this
approach, the substitute data values would become increasingly
conservative as the PMA decreases and the length of the missing data
period increases. For PMA values below 80 percent, the MPC would be
reported.
For a unit equipped with an FGD system that meaningfully reduces
the concentration of Hg emitted to the atmosphere, or for a unit
equipped with add-on Hg emission controls, the initial and standard Hg
missing data procedures would apply only when the FGD or add-on
controls are documented to be operating properly, in accordance with 40
CFR 75.58(b)(3). For any hour in which the FGD or add-on controls are
not operating properly, the MPC would be the required substitute data
value.
Also for units equipped with FGD systems or add-on Hg emission
controls, proposed 40 CFR 75.38 would allow the owner or operator to
petition to use the maximum controlled Hg 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.
EPA considered using the load-based NOX missing data
routines in 40 CFR 75.33(c) as the model for Hg, but this approach was
not proposed in the absence of any data indicating that vapor phase Hg
emissions are load-dependent. The Agency solicited comments on the
proposed missing data approach.
EPA also proposed to add initial and standard missing data
procedures for sorbent trap monitoring systems, in a new section, 40
CFR 75.39. Missing data substitution would be required whenever a gas
sample is not extracted from the stack, or when the results of the Hg
analyses representing a particular period of unit operation are missing
or invalid.
The initial missing data procedures for sorbent trap systems would
be applied from the hour of certification until 720 quality-assured
hours of data have been collected. The initial missing data algorithm
would require the owner or operator to average the Hg 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 Hg concentration data were
collected, the owner or operator would begin reporting the PMA and
would begin using the standard missing data algorithms. The standard
missing data procedures for sorbent trap systems would also follow a
``tiered'' approach, based on the PMA. For example, at high PMA
(greater than or equal to 95.0 percent), the substitute data value
would be the average Hg 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 dropped below 80.0 percent, the MPC would be
reported.
Similar to the proposed provision for Hg CEMS, if a unit using
sorbent traps is equipped with an FGD system or add-on Hg emission
controls, the initial and standard missing data procedures could only
be applied for hours in which proper operation of the emission controls
is documented. In the absence of such documentation, the MPC would be
reported.
Several commenters stated that the proposed missing data procedures
seem to be unduly harsh and appear to be unfairly biased against the
use of the sorbent trap method. The commenters indicated that the
missing data routines should properly consider the uncertainties
associated with Hg monitoring, i.e., there is a lack of evidence that
high PMA is achievable with these monitoring systems. Other commenters
suggested that EPA should remove the MPC provision altogether for Hg
monitors and fill in all missing data periods using average
concentrations until more confidence is gained in the reliability of Hg
monitors.
The final rule retains the proposed missing data provisions for Hg
CEMS, but slightly relaxes the PMA cut-points. In the proposed four-
tiered missing data procedure the cut points separating the tiers are
at 95 percent, 90 percent, and 80 percent PMA. The final rule lowers
these to 90 percent, 80 percent, and 70 percent PMA, respectively for
Hg concentration monitors. The final rule also retains the MPC concept,
and amends the proposed missing data procedures for sorbent traps to
more closely match the Hg CEMS missing data procedures.
The final rule retains the basic missing data substitution approach
for Hg that was proposed. This approach has worked well in the Acid
Rain and NOX Budget Programs. The conservative nature of the
missing data routines has provided a strong incentive to sources to
keep their monitoring systems operating and well-maintained. However,
the PMA cut points in the final rule have been loosened slightly to
account for the present lack of long-term Hg monitoring experience in
the U.S. The Agency will continue to collect and analyze CEMS and
sorbent trap data from various field demonstration projects and will
evaluate the performance of certified Hg CEMS operating on similar
source categories (e.g., waste combustors). If the data indicate that
the PMA cut-points should be changed for Hg CEMS or sorbent traps, the
Agency will initiate a rulemaking for that purpose.
The suggestion to remove the MPC provisions and to fill in all
missing data periods using average concentrations until EPA develops
better procedures was not incorporated in the final rule for two
reasons. First, when add-on emission controls that reduce Hg emissions
either malfunction and are taken off-line, uncontrolled Hg emissions
will result. If the Hg CEMS or sorbent trap system is out-of-control
during the control device outage, an appropriate substitute data value
must be used to represent uncontrolled Hg emissions and provide an
incentive to fix the Hg monitoring system. The MPC concept has
successfully been used in the Acid Rain and NOX Budget
Programs.
Second, EPA does not agree with the commenters that using the MPC
for certain missing data periods is always unduly harsh or punitive.
For the initial Hg MPC determination, the March 16, 2004 SNPR provided
three options: (1) Use a coal-specific default value; or (2) perform
site-specific emission testing upstream of any control device; or (3)
base the MPC on 720 hours or more of historical CEMS data on
uncontrolled Hg emissions. The Agency believes that these options
provide adequate opportunity for affected units to develop appropriate
MPC values.
Regarding the missing data routines for sorbent trap systems,
available field test data have indicated that these
[[Page 28636]]
systems are capable of performance that is equivalent to a CEMS. In
view of this, EPA believes that sorbent traps should be treated on a
more equal footing with Hg CEMS in many areas, including the missing
data provisions.
Finally, EPA notes that a new missing data policy has been posted
on the CAMD Web site. The policy allows the four-tiered missing data
algorithms to be applied hour-by-hour, in a stepwise manner, based on
the PMA. Previously, the Agency's policy had been to determine the PMA
at the end of the missing data period and to apply a single substitute
data value (sometimes the MPC, if the ending PMA was less than 80
percent) to each hour in the missing data block. This new, more lenient
interpretation of the 40 CFR part 75 missing data requirements will
result in more representative missing data substitution and minimize
the use of the MPC.
4. Instrumental Reference Method for Hg
Only a wet chemistry method, the Ontario Hydro Method, was proposed
to perform RATAs of Hg CEMS and sorbent trap monitoring systems.
Some commenters objected to the use of the Ontario Hydro Method for
RATA testing, stating that due to the complexity of wet chemical
methods and their inability to produce accurate concentrations, there
will be some cases where a properly functioning Hg CEMS will fail a
RATA due to inaccuracies in the reference method. Other commenters
noted that unlike the instrumental reference methods routinely used to
QA SO2 and NOX CEMS, the Ontario Hydro Method can
take days to complete and weeks for the return of test results from the
laboratory, which could lead to significant implementation problems
with respect to missing data and requirements to calculate and report
data. A number of commenters stated that for applications where Hg CEMS
are used, a real time instrumental reference method for RATAs is
needed, and that EPA should develop such an instrumental method.
Use of an instrumental method for RATAs of Hg monitoring systems
and sorbent trap systems is allowed by 40 CFR 75.22 of the final rule,
subject to approval by the Administrator. EPA will propose a Hg
instrumental reference method once sufficient field test data are
collected and analyzed.
At present, EPA is conducting field demonstrations of Hg monitoring
technology. One of the high priority items in these studies is the
development of a suitable instrumental method for Hg. When the field
testing is complete, EPA intends to propose and promulgate the
instrumental method. A Hg instrumental reference method for RATA
testing is vastly preferable to the Ontario Hydro Method and will
greatly facilitate the implementation of a Hg cap-and-trade program.
The Ontario Hydro Method, which is a wet chemistry method that uses
numerous glass impingers, requires at least a one week turn-around to
obtain results, and (as with all wet chemistry methods) is cumbersome
to use and subject to operator error.
5. QA/QC Procedures for Hg CEMS
For initial certification, EPA proposed to require the following
tests for Hg CEMS:
A 7-day calibration error test, using elemental Hg
calibration gas standards. The monitor would be required to meet a
performance specification of 5.0 percent of span on each day of the
test or (for span values of 10 [mu]g/scm) an alternate specification of
1.0 [mu]g/scm absolute difference between reference gas and CEMS;
A 3-point linearity check, using elemental Hg calibration
gas standards. The monitor would be required to meet a performance
specification of 10.0 percent of the reference gas concentration at
each gas level or an alternate specification of 1.0 [mu]g/scm absolute
difference between reference gas and CEMS;
A cycle time test. The maximum allowable cycle time would
be 15 minutes;
A RATA, using the Ontario Hydro Method. The monitor would
be required to achieve a relative accuracy of 20.0 percent.
Alternatively, if the Hg concentration during the RATA is less than 5.0
[mu]g/scm, the results would be acceptable if the mean difference
between the reference method and CEMS does not exceed 1.0 [mu]g/scm.
A bias test, using data from the RATA, to ensure that the
CEMS is not biased low with respect to the reference method.
A 3-point converter check, using HgCl2
standards. The monitor would be required to meet a performance
specification of 5.0 percent of span at each gas level.
For ongoing QA/QC, we proposed the following QA/QC tests:
Daily 2-point calibration error checks, using elemental Hg
gas standards. The monitor would be required to meet a performance
specification of 7.5 percent of span or an alternate specification of
1.5 [mu]g/scm absolute difference between reference gas and CEMS;
Quarterly 3-point linearity checks, using elemental Hg gas
standards. The performance specifications would be the same as for
initial certification.
Monthly 3-point converter checks using HgCl2
standards. The performance specifications would be the same as for
initial certification.
Annual RATA and bias test. The performance specifications
would be the same as for initial certification.
After reviewing the proposed rule, commenters were in general
agreement on the following points. Although many vendors of Hg CEMS
have recently upgraded their instrument systems and these changes
should eventually improve the accuracy and reliability of Hg CEMS and
reduce the labor needed for instrument maintenance, these new
instrument systems have not been tested extensively in demonstration
programs. Therefore, the ability of these instrument systems to achieve
the proposed relative accuracy, calibration error, and calibration
precision requirements has not been adequately demonstrated. Therefore,
EPA does not yet have a basis or data to guide the setting of
specifications for calibration error, linearity, or RA. It appears that
the proposed performance specifications mirror those for SO2
and NOX monitoring. EPA should commit to collecting data and
evaluating these specifications as soon as calibration gases are
available, so that the specifications can be adjusted if necessary,
prior to program implementation. EPA should require operators of Hg
CEMS to conduct procedures that include but are not necessarily limited
to daily zero and span audits, quarterly RA tests and 3-point elemental
Hg linearity tests, and absolute calibration audits. Analytically,
there is clearly a need to challenge the entire system often with a
form of oxidized Hg. This Hg chloride reference gas would be highly
desirable to check integrity of the sample interface. However, further
research needs to be required to enable the development of an accurate
oxidized Hg standard. One device, the HOVACAL, may have the potential
of delivering known concentrations of HgCl2. EPA should
recognize and accept this type of calibration system in the proposed
regulation. There are concerns with the proposed RATA process,
particularly the length of time and amount of money that may be
required to comply with the Hg monitoring requirements on an annual
basis. The final monitoring requirements must be technically achievable
and capable of measuring Hg emissions with precision, reliability, and
accuracy in a cost-effective manner.
[[Page 28637]]
The decision to report Hg concentration on dry or wet basis needs more
consideration, as well as, the evaluation of gaseous interferences.
Lastly, many of the equations and calculations are incomplete or
contain errors and many sections need further clarification.
After considering the comments received, the Agency decided to
retain in the final rule, the same tests as were required for initial
certification and on-going QA of Hg CEMS in the SNPR. However, note the
following changes to some of the procedures and performance
specifications:
For the 7-day calibration error test, either elemental Hg
standards or a National Institute of Standards and Technology (NIST)-
traceable source of oxidized Hg (referred to as ``HgCl2
standards'' in the SNPR) may be used;
Quarterly 3-level ``system integrity checks'' (which were
called ``converter checks'' in the SNPR) using a NIST-traceable source
of oxidized Hg may be performed in lieu of the quarterly linearity
checks with elemental Hg;
Daily calibration error checks may be performed using
either elemental Hg standards or a NIST-traceable source of oxidized
Hg. The daily performance specification has been made the same as for
the 7-day calibration error test;
The monthly converter check at 3 points has been replaced
with a weekly system integrity check at a single point, and the weekly
test is not required if daily calibrations are performed with a NIST-
traceable source of oxidized Hg.
When the Ontario Hydro Method is used, paired trains are
required, the results must agree within 10 percent of the relative
deviation (RD), and the results should be averaged.
Note that EPA plans to analyze RATA data from Hg monitors and may
initiate a future rulemaking to adjust the RA performance
specifications and to propose a performance-based RATA incentive system
similar to the reduced frequency incentive system in 40 CFR part 75 for
SO2, NOX, CO2, and flow monitors.
EPA disagrees with the commenters who stated that there are no data
available to justify the proposed performance specifications for Hg
monitors. Such data have been collected from several field test sites
and for several different types of Hg concentration monitors, which
show that Hg CEMS can meet the proposed calibration error and linearity
standards, and can meet a 20 percent RA standard. A more detailed
discussion of these studies is provided in the Response to Comments
document. Therefore, except for the daily calibration error
specification, which has been tightened based on the available data,
the final rule promulgates the proposed calibration error, linearity
check, and RATA performance specifications, as proposed.
EPA has retained the requirement to check the converter
periodically with HgCl2 standards, because it is essential
to ensure that all of the vapor phase Hg is being measured. The
frequency of the check (which is referred to as a ``system integrity
check'' in the final rule) has been increased from monthly to weekly,
based on supportive comments to check the entire system more often, but
the requirement to perform a 3-point check has been reduced to a
single-point test. And the weekly test is not required if a NIST-
traceable oxidized Hg source is used for daily calibrations.
There are several different devices available that can provide
oxidized Hg, including the HOVACAL and the MerCAL. The HOVACAL has been
successfully applied in the laboratory and field to generate and
deliver known concentrations of HgCl2 to Hg CEMS to achieve
the requirements of the 40 CFR part 75 system integrity check.
Moreover, oxidized Hg gas standards such as are produced by the HOVACAL
and MerCAL are currently scheduled to be independently tested by NIST,
to verify their suitability as reference gas standards.
6. Sorbent Trap Operation and QA/QC
General guidelines for operating sorbent trap systems were proposed
in 40 CFR 75.15. The use of paired traps would be required, and the
stack gas would be sampled at a rate that is proportional to the stack
gas volumetric flow rate. Proposed Method 324 would be used as the
protocol for operating the monitoring systems and for analyzing the Hg
samples collected by the sorbent traps.
Additional QA requirements for sorbent trap systems were proposed
in sections 1.5, 2.3 and 2.7 of 40 CFR part 75, appendix B. Development
of a QA/QC program and plan would be required. Key components of this
program would be assignment of permanent identification (ID) numbers to
the sorbent traps, keeping of records of the dates and times that each
trap is used, establishment of a chain of custody for transporting and
analyzing the traps, documentation that the laboratory analyzing the
samples is certified according to International Organization for
Standardization (ISO) 9000 standards, explanations of the leak check
and other QA test procedures, and the rationale for the minimum
acceptable data collection time for each trap. In addition, the data
acceptance and QC criteria of proposed Method 324 would be included in
the QA plan.
An annual RATA and bias test of each sorbent trap system would be
required, using the Ontario Hydro Method as the reference method. And
if proposed Alternative 2 were implemented (i.e., allowing
sorbent trap systems to be used by any affected unit), for units with
annual Hg mass emissions above a certain threshold value (we took
comment on four thresholds, i.e., 9 lb/hr, 29 lb/hr, 46 lb/hr, and 76
lb/hr), additional 3-run RAs would be required in the other three
quarters of the year.
The commenters were generally opposed to the proposed quarterly RAs
for sorbent trap systems as being too costly and of little value. A
number of commenters suggested that EPA should revise proposed
Alternative 2 and specify QA procedures that are meaningful to
the type of measurement system that the sorbent trap actually is. For
example, the volume of stack gas sampled by the system is an important
parameter in determining the Hg concentration. Therefore, procedures
for quality-assuring the measurement of the sample volume could be
implemented.
Some commenters favored allowing the use of proposed Method 324 for
all affected units, and stated that because proposed Method 324 is
itself a test method, it does not need additional QA procedures. Two
commenters suggested that EPA should even take steps to make proposed
Method 324 a reference method. However, numerous other commenters
objected to various provisions of proposed Method 324 and offered
suggestions for improving it. Some of the chief objections raised were
as follows:
The allowable analytical techniques and procedures in the
method are too exclusive, and in the case of EPA Method 1631 of 40 CFR
part 136, inappropriate. Other analytical methodologies should be
allowed;
The impinger and dessicant method of moisture removal is
inadequate;
The leakage rate prescribed for the leak checks may be too
low to measure;
The method allows constant-rate sampling for collection
periods less than 12 hours, which may introduce bias if unit load
changes during the collection period;
The specification for flow proportional sampling (adjust
sample flow rate to maintain proportional sampling within
25 percent of stack gas flow rate) is not stringent enough and can lead
to inaccurate concentration measurement;
The frequency for dry gas meter calibration is
unspecified; and
[[Page 28638]]
The method does not include chain of custody procedures.
A number of commenters suggested that EPA should not require the
use of paired sorbent traps and should allow the use of single sorbent
traps.
Several commenters objected to the proposal in section 1.5.4 of 40
CFR part 75, appendix B that laboratories performing proposed Method
324 be certified by the ISO to have proficiency that meets the
requirements of ISO 9000. One commenter stated that having a good blank
and matrix spike program in place is much more indicative of a good QA/
QC program for Hg measurement than ISO 9000 certification. Another
commenter favored ISO certification, but not according to ISO 9000. The
commenter recommended that ISO 17025 be required instead, because it
requires the laboratory to demonstrate proficiency, rather than simply
having an acceptable protocol for the analyses.
One commenter stated that EPA has not explained the appropriateness
of applying a bias test and adjustment factor to proposed Method 324,
when it has already satisfied the same standards for bias and precision
as the Ontario Hydro Method under EPA Method 301 of 40 CFR part 63.
Another commenter suggested that it does not make sense to subject Hg
monitors to a bias adjustment factor under 40 CFR part 75, appendix A,
section 7.6 when paired reference method trains are allowed to differ
by 10 percent RD, based on a flawed definition of RD. The commenter
asserted that it is not reasonable to suggest that a Hg monitor is
biased by comparing its readings to a pair of reference method tests
that can differ by 20 percent.
In view of the many comments received regarding a large number of
testing and QA provisions in proposed Method 324, EPA has decided to
revise and rename proposed Method 324 as 40 CFR part 75, appendix K in
the final rule. Based on comments received and experience gained from
field tests since proposal, 40 CFR part 75, appendix K retains certain
provisions and revises others in proposed Method 324 to include
detailed, performance-based criteria, QA standards and procedures for
sorbent trap monitoring systems. The final rule also revises both the
definition of a sorbent trap monitoring system in section 72.2 and the
general guidelines for sorbent trap monitoring system operation in 40
CFR 75.15, to be consistent with the requirements of 40 CFR part 75,
appendix K.
The final rule retains the annual RATA and bias test requirements
for sorbent trap monitoring systems, but the proposed quarterly RA
requirement has been withdrawn. The requirements to use paired traps
and flow proportional sampling have also been retained. Finally, the
ISO 9000 certification requirement for the laboratory performing the Hg
analyses has been replaced with a requirement for the laboratory to
either comply with ISO-17025 or to comply initially, and annually
thereafter, with the spike recovery study provision in section 10 of 40
CFR part 75, appendix K.
Several commenters recommended that EPA should require QA
procedures for sorbent traps that are more meaningful and reasonable
than the procedures in the SNPR. EPA agrees with these comments, and
based on the recommendations received, the final rule specifies such
procedures in 40 CFR part 75, appendix K. Many provisions of proposed
Method 324 have been included in 40 CFR part 75, appendix K, without
modification, but other provisions of the proposed Method have been
modified to employ a more performance-based approach and some new QA
procedures have been added to address concerns expressed by the
commenters. Some of the more significant differences between proposed
Method 324 and 40 CFR part 75, appendix K, are as follows:
40 CFR part 75, appendix K allows the use of any sample
recovery and analytical methods that are capable of quantifying the
total vapor phase Hg collected on the sorbent media. Candidate recovery
techniques include leaching, digestion, and thermal desorption.
Candidate analytical techniques include ultraviolet atomic fluorescence
(UV AF), ultraviolet atomic absorption (UV AA), and in-situ X-ray
fluorescence (XRF);
40 CFR part 75, appendix K, requires that each sorbent
trap be comprised of three equal sections, capable of being separately
analyzed. The first section is for sample collection, the second to
assess ``breakthrough,'' and the third to allow spiking with elemental
Hg for QA purposes;
40 CFR part 75, appendix K, specifies the frequency of dry
gas meter calibration and the appropriate calibration procedures;
40 CFR part 75, appendix K, requires ASTM sample handling
and chain of custody procedures to be followed;
Spiking of the third section of each trap with elemental
Hg is required before the data collection period begins;
The laboratory performing the analyses must demonstrate
the ability to recover and quantify Hg from the sorbent media; and
The measured Hg mass in the first and second sections of
each trap is adjusted, based on the percent recovery of Hg from the
third (``spiked'') section.
EPA believes that if these procedures are implemented, this will ensure
the quality of the data from sorbent trap systems.
The final rule retains the requirement to use paired sorbent traps.
The SNPR proposed the use of paired sorbent traps for the same basic
reason that paired Ontario Hydro trains are required for RATA testing,
i.e., it provides an important check on the quality of the data. The
proposed rule would have required the higher of the two Hg
concentrations obtained from the paired traps to be used for reporting.
However, the final rule requires the results from the two traps to be
averaged if paired concentrations agree within specified criteria, and
allows the results from one trap (if those results are valid) to be
reported in cases where the other trap is accidentally damaged, broken
or lost during transport and analysis. Thus, using paired sorbent traps
provides a relatively inexpensive means of ensuring against data loss
should one of the traps become lost or damaged.
The commenters generally objected to the proposed quarterly
relative accuracy testing of sorbent traps, believing it to be
unnecessary and costly. After consideration of recent field data
comparing the sorbent traps to Hg CEMS, EPA agrees that sorbent trap
systems should be treated more similarly to Hg CEMS. Therefore, the
final rule removes the quarterly RA requirement, and requires only that
an annual RATA be performed on a sorbent trap monitoring system.
One commenter objected to the proposed bias test requirement for
sorbent trap systems, citing the fact that proposed Method 324 had
satisfied the same standards for bias and precision as the Ontario
Hydro Method under EPA Method 301 of 40 CFR part 63. EPA does not agree
with this comment. The fact that proposed Method 324 met the bias and
precision requirements of Method 301 does not imply that Hg sorbent
traps will not exhibit low bias with respect to a Hg reference method
during a RATA. The bias test in section 7.6 of 40 CFR part 75, appendix
A is a one-tailed t-test, which, if failed, requires a bias adjustment
factor (BAF) to be applied to the subsequent emissions data.
EPA also does not agree with the commenter who stated that bias
adjustment is not appropriate for
[[Page 28639]]
sorbent trap systems because of the allowable 10 percent RD between the
paired reference method trains. The 40 CFR part 75 bias test determines
systematic error, not random error, whereas RD and relative accuracy
are metrics used to quantify random error in the measurement.
7. Mercury-Diluent Systems
Mercury-diluent monitoring systems (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 were allowed in the proposed
rule.
One commenter asked why the proposed Hg emissions units of
measurement are the same as NOX-diluent. The Hg
concentration measurements are orders of magnitude below NOX
emissions, thus applying a diluent correction with the additional
uncertainties of measurement further complicates the direct emissions
reporting uncertainties. Mercury is a resident pollutant in the fuel,
it can be measured, and measurement should parallel the same regulation
requirements as SO2.
The final rule removes all mention of Hg-diluent monitoring systems
and requires the hourly Hg mass emissions to be calculated in the same
manner as is done for SO2 under the Acid Rain Program, i.e.,
as the product of the Hg concentration and the stack gas flow rate. The
final rule also better accommodates Hg analyzers that measure on a wet
basis.
EPA believes that the rule, as proposed, can be considerably
simplified and shortened without losing any flexibility by deleting the
provisions related to Hg-diluent monitoring systems and allowing only
Hg concentration monitoring systems and sorbent trap systems to be
used. Therefore, the final rule removes all mention of Hg-diluent
monitoring systems and requires the hourly Hg mass emissions to be
calculated in the same manner as is done for SO2, i.e., as
the product of the Hg concentration and the stack gas flow rate.
V. Summary of the Environmental, Energy, Cost, and Economic Impacts
A. What Are the Air Quality Impacts?
EPA has assessed the change in the amount of Hg deposited in the
continental U.S. as a result of the final rule. The recently
promulgated CAIR significantly reduced utility attributable Hg
deposition. Both the selected CAMR approach and the regulatory
alternative result in small additional shifts in the overall
distribution of Hg deposition from utilities reactive to the CAIR
result. Table 2 of this preamble presents the frequency and cumulative
distributions of the reductions in deposition associated with the CAMR
requirements and the CAMR alternative. We also provide the reduction in
deposition from the 2020 base case with CAIR implemented relative to
the 2001 base case. This change (2001 Base--2020 CAIR) shows that there
are both increases and decreases in deposition. Negative reductions
(increases) are due to growth in non-utility Hg emissions, and growth
in utility emissions in areas unaffected by CAIR. Reductions in
deposition are largely due to the implementation of CAIR controls at
utilities.
Table 2.--Distributions of Reductions in Total Mercury Deposition
--------------------------------------------------------------------------------------------------------------------------------------------------------
2001 base--2020 base 2020 base (with CAIR)-- 2020 base (with CAIR)-- 2020 CAMP requirements--
(with CAIR) 2020 CAMR requirements 2020 CAMR requirements 2020 CAMR alternative
---------------------------
Range ([mu]g/m\2\) --------------------------------------------------------------------------------
Percent Cumulative Cumulative Cumulative Cumulative
percent Percent percent Percent percent Percent percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
<=0......................................... 6.59 6.59 2.13 2.13 0.83 0.83 0.28 0.28
0-1......................................... 58.02 64.61 97.03 99.17 97.87 98.70 99.58 99.86
1-2......................................... 12.06 76.67 0.83 100.00 1.30 100.00 0.14 100.00
2-3......................................... 7.33 84.00 0.00 100.00 0.00 100.00 0.00 100.00
3-4......................................... 5.10 89.10 0.00 100.00 0.00 100.00 0.00 100.00
4-5......................................... 3.71 92.81 0.00 100.00 0.00 100.00 0.00 100.00
5-10........................................ 6.08 98.89 0.00 100.00 0.00 100.00 0.00 100.00
10-15....................................... 0.88 99.77 0.00 100.00 0.00 100.00 0.00 100.00
15-20....................................... 0.23 100.00 0.00 100.00 0.00 100.00 0.00 100.00
--------------------------------------------------------------------------------------------------------------------------------------------------------
Source: Technical Support Document: Methodology Used to Generate Deposition, Fish Tissue Methylmercury Concentrations, and Exposure for Determining
Effectiveness of Utility Emission Controls
B. What Are the Non-Air Health, Environmental, and Energy Impacts?
According to EO 13211 ``Actions that Significantly Affect Energy
Supply, Distribution, or Use,'' the final rule is not significant,
measured incrementally to CAIR, because it does not have a greater than
a 1 percent impact on the cost of electricity production, and it does
not result in the retirement of greater than 500 MW of coal-fired
generation.
Several aspects of CAMR are designed to minimize the impact on
energy production. First, EPA recommends a trading program rather than
the use of command-and-control regulations. Second, compliance
deadlines are set cognizant of the impact that those deadlines have on
electricity production. Both of these aspects of CAMR reduce the impact
of the final rule on the electricity sector.
C. What Are the Cost and Economic Impacts?
The projected annual costs of CAMR to the power industry are $160
million in 2010, $100 million in 2015, and $750 million in 2020. These
costs represent the total cost to the electricity-generating industry
of reducing Hg emissions to meet the caps set forth in the final rule
and are incremental costs to the requirements to meet NOX
and SO2 emissions caps set forth in the CAIR. Estimates are
in 1999 dollars.
Retail electricity prices are projected to increase roughly 0.2
percent higher with CAMR in 2020 when compared to CAIR. Natural gas
prices are projected to increase by roughly 1.6 percent with CAMR in
2020 when compared to CAIR. There will be continued reliance on coal-
fired generation, which is projected to remain at roughly 50 percent of
total electricity generated and no coal-fired capacity projected to be
uneconomic to
[[Page 28640]]
maintain incremental to CAIR. As demand grows in the future, additional
coal-fired generation is projected to be built. As a result, coal
production for electricity generation is projected to increase from
2003 levels by about 13 percent in 2010 and 20 percent by 2020, and we
expect a small shift towards greater coal production in Appalachia and
the Interior coal regions of the country with CAMR compared to 2003.
Additional information on the cost and economic impacts of CAMR is
provided in the discussion under EO 12866 below.
VI. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review
Under EO 12866 (58 FR 51735, October 4, 1993), the Agency must
determine whether a regulatory action is ``significant'' and,
therefore, subject to Office of Management and Budget (OMB) review and
the requirements of the EO. The EO defines ``significant regulatory
action'' as one that is likely to result in a rule that may:
(1) Have an annual effect on the economy of $100 million or more or
adversely affect in a material way the economy, a sector of the
economy, productivity, competition, jobs, the environment, public
health or safety, or State, local, or Tribal governments or
communities;
(2) Create a serious inconsistency or otherwise interfere with an
action taken or planned by another agency;
(3) Materially alter the budgetary impact of entitlements, grants,
user fees, or loan programs or the rights and obligations of recipients
thereof; or
(4) Raise novel legal or policy issues arising out of legal
mandates, the President's priorities, or the principles set forth in
the EO.
In view of its important policy implications and potential effect
on the economy of over $100 million, the final rule has been judged to
be an economically ``significant regulatory action'' within the meaning
of the EO. As a result, the final rule was submitted to OMB for review,
and EPA has prepared an economic analysis of the final rule entitled
``Regulatory Impact Analysis of the Final Clean Air Mercury Rule''
(March 2005) (OAR-2002-0056).
CAMR is an example of environmental regulation that recognizes and
balances the need for energy diversity, reliability, and affordability.
1. What Economic Analyses Were Conducted for the Final Rule?
The analyses conducted for the final rule provide several important
analyses of impacts on public welfare. These include an analysis of the
social benefits, social costs, and net benefits of the regulatory
scenario. The economic analyses also address issues involving small
business impacts, unfunded mandates (including impacts for Tribal
governments), environmental justice, children's health, energy impacts,
and requirements of the Paperwork Reduction Act (PRA).
2. What Are the Benefits and Costs of the Final Rule?
a. Control Scenario. The final CAMR requires annual Hg reductions
for the power sector in 50 States, the District of Columbia, and in
Indian country. EPA considered the final CAIR for SO2 and
NOX requirements and all promulgated CAA requirements and
known State actions in the baseline used to develop the estimates of
benefits and costs for the final rule. A more complete description of
the reduction requirements and how they were calculated is described
earlier in this preamble.
CAMR was designed to achieve significant Hg emissions reductions
from the power sector in a much more cost-effective manner than a
facility-specific or unit-specific approach. EPA analysis has found
that the most cost-effective method to achieve the emissions reductions
targets is through a cap-and-trade system that States have the option
of adopting. States, in fact, can choose not to participate in the
optional cap-and-trade program. However, EPA believes that a cap-and-
trade system for the power sector is the best approach for reducing Hg
emissions and EPA's analysis assumes that States will adopt this more
cost effective approach.
b. Cost Analysis and Economic Impacts. For the final rule, EPA
analyzed the costs using the IPM. IPM is a dynamic linear programming
model that can be used to examine the economic impacts of air pollution
control policies for Hg, SO2, and NOX throughout
the contiguous U.S. for the entire power system. Documentation for IPM
can be found in the docket for the final rule or at http://www.epa.gov/airmarkets/epa-ipm.
CAMR calls for environmental improvement and emission reductions
from the power sector while recognizing the need to maintain energy
diversity and reliability.
The projected annual costs of CAMR to the power industry are $160
million in 2010, $100 million in 2015, and $750 million in 2020. These
costs represent the total cost to the electricity-generating industry
of reducing Hg emissions to meet the caps set forth in the final rule
and are incremental costs to the requirements to meet NOX
and SO2 emissions caps set forth in the CAIR. Estimates are
in 1999 dollars.
Retail electricity prices are projected to increase roughly 0.2
percent higher with CAMR in 2020 when compared to CAIR. Natural gas
prices are projected to increase by roughly 1.6 percent with CAMR in
2020 when compared to CAIR. There will be continued reliance on coal-
fired generation, which is projected to remain at roughly 50 percent of
total electricity generated and no coal-fired capacity projected to be
uneconomic to maintain incremental to CAIR. As demand grows in the
future, additional coal-fired generation is projected to be built. As a
result, coal production for electricity generation is projected to
increase from 2003 levels by about 13 percent in 2010 and 20 percent by
2020, and we expect a small shift towards greater coal production in
Appalachia and the Interior coal regions of the country with CAMR
compared to 2003.
c. Human Health and Welfare Benefit Analysis. The Hg emissions
reductions associated with implementing the final CAMR will produce a
variety of benefits. Mercury emitted from utilities and other natural
and man-made sources is carried by winds through the air and eventually
is deposited to water and land. In water, some Hg is transformed to
MeHg through biological processes. Methylmercury, a highly toxic form
of Hg, is the form of Hg of concern for the purpose of the final rule.
Once Hg has been transformed into MeHg, it can be ingested by the lower
trophic level organisms where it can bioaccumulate in fish tissue
(i.e., concentrations in predatory fish build up over the fish's entire
lifetime, accumulating in the fish tissue as predatory fish consume
other species in the food chain). Thus, fish and wildlife at the top of
the food chain can have Hg concentrations that are higher than the
lower species, and they can have concentrations of Hg that are higher
than the concentration found in the water body itself. Therefore, the
most common form of exposure to Hg for humans and wildlife is through
the consumption of Hg contained in predatory fish, such as: Shark,
swordfish, king mackerel, tilefish and recreationally caught bass,
perch, walleye or other freshwater fish species.
When humans consume fish containing MeHg, the ingested MeHg is
almost completely absorbed into the
[[Page 28641]]
blood and distributed to all tissues (including the brain).
In pregnant women, MeHg can be passed on to the developing fetus,
and at sufficient exposure may lead to a number of neurological effects
in children. Thus, children who are exposed to low concentrations of
MeHg prenatally may be at increased risk of poor performance on
neurobehavioral tests, such as those measuring attention, fine motor
function, language skills, visual-spatial abilities (like drawing), and
verbal memory. The effects from prenatal exposure can occur even at
doses that do not result in effects in the mother. A full discussion of
the neurological health effects of Hg is provided by the National
Research Council in ``Neurological Effects of Methylmercury.'' \8\ Some
subpopulations in the U.S. (e.g., certain Native Americans, Southeast
Asian Americans, recreational and subsistence anglers) consume larger
amounts of fish than the general population and may be at a greater
risk to the adverse health effects from Hg due to increased exposure.
---------------------------------------------------------------------------
\8\ National Research Council (NRC). 2000. Toxicological Effects
of Methylmercury. Committee on the Toxicological Effects of
Methylmercury, Board on Environmental Studies and Toxicology,
Commission on Life Sciences, National Research Council. National
Academy Press, Washington, DC.
---------------------------------------------------------------------------
EPA held a workshop with several of the National Research Council
(NRC) panel members in 2002. Participants were asked about which
studies should be considered in generating dose-response functions for
developmental neurotoxicity. Participants were also asked about
endpoints to consider for monetization, and they suggested looking at
neurological tests that might lead to changes in IQ or other
neurodevelopmental impacts. EPA determined that IQ decrements due to Hg
exposure is one endpoint that EPA should focus on for a benefit
analysis, because it can be monetized.\9\ The focus population for the
benefit analysis is women of childbearing age who consume freshwater,
recreationally-caught fish. Methylmercury is a developmental
neurotoxicant with greatest biological sensitivity from in utero
exposure.
---------------------------------------------------------------------------
\9\ See footnote 3 of chapter 11 of the RIA for an explanation
of the basis for the monetization.
---------------------------------------------------------------------------
Three large-scale epidemiological studies have examined the effects
of low dose prenatal Hg exposure and neurodevelopmental outcomes
through the administration of numerous tests of cognitive functioning.
These studies were conducted in the Faroe Islands (Grandjean et al.
1997), New Zealand (Kjellstrom et al. 1989, Crump et al. 1998), and the
Seychelles Islands (Davidson et al. 1998, Myers et al. 2003). Based on
recommendations from participants at the Hg workshop discussed above,
and the ability to monetize IQ decrements, EPA combined data and
information from all three of these studies to develop a combined dose-
response function for IQ decrements to apply in a benefit analysis.
CAMR may also reduce emissions of directly emitted PM, which
contribute to the formation of PM2.5. In general, exposure
to high concentrations of PM2.5 may aggravate existing
respiratory and cardiovascular disease including asthma, bronchitis and
emphysema, especially in children and the elderly. Exposure to
PM2.5 can lead to decreased lung function, and alterations
in lung tissue and structure and in respiratory tract defense
mechanisms which may then lead to, increased respiratory symptoms and
disease, or in more severe cases, premature death or increased hospital
admissions and emergency room visits. Children, the elderly, and people
with cardiopulmonary disease, such as asthma, are most at risk from
these health effects. PM2.5 can also form a haze that
reduces the visibility of scenic areas, can cause acidification of
water bodies, and have other impacts on soil, plants, and materials.
Due to both technical and resource limits in available modeling, we
have only been able to quantify and monetize the benefits for a few of
the endpoints associated with reducing Hg, and directly emitted PM. In
the ``Regulatory Impact Analysis of the Final Clean Air Mercury Rule,''
we provide an analysis of the benefits from avoided IQ decrements in
potentially prenatally exposed children from the reduction of MeHg
exposures and the benefits of reducing directly emitted PM.
There are several fish consumption pathways considered by the
Agency for the benefit analysis, including: Consumption from commercial
sources (including saltwater and freshwater fish from domestic and
foreign producers), consumption of commercial fish raised at fish farms
(aquaculture), and consumption of recreationally caught freshwater and
saltwater fish. As explained in the RIA, we believe that the focus of
the analysis on recreationally and subsistence caught freshwater fish
captures the bulk of the benefits. Nevertheless, we believe that the
analysis captures the bulk of the benefits.
To model recreational angling and prenatal exposure from this
consumption pathway (i.e., women of childbearing age consuming
freshwater fish and, hence, exposing the fetus in utero), we consider
two modeling approaches: One approach that estimates the distance
anglers are likely to travel from their households to water bodies for
fishing activities (referred to as the Population Centroid Approach),
and another approach that models how often recreational anglers fish at
certain locations (referred to as the Angler Destination Approach).
These resulting benefits from the two exposure modeling approaches
differ, however, we expected they are likely to capture the range of
actual behavior (and likely exposure) of recreational anglers.
This approach forms the core analytic underpinnings for the final
benefit numbers, but incorporates an assumption of no threshold, and,
therefore, reflects an upper-bound on the number of people affected by
Hg. A more simplified approach used to simulate exposure scenarios
under the assumption of two different thresholds. This threshold
analysis provides ``scaling factors,'' or benefits as a percent of the
no threshold case. We consider two benchmark levels of exposure
established by regulatory agencies as possible thresholds: (1) A
threshold equal to EPA's reference dose (RfD) of 0.1 micrograms per
kilogram per day (ug/kg-day) and (2) a threshold in the neighborhood of
the World Health Organization and Health Canada benchmarks of 0.23 and
0.2 ug/kg-day respectively. Scaling factors for the no threshold
benefits from the more detailed analysis range from 4 percent to 34
percent. The final estimates of IQ-related benefits are arrayed in a
hierarchy from most certain to less certain benefits.
In addition, the current state of knowledge of the science
indicates that there is likely a lag in the time between the reduction
in Hg deposition to a water body and the change in MeHg concentrations
in fish tissue. Based on a review of available literature and a series
of case studies conducted by EPA, the lag period for changes in fish
tissue (and hence changes in avoided IQ decrements) can range from less
than 5 years to more than 50 years, with an average time span of 1 to 3
decades (10 to 30 years). In the benefit analysis presented in the RIA,
we present a range of results assuming a series of potential lag
scenarios (including 5, 10, 20, and 50 years) on the total benefits.
The 10- and 20-year lag periods are presented as the likely outcome of
results from the analysis, while the 5- and 50-year lag periods are
presented to show the outcomes if the time span to steady-state
[[Page 28642]]
is less than or more than the average lag periods observed in the case
studies.
We also present future year benefits discounted at a 3 percent and
a 7 percent rate. In addition, due to the potential for
intergenerational effects, the 50 year lag is assessed using a 1
percent discount rate as well as the 3 and 7 percent discount rates (in
accordance with the EPA Economic Guidelines). Benefits are evaluated
after full implementation of CAMR (in 2020, 2 years after imposition of
the Phase II cap) and presented in 1999 dollars. The resulting benefits
presented in the RIA show a range of potential values based on all of
these sources of variability in the estimate.
Giving consideration to all of the possible outcomes discussed in
the RIA, the range of annual monetized benefits of CAMR under a 10- to
20-year lag period are approximately $0.4 million to $3.0 million using
a 3 percent discount rate (or $0.2 million to $2.0 million using a 7
percent discount rate).
In addition to the benefits of reducing exposures to MeHg from
recreational freshwater angling, there are several additional benefits
that may be associated with reduced exposures to MeHg; however, the
literature with regard to these effects is less developed than the
literature for childhood neurodevelopmental effects.\10\ Because of the
uncertainty associated with these effects, and, in most cases, the lack
of sufficient data to evaluate whether or not these effects are present
at levels associated with U.S. exposures, we did not quantify these
benefits. Most notably these effects include:
---------------------------------------------------------------------------
\10\ It should no noted that the degree of uncertainty
associated with these effects varies as does our knowledge about
whether the effects are seen at levels consistent with those in the
U.S.
---------------------------------------------------------------------------
Cardiovascular effects--Some recent epidemiological
studies in men suggest that MeHg is associated with a higher risk of
acute myocardial infarction, coronary heart disease and cardiovascular
disease in some populations. Other recent studies have not observed
this association. The studies that have observed an association suggest
that the exposure to MeHg may attenuate the beneficial effects of fish
consumption. The findings to date and the plausible biologic mechanisms
warrant additional research in this arena (Stern 2005; Chan and Egeland
2004).
Ecosystem effects--Plant and aquatic life, as well as
fish, birds, and mammalian wildlife can be affected by Hg exposure;
however overarching conclusions about ecosystem health and population
effects are difficult to make at this time.
Other effects--There is some recent evidence that
exposures of MeHg may result in genotoxic or immunotoxic effects. Other
research with less corroboration suggest that reproductive, renal, and
hematological impacts may be of concern. Overall, there is a relatively
small body of evidence from human studies that suggests exposure to
MeHg can result in immunotoxic effects and the NRC concluded that
evidence that human exposure caused genetic damage is inconclusive.
There are insufficient human data to evaluate whether these effects are
consistent with levels in the U.S. population. See chapter 2 of the
RIA.
In an analysis of the possible co-benefits associated with emission
reductions of directly emitted PM, we estimated the total change in
incidence of premature mortality. We conducted an illustrative analysis
using a simplified air quality and exposure modeling approach (the
Source-Receptor Matrix) to derive a benefit transfer value (i.e., $
benefit per ton PM) that were applied to total estimate emission
reductions of direct PM. The total estimated PM-related benefits are
approximately $1.4 million to $40 million; however, the calculation of
these benefits is highly dependent on uncertain future technology
choices of the industry. Because of this significant uncertainty,
therefore, these benefit estimates are not included in our primary
benefit estimate.
In response to potential risks of consuming fish containing
elevated concentrations of Hg, EPA and the U.S. Food and Drug
Administration (FDA) have issued a joint fish consumption advisory
which provides recommended limits on consumption of certain fish
species (shark, swordfish, king mackerel, tilefish) for different
populations. This joint EPA and FDA advisory recommends that women who
may become pregnant, pregnant women, nursing mothers, and young
children to avoid some types of fish and eat fish and shellfish that
are lower in Hg, diversifying the types of fish they consume, and by
checking any local advisories that may exist for local rivers and
streams.
3. How Do the Benefits Compare to the Costs of the Final Rule?
The costs presented above are EPA's best estimate of the direct
private costs of the CAMR. In estimating the net benefits of regulation
(benefits minus costs), the appropriate cost measure is ``social
costs.'' Social costs represent the total welfare costs of the rule to
society. These costs do not consider transfer payments (such as taxes)
that are simply redistributions of wealth. Using these alternate
discount rates, the social costs of the final rule are estimated to be
approximately $848 million in 2020 when assuming a 3 percent discount
rate. These costs become $896 million in 2020 if one assumes a 7
percent discount rate. The costs of the CAMR using the adjusted
discount rates differ from the private costs of the CAMR generated
using IPM because the social costs do not include certain transfer
payments, primarily taxes, that are considered a redistribution of
wealth rather than a social cost.
As is discussed above, the total social benefits that EPA was able
to monetize in the RIA total $0.4 million to $3.0 million using a 3
percent discount rate, and $0.2 million to $2.0 million using a 7
percent discount rate.
Thus, the annual monetized net benefit in 2020 (social benefits
minus social costs) of the CAMR program is approximately -$846 million
or -$895 million (using 3 percent and 7 percent discount rates,
respectively) annually in 2020. Although the final rule is expected to
result in a net cost to society, it achieves a significant reduction in
Hg emissions by domestic sources. In addition, the cost of reduced
earnings borne by U.S. citizens from Hg exposure falls
disproportionately on prenatally exposed children of populations who
consume larger amounts of recreationally caught freshwater fish than
the general population.
The annualized cost of the CAMR, as quantified here, is EPA's best
assessment of the cost of implementing the CAMR, assuming that States
adopt the model cap-and-trade program. These costs are generated from
rigorous economic modeling of changes in the power sector due to the
CAMR. This type of analysis using IPM has undergone peer review and
been upheld in Federal courts. The direct cost includes, but is not
limited to, capital investments in pollution controls, operating
expenses of the pollution controls, investments in new generating
sources, and additional fuel expenditures. The EPA believes that these
costs reflect, as closely as possible, the additional costs of the CAMR
to industry. The relatively small cost associated with monitoring
emissions, reporting, and recordkeeping for affected sources is not
included in these annualized cost estimates, but EPA has done a
separate analysis and estimated the cost to less than $76 million.
However, there may exist certain costs that EPA has not quantified in
these estimates. These costs may include costs of transitioning to the
CAMR, such as
[[Page 28643]]
employment shifts as workers are retrained at the same company or re-
employed elsewhere in the economy, and certain relatively small
permitting costs associated with title IV that new program entrants
face. Costs may be understated since an optimization model was employed
that assumes cost minimization, and the regulated community may not
react in the same manner to comply with the final rule. Although EPA
has not quantified these costs, the Agency believes that they are small
compared to the quantified costs of the program on the power sector.
The annualized cost estimates presented are the best and most accurate
based upon available information.
Table 3.--Summary of Annual Benefits, Costs, and Net Benefits of the
CAMR \a\
[billions of 1999 dollars]
------------------------------------------------------------------------
2020 (millions
Description of 1999
dollars)
------------------------------------------------------------------------
Social Costs: \c\
3 percent discount rate............................ $848.0
7 percent discount rate............................ 896.0
Social Benefits b, c
3 percent discount rate:
EPA RfD........................................ 0.4-1.0
No Threshold................................... 1.7-3.0
7 percent discount rate:
EPA RfD........................................ 0.2-0.7
No Threshold................................... 0.8-2.0
--------------------------------------------------------
Unquantified benefits and costs U
--------------------------------------------------------
Annual Net Benefits (Benefits-Costs): c, d
3 percent discount rate:
EPA RfD........................................ -848 + U
No Threshold................................... -846 + U
7 percent discount rate:
EPA RfD........................................ -896 + U
No Threshold................................... -895 + U
------------------------------------------------------------------------
\a\ All estimates are rounded to first significant digits and represent
annualized benefits and costs anticipated in 2020.
\b\ Not all possible benefits are quantified and monetized in this
analysis. B is the sum of all unquantified benefits. Potential benefit
categories that have not been quantified and monetized are listed in
section 10 of the RIA.
\c\ Results reflect 3 percent and 7 percent discount rates consistent
with EPA and OMB guidelines for preparing economic analyses (U.S. EPA,
2000, and OMB, 2003).\11\
\d\ Net benefits are rounded to the nearest $100 million. Columnar
totals may not sum due to rounding.
Every benefit-cost analysis examining the potential effects of a
change in environmental protection requirements is limited to some
extent by data gaps, limitations in model capabilities (such as
geographic coverage), and uncertainties in the underlying scientific
and economic studies used to configure the benefit and cost models.
Gaps in the scientific literature often result in the inability to
estimate quantitative changes in health and environmental effects. Gaps
in the economics literature often result in the inability to assign
economic values even to those health and environmental outcomes that
can be quantified. Although uncertainties in the underlying scientific
and economics literature (that may result in overestimation or
underestimation of benefits) are discussed in detail in the economic
analyses and its supporting documents and references, the key
uncertainties which have a bearing on the results of the benefit-cost
analysis of the final rule include the following:
---------------------------------------------------------------------------
\11\ United States Environmental Protection Agency, 2000.
Guidelines for Preparing Economic Analyses. http://www.yosemite1.epa.gov/ee/epa/eed/hsf/pages/Guideline.html. Office of
Management and Budget, The Executive Office of the President, 2003.
Circular A-4. http://www.whitehouse.gov/omb/circulars.
---------------------------------------------------------------------------
EPA's inability to quantify potentially significant
benefit categories;
Uncertainties in population growth and baseline incidence
rates;
Uncertainties in projection of emissions inventories and
air quality into the future;
Uncertainty in the estimated relationships of health and
welfare effects to changes in pollutant concentrations;
Uncertainties in exposure estimation; and
Uncertainties associated with the effect of potential
future actions to limit emissions.
Despite these uncertainties, we believe the benefit-cost analysis
provides a reasonable indication of the expected economic benefits of
the final rule in future years under a set of reasonable assumptions.
The benefits estimates generated for the final rule are subject to
a number of assumptions and uncertainties, that are discussed
throughout the ``Regulatory Impact Analysis for the Final Clean Air
Mercury Rule'' (March 2005) (OAR-2002-0056).
B. Paperwork Reduction Act
The information collection requirements in the final rule will be
submitted for approval to OMB under the Paperwork Reduction Act, 44
U.S.C. 3501 et seq. The information collection requirements are not
enforceable until OMB approves them.
The information requirements are based on notification,
recordkeeping and reporting requirements in the NSPS. The recordkeeping
and reporting requirements are specifically authorized by CAA section
114 (42 U.S.C. 7414) and are, therefore, mandatory. All information
submitted to EPA pursuant to the recordkeeping and reporting
requirements for which a claim of confidentiality is made is
safeguarded according to Agency policies set forth in 40 CFR.
The EPA is still working on the projected cost and hour burden for
information requirements mandated by the NSPS. Those estimates will be
[[Page 28644]]
provided to OMB and notice of their availability provided to the public
when they are completed. The information requirements mandated by the
NSPS requirements for existing sources will be essentially the same as
those for CAIR. The ICR for CAIR has been designated as EPA ICR number
2137.01. The EPA will, nevertheless, provide a full estimate of the
projected cost and hour burden for those information requirements to
OMB and provide the public with notice of the availability of that
information. Burden means the total time, effort, or financial
resources expended by persons to generate, maintain, retain, or
disclose or provide information to or for a Federal agency. This
includes the time needed to review instructions; develop, acquire,
install, and utilize technology and systems for the purposes of
collecting, validating, and verifying information, processing and
maintaining information, and disclosing and providing information;
adjust the existing ways to comply with any previously applicable
instructions and requirements; train personnel to be able to respond to
a collection of information; search data sources; complete and review
the collection of information; and transmit or otherwise disclose the
information.
An agency may not conduct or sponsor, and a person is not required
to respond to a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for EPA's
regulations in 40 CFR are listed in 40 CFR part 9. When the ICR is
approved by OMB, the Agency will publish a technical amendment to 40
CFR part 9 in the Federal Register to display the OMB control number
for the approved information collection requirements contained in the
final rule.
C. Regulatory Flexibility Act
The Regulatory Flexibility Act (5 U.S.C. 601 et seq.) (RFA), as
amended by the Small Business Regulatory Enforcement Fairness Act (Pub.
L. 104-121) (SBREFA), provides that whenever an agency is required to
publish a general notice of rulemaking, it must prepare and make
available an initial regulatory flexibility analysis, unless it
certifies that the rule, if promulgated, will not have ``a significant
economic impact on a substantial number of small entities.'' (See 5
U.S.C. section 605(b).) Small entities include small businesses, small
organizations, and small governmental jurisdictions.
As was discussed in the January 30, 2004 NPR and the March 16, 2004
SNPR, EPA determined that it was not necessary to prepare a regulatory
flexibility analysis in conjunction with the final rule. EPA also
announced in the NPR its determination that, based on analysis
conducted for the proposed rule, CAMR would not have a significant
impact on a substantial number of small entities. Although not required
by the RFA, the Agency has conducted an additional analysis of the
effects of CAMR on small entities in order to provide additional
information to States and affected sources.
For purposes of assessing the impacts of the final rule on small
entities, small entity is defined as: (1) A small business that is
identified by the NAICS Code, as defined by the Small Business
Administration (SBA); (2) a small governmental jurisdiction that is a
government of a city, county, town, school district, or special
district with a population of less that 50,000; and (3) a small
organization that is any not-for-profit enterprise which is
independently owned and operated and is not dominant in its field.
Categories and entities potentially regulated by the final rule with
applicable NAICS codes are provided in the Supplementary Information
section of this action.
According to the SBA size standards for NAICS code 221122
Utilities-Fossil Fuel Electric Power Generation, a firm is small if,
including its affiliates, it is primarily engaged in the generation,
transmission, and or distribution of electric energy for sale and its
total electric output for the preceding fiscal year did not exceed 4
million MWh.
Courts have interpreted the RFA to require a regulatory flexibility
analysis only when small entities will be subject to the requirements
of the rule. (See Michigan v. EPA, 213 F.3d 663, 668-69 (DC Cir. 2000),
cert. den. 121 S.Ct. 225, 149 L.Ed.2d 135 (2001).)
The final rule would not establish requirements applicable to small
entities, other than those that are new sources subject to NSPS. We
believe that there will not by any such small entities subject to the
final rule because the IPM projects no new construction of coal-fired
utility units. Additionally, the CAMR rule does not establish
requirements applicable to small entities because the final rule
requires States to develop, adopt, and submit a State Plan that would
achieve the necessary Hg emissions reductions, and would leave to the
States the task of determining how to obtain those reductions,
including which Utility Units to regulate.
EPA's analysis of the final rule supports the results of the
earlier analysis discussed in the NPR that found that CAMR would not
have a significant direct impact on a substantial number of small
entities, although there could be an increase in their costs of
electricity. Analysis conducted for the final rule projects that in
2020, 2 years into the start of the second phase of the cap-and-trade
program, the total compliance costs to small entities under CAMR would
be approximately $37 million. This is just under 1 percent of the total
projected electricity generation revenues to small entities for 2020. A
few of the 80 small entities identified in EPA's analysis may
experience significant costs in 2020. These entities do not bank over
the course of the program, and must purchase allowances in 2020 to
cover their emissions. It is important to note that the marginal cost
of Hg control in 2020 projected by EPA modeling is largely responsible
for the presence of significant impacts. EPA's modeling assumes no
improvements in the cost or effectiveness of Hg control technology over
time. In reality, by 2020, costs of Hg control are expected to have
declined, such that the actual impacts of the cap-and-trade program on
small entities will be less than projected. Additionally, given that
most of the small entities identified operate in market environments in
which they can pass on compliance costs to consumers, most of these
entities should be able to recover their costs of compliance with CAMR.
Two other points should be considered when evaluating the impact of
CAMR, specifically, and cap-and-trade programs more generally, on small
entities. First, under CAMR, the cap-and-trade program is designed such
that States determine how Hg allowances are to be allocated across
units. A State that wishes to mitigate the impact of the final rule on
small entities might choose to allocate Hg allowances in a manner that
is favorable to small entities. Finally, the use of cap-and-trade in
general will limit impacts on small entities relative to a less
flexible command-and-control program.
D. Unfunded Mandates Reform Act
Title II of the Unfunded Mandates Reform Act of 1995 (Pub. L. 104-
4) (UMRA), establishes requirements for Federal agencies to assess the
effects of their regulatory actions on State, local, and Tribal
governments and the private sector. Under UMRA section 202, 2 U.S.C.
1532, EPA generally must prepare a written statement, including a cost-
benefit analysis, for any proposed or final rule that ``includes any
Federal mandate that may result in the expenditure by State, local, and
Tribal governments, in the aggregate, or by the private sector, of
$100,000,000 or more
[[Page 28645]]
* * * in any one year.'' A ``Federal mandate'' is defined under section
421(6), 2 U.S.C. 658(6), to include a ``Federal intergovernmental
mandate'' and a ``Federal private sector mandate.'' A ``Federal
intergovernmental mandate,'' in turn, is defined to include a
regulation that ``would impose an enforceable duty upon State, local,
or Tribal governments,'' section 421(5)(A)(i), 2 U.S.C. 658(5)(A)(i),
except for, among other things, a duty that is ``a condition of Federal
assistance,'' section 421(5)(A)(i)(I). A ``Federal private sector
mandate'' includes a regulation that ``would impose an enforceable duty
upon the private sector,'' with certain exceptions, section 421(7)(A),
2 U.S.C. 658(7)(A).
Before promulgating an EPA rule for which a written statement is
needed under UMRA section 202, UMRA section 205, 2 U.S.C. 1535,
generally requires EPA to identify and consider a reasonable number of
regulatory alternatives and adopt the least costly, most cost-
effective, or least burdensome alternative that achieves the objectives
of the rule.
The EPA prepared a written statement for the final rule consistent
with the requirements of UMRA section 202. Furthermore, as EPA stated
in the final rule, EPA is not directly establishing any regulatory
requirements that may significantly or uniquely affect small
governments, including Tribal governments. Thus, EPA is not obligated
to develop under UMRA section 203 a small government agency plan.
Furthermore, in a manner consistent with the intergovernmental
consultation provisions of UMRA section 204, EPA carried out
consultations with the governmental entities affected by the final
rule.
For the final rule, EPA has conducted an analysis of the potential
economic impacts anticipated of CAMR on government-owned entities.
These results support EPA's assertion in the NPR that the proposed rule
would not have a disproportionate budgetary impact on government
entities. Overall, analysis conducted for the final rule projects that
in 2020, 2 years into the start of the second phase of the cap-and-
trade program, compliance costs to government-owned entities would be
approximately $48 million. This cost is less than one-half of 1 percent
of projected electricity generation revenues for these entities in
2020. A few of the 88 entities identified in EPA analysis are projected
to experience significant costs in 2020. These entities do not bank
over the course of the program, and must purchase allowances in 2020 to
cover their emissions. As was the case in EPA's analysis of small
entities, it is important to note that the marginal cost of Hg control
in 2020 projected by EPA modeling is largely responsible for the
presence of significant impacts in the analysis. EPA modeling assumes
no improvements in the cost or effectiveness of Hg control technology
over time. In reality, by 2020, costs of Hg control are expected to
have declined, such that the impacts of the cap-and-trade program on
small entities would be reduced. Additionally, given that most of the
small entities identified operate in market environments in which they
can pass on compliance costs to consumers, most of these entities
should be able to recover their costs of compliance with CAMR.
Potentially adverse impacts of CAMR on State and municipality-owned
entities could be limited by the fact that the cap-and-trade program is
designed such that States determine how Hg allowances are to be
allocated across units. A State that wishes to mitigate the impact of
the final rule on State or municipality-owned entities might choose to
allocate Hg allowances in a manner that is favorable to these entities.
Finally, the use of cap-and-trade in general will limit impacts on
entities owned by small governments relative to a less flexible
command-and-control program.
EPA has determined that the final rule may result in expenditures
of more than $100 million to the private sector in any single year. EPA
believes that the final rule represents the least costly, most cost-
effective approach to achieve the air quality goals of the final rule.
The costs and benefits associated with the final rule are discussed
above and in the RIA.
As noted earlier, however, EPA prepared for the final rule the
statement that would be required by UMRA if its statutory provisions
applied, and EPA has consulted with governmental entities as would be
required by UMRA. Consequently, it is not necessary for EPA to reach a
conclusion as to the applicability of the UMRA requirements.
E. Executive Order 13132: Federalism
EO 13132 (64 FR 43255, August 10, 1999) requires EPA to develop an
accountable process to ensure ``meaningful and timely input by State
and local officials in the development of regulatory policies that have
federalism implications.'' ``Policies that have federalism
implications'' is defined in the EO to include regulations that have
``substantial direct effects on the States, on the relationship between
the national government and the States, or on the distribution of power
and responsibilities among the various levels of government.''
The final rule does not have federalism implications. It will not
have substantial direct effects on the States, on the relationship
between the national government and the States, or on the distribution
of power and responsibilities among the various levels of government,
as specified in EO 13132. The CAA establishes the relationship between
the Federal government and the States, and the final rule does not
impact that relationship. Thus, EO 13132 does not apply to the final
rule. In the spirit of EO 13132, and consistent with EPA policy to
promote communications between EPA and State and local governments, EPA
specifically solicited comment on the rule, as proposed, from State and
local officials.
F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
EO 13175 (65 FR 67249, November 9, 2000) requires EPA to develop an
accountable process to ensure ``meaningful and timely input by Tribal
officials in the development of regulatory policies that have Tribal
implications.'' The final rule does not have ``Tribal implications'' as
specified in EO 13175 because it does not have a substantial direct
effect on one or more Indian Tribes. No Tribe has implemented a
federally enforceable air quality management program under the CAA at
this time. Furthermore, the final rule does not affect the relationship
or distribution of power and responsibilities between the Federal
government and Indian Tribes. The CAA and the Tribal Authority Rule
(TAR) (40 CFR 49.1 through 49.11) establish the relationship of the
Federal government and Tribes in developing plans to attain the
national ambient air quality standards (NAAQS), and the final rule does
nothing to modify that relationship. Because the final rule does not
have Tribal implications, EO 13175 does not apply.
The final rule addresses pollution composed of Hg and mercuric
compounds. The final CAMR requires annual Hg reductions for the power
sector in 50 States, the District of Columbia, and in Indian country,
through a cap-and-trade system that States and eligible Tribes have the
option of adopting. The CAA provides for States and eligible Tribes to
develop plans to regulate emissions of air pollutants within their
areas. The regulations clarify the statutory obligations of States and
eligible Tribes that develop plans to implement the
[[Page 28646]]
final rule. The TAR gives eligible Tribes the opportunity to develop
and implement CAA programs, but it leaves to the discretion of the
Tribe whether to develop these programs and which programs, or
appropriate elements of a program, the Tribe will adopt. As noted
earlier, the EPA will implement the emission trading rule for coal-
fired Utility Units located in Indian Country in accordance with the
TAR unless the relevant Tribe for the land on which a particular coal-
fired Utility Unit is located seeks and obtains TAS status and submits
a TIP to implement the allocated Hg emissions budget. Tribes which
choose to do so will be responsible for submitting a TIP analogous to
the State Plans discussed throughout this preamble, and, like States,
can chose to adopt the model cap-and-trade rule described elsewhere in
this action.
EPA notes that in the event a Tribe does implement a TIP in the
future, the final rule could have implications for that Tribe, but it
would not impose substantial direct costs upon the Tribe, nor preempt
Tribal law. As provided above, EPA has estimated that the total annual
private costs for the final rule for Hg as implemented by State, local,
and eligible Tribal governments (or EPA in the absence of any Tribe
seeking TAS status) is approximately $160 million in 2010, $100 million
in 2015, and $750 million in 2020 (1999$). There are currently three
coal-fired Utility Units located in Indian country that will be
affected by the final rule and the percentage of Indian country that
will be impacted is very small. For eligible Tribes that choose to
regulate sources in Indian country, the costs would be attributed to
inspecting regulated facilities and enforcing adopted regulations.
EPA consulted with Tribal officials in developing the final rule.
The EPA encouraged Tribal input at an early stage. A Tribal
representative from the Navajo Nation was a member the official
workgroup and was provided with all workgroup materials. The EPA has
provided two briefings for Tribal representatives and the newly formed
National Tribal Air Association (NTAA), and other national Tribal
forums such as the National Tribal Environmental Council (NTEC) and the
National Tribal Forum during the period prior to issuance of the NPR.
Another briefing for Tribal representatives, NTAA, and NTEC was
provided post-proposal to provide opportunity for additional input.
Input from Tribal representatives has been taken into consideration in
development of the final rule.
G. Executive Order 13045: Protection of Children From Environmental
Health and Safety Risks
EO 13045 (62 FR 19885, April 23, 1997) applies to any rule that (1)
is determined to be ``economically significant'' as defined under EO
12866, and (2) concerns an environmental health or safety risk that EPA
has reason to believe may have a disproportionate effect on children.
If the regulatory action meets both criteria, Section 5-501 of the EO
directs the Agency to evaluate the environmental health or safety
effects of the planned rule on children, and explain why the planned
regulation is preferable to other potentially effective and reasonably
feasible alternatives considered by the Agency.
The final rule is subject to the EO because it is an economically
significant regulatory action as defined by EO 12866, and we believe
that the environmental health or safety risk addressed by this action
may have a disproportionate effect on children. Accordingly, we have
evaluated the environmental health or safety effects of the final rule
on children. The results of this evaluation are discussed elsewhere in
this preamble and the RIA, and are contained in the docket.
As discussed in the RIA, EPA and the NRC of the National Academy of
Science (NAS) identified neurodevelopmental effects as the most
sensitive endpoints (NRC 2000) and, thus, the appropriate endpoint upon
which to establish a health-based standard establishing the level of
exposure to MeHg that would result in a nonappreciable risk. As such,
EPA has established its health-based ingestion rate, or RfD at a level
designed to protect children prenatally exposed to MeHg. The RfD is an
estimate (with uncertainty spanning perhaps an order of magnitude) of a
daily exposure to the human population (including sensitive subgroups)
that is likely to be without an appreciable risk of deleterious effects
during a lifetime (EPA 2002). EPA believes that exposures at or below
the RfD are unlikely to be associated with appreciable risk of
deleterious effects. It is important to note, however, that the RfD
does not define an exposure level corresponding to zero risk; Hg
exposure near or below the RfD could pose a very low level of risk
which EPA deems to be non-appreciable. It is also important to note
that the RfD does not define a bright line, above which individuals are
at risk of adverse effect. CAMR benefits prenatally exposed children by
contributing to the reduction in the number of women of childbearing
age who ingest Hg at a rate that exceeds the RfD due solely to power
plants and by contributing the to the overall reduction in exposure to
MeHg of women of childbearing age.
In order to protect prenatally exposed children, it is appropriate
to focus on reducing MeHg exposure for women of childbearing age. In
the U.S., the primary means of exposure to MeHg is through the
consumption of fish containing MeHg. When emitted, Hg deposits in water
bodies where bacteria in the sediment can convert that Hg in the MeHg
which can then bioaccumulate in fish. By reducing the amount of Hg
deposition, CAMR reduces the amount of Hg that is available for
methylation, which in turn reduces the amount that can be taken up by
fish and then consumed by women of childbearing age. This chain of
events ultimately reduces exposure to the developing fetus. Thus, CAMR
is specifically targeted at protecting children in their most
vulnerable phase--during fetal development.
EPA's ability to reduce exposure by reducing Utility Unit emissions
is limited by the fact that emissions from U.S. Utility Units are only
one source of domestic Hg deposition. Further, the impact of U.S.
Utility Unit emissions on fish tissue MeHg concentrations is not likely
to be as significant for marine species, which on average accounts for
about 63 percent of consumption for the U.S. general population and 60
percent of consumption for U.S. women of childbearing age.
Nevertheless, EPA chose a regulatory approach that required Hg-specific
reductions of Utility Unit emissions by setting a cap on total
emissions in 2018. This Hg-specific cap, combined with the co-benefits
associated with reductions of SO2 and NOX
required by EPA's CAIR, will provide for reduction in MeHg exposure to
U.S. women of childbearing age.
CAMR will reduce the level of exposures to children from current
levels today. In section 11 of the RIA, we estimate that 529,000 to
825,000 children will be exposed to MeHg prenatally in 2020. Our RIA
analyses assess how IQ decrements, which were used as a surrogate
representing the neurodevelopmental effects of MeHg exposure, will be
reduced as a result of CAMR. Because these analyses only quantitatively
assess benefits in terms of IQ loss, the overall quantified benefit to
the prenatally exposed children is likely to be understated. Compared
to the other regulatory alternative considered during the final rule,
the selected approach delivers about the same amount of benefits at a
lower cost.
[[Page 28647]]
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
EO 13211 (66 FR 28355, May 22, 2001) provides that agencies shall
prepare and submit to the Administrator of the Office of Regulatory
Affairs, OMB, a Statement of Energy Effects for certain actions
identified as ``significant energy actions.'' Section 4(b) of EO 13211
defines ``significant energy actions'' as any action by an agency
(normally published in the Federal Register) that promulgates or is
expected to lead to the promulgation of a final rule or regulation,
including notices of inquiry, advance notices of final rulemaking, and
notices of final rulemaking: (1)(i) That is a significant regulatory
action under EO 12866 or any successor order, and (ii) is likely to
have a significant adverse effect on the supply, distribution, or use
of energy; or (2) that is designated by the Administrator of the Office
of Information and Regulatory Affairs as a ``significant energy
action.'' Although the final rule is a significant regulatory action
under EO 12866, the final rule likely will not have a significant
adverse effect on the supply, distribution, or use of energy.
CAMR, in conjunction with CAIR, has the potential to require
installation of significant amounts of control equipment at power
plants that are integral to the country's electric power supply, and,
in light of this, EPA has focused on minimizing the impacts of CAMR
throughout the development of the final rule. The final rule uses cost-
effective, market-based mechanisms while providing regulatory certainty
and sufficient time to achieve reductions of Hg emissions from the
power sector in a way that will help the country maintain electric
reliability and affordability while ensuring environmental goals are
met. In addition, Hg reductions have been coordinated with the CAIR,
with the first phase reductions set at a cap level that reflects the Hg
reductions that would be achieved from the SO2 and
NOX cap levels under CAIR. Although the Administration has
sought multi-pollutant legislation, like the Clear Skies Act, EPA has
acted in accordance with the CAA to ensure substantial reduction of
pollution to protect human health and welfare.
EPA has conducted the analysis of the final rule assuming States
participate in a cap-and-trade program to reduce emissions from Utility
Units. EPA does not believe that the final rule will have any impacts
incremental to CAIR that exceed the significance criteria, because it
does not have a greater than a 1 percent impact on the cost of
electricity production, and it does not result in the retirement of
greater than 500 MW of coal-fired generation.
In addition, the EPA believes that a number of features of the
final rule serve to reduce its impact on energy supply. First, the
optional trading program provides considerable flexibility to the power
sector and enables industry to comply with the emission reduction
requirements in the most cost-effective manner, thus minimizing overall
costs and the ultimate impact on energy supply. The ability to use
banked allowances from the first phase of the program also provides
additional flexibility. Second, the CAMR caps are set in two phases,
provide adequate time for Utility Units to install pollution controls,
and Hg reductions have been coordinated with the CAIR, with the first
phase reductions set at a cap level that reflects the Hg reductions
that would be achieved from the SO2 and NOX cap
levels under CAIR.
For more details concerning energy impacts, see ``Regulatory Impact
Analysis for the Final Clean Air Mercury Rule'' (March 2005) (OAR-2002-
0056).
I. National Technology Transfer and Advancement Act
Section 12(d) of the National Technology Transfer and Advancement
Act (NTTAA) of 1995 (Pub. L. 104-113; Section 12(d), 15 U.S.C. 272
note) directs EPA to use voluntary consensus standards (VCS) in their
regulatory and procurement activities unless to do so would be
inconsistent with applicable law or otherwise impractical. Voluntary
consensus standards are technical standards (e.g., materials
specifications, test methods, sampling procedures, business practices)
developed or adopted by one or more voluntary consensus bodies. NTTAA
directs EPA to provide Congress, through annual reports to OMB, with
explanations when an agency does not use available and applicable VCS.
The final rule involves technical standards. The EPA methods cited
in the final rule are: 1, 1A, 2, 2A, 2C, 2D, 2F, 2G, 2H, 3, 3A, 3B, 4,
6, 6A, 6C, 7, 7A, 7C, 7D, 7E, 19, 20, and 29 (for Hg only) of 40 CFR
part 60, appendix A; PS 2 and 12A of 40 CFR part 60, appendix B; 40 CFR
part 75, appendix K; and ASTM D6784-02, ``Standard Test Method for
Elemental, Oxidized, Particle-Bound and Total Mercury Gas Generated
from Coal-Fired Stationary Sources (Ontario Hydro Method).''
Consistent with the NTTAA, EPA conducted searches to identify VCS
in addition to these EPA methods/performance specifications. No
applicable VCS were identified for EPA Method 1A, 2A, 2D, 2F, 2G, 2H,
7D, and 19, of 40 CFR part 60, appendix A; 40 CFR part 75, appendix K;
and ASTM D6784-02. The search and review results have been documented
and are placed in the docket for the final rule.
One VCS was identified as an acceptable alternative for the EPA
methods cited in the final rule. The VCS ASME PTC 19-10-1981-Part 10,
``Flue and Exhaust Gas Analyses,'' is cited in the final rule for its
manual method for measuring the oxygen, carbon dioxide
(CO2), SO2, and NOX content of exhaust
gas. These parts of ASME PTC 19-10-1981-Part 10 are acceptable
alternatives to EPA Methods 3B, 6, 6A, 7, 7C, and 20 of 40 CFR part 60
(SO2 only).
The standard ASTM D6784-02, Standard Test Method for Elemental,
Oxidized, Particle-Bound and Total Mercury Gas Generated from Coal-
Fired Stationary Sources (Ontario Hydro Method), cited in the final
rule for measuring Hg emissions is a VCS.
In addition to the VCS EPA uses in the final rule, the search for
emissions measurement procedures identified 14 other VCS. The EPA
determined that 12 of these 14 standards identified for measuring air
emissions or surrogates subject to emission standards in the final rule
were impractical alternatives to EPA test methods/performance
specifications for the purposes of the rule. Therefore, the EPA does
not intend to adopt these standards. The reasons for the determinations
of these 12 standards are found in the docket.
Two of the 14 VCS identified in this search were not available at
the time the review was conducted for the purposes of the final rule
because they are under development by a voluntary consensus body: ASME/
BSR MFC 12M, ``Flow in Closed Conduits Using Multiport Averaging Pitot
Primary Flowmeters,'' for EPA Method 2, and ASME/BSR MFC 13M, ``Flow
Measurement by Velocity Traverse,'' for EPA Method 2 (and possibly 1).
The EPA testing methods, performance specifications, and procedures
required are discussed in 40 CFR 60.49a, 40 CFR part 75, and PS 12A.
Under 40 CFR 63.7(f) and 63.8(f) of subpart A of the General
Provisions, a source may apply to EPA for permission to use alternative
test methods or alternative monitoring requirements in place of any of
the EPA testing methods, performance specifications, or procedures.
[[Page 28648]]
J. Executive Order 12898: Federal Actions to Address Environmental
Justice in Minority Populations and Low-Income Populations
EO 12898 requires Federal agencies to consider the impact of
programs, policies, and activities on minority populations and low-
income populations. According to EPA guidance,\12\ agencies are to
assess whether minority or low-income populations face risks or a rate
of exposure to hazards that are significant and that ``appreciably
exceed or is likely to appreciably exceed the risk or rate to the
general population or to the appropriate comparison group.'' (EPA,
1998)
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\12\ U.S. Environmental Protection Agency, 1998. Guidance for
Incorporating Environmental Justice Concerns in EPA's NEPA
Compliance analyses. Office of Federal Activities, Washington, DC,
April, 1998.
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In accordance with EO 12898, the Agency has considered whether the
final rule may have disproportionate negative impacts on minority or
low income populations. The Agency expects the final rule to lead to
beneficial reductions in air pollution and exposures generally with a
small negative impact through increased utility bills. The increase in
the price for electric power is estimated to be 0.2 percent of retail
electricity prices and is shared among all members of society equally
and, thus, is not considered to be a disproportionate impact on
minority populations and low-income populations. For this reason,
negative impacts to these sub-populations that appreciably exceed
similar impacts to the general population are not expected.
There will be beneficial outcomes to these populations as a result
of this action. In the absence of CAMR, there are health effects that
are likely to affect certain populations in the U.S., including
subsistence anglers, Native Americans, and Asian American. These
populations may include low income and minority populations who are
disproportionately impacted by Hg exposures due to their economic,
cultural, and religious activities that lead to higher levels of
consumption of fish than the general population. The CAMR is expected
to reduce exposures to these populations.
For subsistence anglers, we conducted an analysis in section 10 of
the RIA using two alternative approaches to determine potentially
exposed subsistence anglers, including one analytical approach based on
income (i.e., the population below $10,000 annual income who may eat
self-caught fish as a means of obtaining a low-cost source of protein),
and another analytical approach based on total consumption levels
(i.e., those anglers who eat two to three fish meals per day are
assumed to be subsistence). Our analysis shows that the final rule will
result in total benefits (under a scenario of no threshold on effects
at low doses of Hg) accrued to potentially prenatally exposed children
in the homes of subsistence anglers of $454,000 to $573,000 in 2020
when using a 3 percent discount rate (or $212,000 to $391,000 when
using a 7 percent discount rate).
We also conducted case studies of the potential benefits of CAMR to
a Native American population and an Asian American population located
in Wisconsin, Minnesota, and (for one of the case studies) Michigan.
The Agency was unable to transfer the results of these case studies to
the rest of the Native American and Asian American populations in the
U.S. due to missing data elements for analysis in other parts of the
country.
In the case study of the Chippewa in Minnesota, Wisconsin, and
Michigan, we determined that this group would accrue total benefits
(under an assumption of no threshold on effects at low doses of Hg) of
$6,300 to $6,700 in 2020 when using a 3 percent discount rate across
the group as a whole (or $3,000 to $4,600 when using a 7 percent
discount rate) due to reduced Hg exposures from consuming self-caught
freshwater fish. Other tribal populations were not evaluated due to
lack of reliable data on yearly (annual) self-caught fish consumption
by location and tribe (although they were considered in a sensitivity
analysis examining the issue of distributional equity--see below).
In a case study of the Hmong (a Southeast Asian-American
population) in Minnesota and Wisconsin, we determined that the
population would accrue total benefits (under an assumption of no
threshold on effects at low doses of Hg) of $3,300 to $3,500 when using
a 3 percent discount rate (or $1,500 to $2,400 when using a 7 percent
discount rate).
To further examine whether high fish-consuming (subsistence)
populations might be disproportionately benefitted by the final rule
(i.e., whether distributional equity is a consideration) and in
response to concerns received in the comments on the NODA regarding
high fish consumption rates for Ojibwe in the Great Lakes area, EPA
conducted a sensitivity analysis focusing specifically on the
distributional equity issue. The sensitivity analysis applied high-end
(near bounding) fish consumption rates for Native American subsistence
populations to the maximum expected Hg fish-tissue concentration
changes predicted to result from CAMR within regions of the 37-State
study area with recognized Native American populations. The fish
consumption rates used in this sensitivity analysis were based on
comments received through the NODA characterizing high-end consumption
for the Ojibwe Tribes in Wisconsin and Minnesota. These values
represent very high consumption rates exceeding the high-end (95th
percentile) consumption rates recommended by the EPA for Native
American subsistence populations and consequently are appropriate for a
sensitivity analysis. The sensitivity analysis suggested that, although
Native American subsistence populations (and other high fish consuming
populations) might experience relatively larger health benefits from
the final rule compared with general recreational angler, the absolute
degree of health benefits involved are relatively low (i.e., less than
a 1.0 IQ point change per fisher for any of the locations modeled).
This sensitivity analysis also provided coverage for the Hmong
population modeled for the RIA, and the conclusions cited above
regarding relatively low IQ changes (less than 1.0) can also be applied
to this high fish consuming population.
K. Congressional Review Act
The Congressional Review Act, 5 U.S.C. 801 et seq., as added by
SBREFA of 1996, generally provides that before a rule may take effect,
the agency promulgating the rule must submit a rule report, which
includes a copy of the rule, to each House of the Congress and to the
Comptroller General of the U.S. The EPA will submit a report containing
the final rule and other required information to the U.S. Senate, the
U.S. House of Representatives, and the Comptroller General of the U.S.
prior to publication of the rule in the Federal Register. A Major rule
cannot take effect until 60 days after it is published in the Federal
Register. The final rule is a ``major rule'' as defined by 5 U.S.C.
804(2).
List of Subjects
40 CFR Part 60
Environmental protection, Administrative practice and procedure,
Air pollution control, Coal, Electric power plants, Incorporation by
reference, Intergovernmental relations, Metals, Natural gas, Nitrogen
dioxide, Particulate matter, Reporting and
[[Page 28649]]
recordkeeping requirements, Sulfur oxides
40 CFR Part 72
Acid rain, Administrative practice and procedure, Air pollution
control, Electric utilities, Intergovernmental relations, Nitrogen
oxides, Reporting and recordkeeping requirements, Sulfur oxides.
40 CFR Part 75
Acid rain, Air pollution control, Carbon dioxide, Electric
utilities, Incorporation by reference, Nitrogen oxides, Reporting and
recordkeeping requirements, Sulfur oxides.
Dated: March 15, 2005.
Stephen Johnson,
Acting Administrator.
0
For the reasons stated in the preamble, title 40, chapter I, parts 60,
72, and 75 of the Code of the Federal Regulations are amended as
follows:
PART 60--[AMENDED]
0
1. The authority citation for part 60 continues to read as follows:
Authority: 42 U.S.C. 7401, 7403, 7426, and 7601.
0
2. Section 60.17 is amended by:
0
a. In the introductory text, the phrase ``(MD-35)'' is revised to read
``(C267-01);''
0
b. In paragraph (a)(12), revising the term ``77, 90, 91, 95, 98a'' to
read ``77, 90, 91, 95, 98a, 99 (Reapproved 2004) [epsiv]\1\ ;''
revising the word ``Sec. Sec. 60.41(f),'' to read ``Sec. Sec.
60.24(h)(8), 60.41(f);'' and revising the words ``and 60.251(b) and
(c).'' to read ``60.251(b) and (c), and 60.4102.''
0
c. In paragraph (a)(22), revising the term ``87, 91, 97'' to read ``87,
91, 97, 03a'' and revising the word Sec. Sec. 60.41b and 60.41c'' to
read ``Sec. Sec. 60.41a of subpart Da of this part, 60.41b of subpart
Db of this part, and 60.41c of subpart Dc of this part.''
0
d. By adding paragraph (a)(76) to read as follows:
Sec. 60.17 Incorporations by Reference.
* * * * *
(a) * * *
(76) ASTM D6784-02, Standard Test Method for Elemental, Oxidized,
Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired
Stationary Sources (Ontario Hydro Method), IBR approved for appendix B
to part 60, Performance Specification 12A, section 8.6.2.
* * * * *
0
3. Section 60.21 is amended by:
0
a. Revise paragraphs (a) and (f); and
0
b. Add a new paragraph (k) to read as follows:
Sec. 60.21 Definitions.
* * * * *
(a) Designated pollutant means any air pollutant, the emissions of
which are subject to a standard of performance for new stationary
sources, but for which air quality criteria have not been issued and
that is not included on a list published under section 108(a) of the
Act. Designated pollutant also means any air pollutant, the emissions
of which are subject to a standard of performance for new stationary
sources, that is on the section 112(b)(1) list and is emitted from a
facility that is not part of a source category regulated under section
112. Designated pollutant does not include pollutants on the section
112(b)(1) list that are emitted from a facility that is part of a
source category regulated under section 112.
* * * * *
(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 a designated pollutant emitted
from that facility during a specified period and which limits the total
amount of such authorizations available to be held for a designated
pollutant for a specified period and allows the transfer of such
authorizations not used to meet the authorization-holding requirement.
0
4. Section 60.24 is amended by:
0
a. Revising paragraph (b)(1); and
0
b. Adding a new paragraph (h) 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. * * *
* * * * *
(h) Each of the States identified in paragraph (h)(1) of this
section shall be subject to the requirements of paragraphs (h)(2)
through (7) of this section.
(1) Alaska, Alabama, Arkansas, Arizona, California, Colorado,
Connecticut, Delaware, Florida, Georgia, Hawaii, Idaho, Illinois,
Indiana, Iowa, Kansas, Kentucky, Louisiana, Maine, Maryland,
Massachusetts, Michigan, Minnesota, Mississippi, Missouri, Montana,
Nebraska, Nevada, New Hampshire, New Jersey, New Mexico, New York,
North Carolina, North Dakota, Ohio, Oklahoma, Oregon, Pennsylvania,
Rhode Island, South Carolina, South Dakota, Tennessee, Texas, Utah,
Vermont, Virginia, Washington, West Virginia, Wisconsin, Wyoming, and
the District of Columbia shall each, and, if approved for treatment as
a State under part 49 of this chapter, the Navajo Nation and the Ute
Indian Tribe may each, submit a State plan meeting the requirements of
paragraphs (h)(2) through (7) of this section and the other applicable
requirements for a State plan under this subpart.
(2) The State's State plan under paragraph (h)(1) of this section
must be submitted to the Administrator by no later than November 17,
2006. The State shall deliver five copies of the State plan to the
appropriate Regional Office, with a letter giving notice of such
action.
(3) The State's State plan under paragraph (h)(1) of this section
shall contain emission standards and compliance schedules and
demonstrate that they will result in compliance with the State's annual
electrical generating unit (EGU) mercury (Hg) budget for the
appropriate periods. The amount of the annual EGU Hg budget, in tons of
Hg per year, shall be as follows, for the indicated State for the
indicated period:
------------------------------------------------------------------------
Annual EGU Hg budget
(tons)
State -------------------------
2018 and
2010-2017 thereafter
------------------------------------------------------------------------
Alaska........................................ 0.005 0.002
Alabama....................................... 1.289 0.509
Arkansas...................................... 0.516 0.204
Arizona....................................... 0.454 0.179
California.................................... 0.041 0.016
Colorado...................................... 0.706 0.279
Connecticut................................... 0.053 0.021
Delaware...................................... 0.072 0.028
District of Columbia.......................... 0 0
Florida....................................... 1.233 0.487
Georgia....................................... 1.227 0.484
Hawaii........................................ 0.024 0.009
Idaho......................................... 0 0
Iowa.......................................... 0.727 0.287
Illinois...................................... 1.594 0.629
Indiana....................................... 2.098 0.828
Kansas........................................ 0.723 0.285
Kentucky...................................... 1.525 0.602
Louisiana..................................... 0.601 0.237
Massachusetts................................. 0.172 0.068
Maryland...................................... 0.49 0.193
Maine......................................... 0.001 0.001
Michigan...................................... 1.303 0.514
[[Page 28650]]
Minnesota..................................... 0.695 0.274
Missouri...................................... 1.393 0.55
Mississippi................................... 0.291 0.115
Montana....................................... 0.378 0.149
North Carolina................................ 1.133 0.447
North Dakota.................................. 1.564 0.617
Nebraska...................................... 0.421 0.166
New Hampshire................................. 0.063 0.025
New Jersey.................................... 0.153 0.06
New Mexico.................................... 0.299 0.118
Nevada........................................ 0.285 0.112
New York...................................... 0.393 0.155
Ohio.......................................... 2.056 0.812
Oklahoma...................................... 0.721 0.285
Oregon........................................ 0.076 0.03
Pennsylvania.................................. 1.78 0.702
Rhode Island.................................. 0 0
South Carolina................................ 0.58 0.229
South Dakota.................................. 0.072 0.029
Tennessee..................................... 0.944 0.373
Texas......................................... 4.657 1.838
Utah.......................................... 0.506 0.2
Virginia...................................... 0.592 0.234
Vermont....................................... 0 0
Washington.................................... 0.198 0.078
Wisconsin..................................... 0.89 0.351
West Virginia................................. 1.394 0.55
Wyoming....................................... 0.952 0.376
Navajo Nation Indian country.................. 0.601 0.237
Ute Indian Tribe Indian country............... 0.06 0.024
------------------------------------------------------------------------
(4) Each State plan under paragraph (h)(1) of this section shall
require EGUs to comply with the monitoring, record keeping, and
reporting provisions of part 75 of this chapter with regard to Hg mass
emissions.
(5) In addition to meeting the requirements of Sec. 60.26, each
State plan under paragraph (h)(1) of this section must show that the
State has legal authority to:
(i) Adopt emissions standards and compliance schedules necessary
for attainment and maintenance of the State's relevant annual EGU Hg
budget under paragraph (h)(3) of this section; and
(ii) Require owners or operators of EGUs in the State to meet the
monitoring, record keeping, and reporting requirements described in
paragraph (h)(4) of this section.
(6)(i) Notwithstanding the provisions of paragraphs (h)(3) and
(5)(i) of this section, if a State adopts regulations substantively
identical to subpart HHHH of this part (Hg Budget Trading Program),
incorporates such subpart by reference into its regulations, or adopts
regulations that differ substantively from such subpart only as set
forth in paragraph (h)(6)(ii) of this section, then such allowance
system in the State's State plan is automatically approved as meeting
the requirements of paragraph (h)(3) of this section, provided that the
State demonstrates that it has the legal authority to take such action
and to implement its responsibilities under such regulations.
(ii) If a State adopts an allowance system that differs
substantively from subpart HHHH of this part only as follows, then the
emissions trading program is approved as set forth in paragraph
(h)(6)(i) of this section.
(A) The State may decline to adopt the allocation provisions set
forth in Sec. Sec. 60.4141 and 60.4142 and may instead adopt any
methodology for allocating Hg allowances.
(B) The State's methodology under paragraph (h)(6)(ii)(A) of this
section must not allow the State to allocate Hg allowances for a year
in excess of the amount in the State's annual EGU Hg budget for such
year under paragraph (h)(3) of this section;
(C) The State's methodology under paragraph (h)(6)(ii)(A) of this
section must require that, for EGUs commencing operation before January
1, 2001, the State will determine, and notify the Administrator of,
each unit's allocation of Hg allowances by October 31, 2006 for 2010,
2011, and 2012 and by October 31, 2009 and October 31 of each year
thereafter for the fourth year after the year of the notification
deadline; and
(D) The State's methodology under paragraph (h)(6)(ii)(A) of this
section must require that, for EGUs commencing operation on or after
January 1, 2001, the State will determine, and notify the Administrator
of, each unit's allocation of Hg allowances by October 31 of the year
for which the Hg allowances are allocated.
(7) If a State adopts an allowance system that differs
substantively from subpart HHHH of this part, other than as set forth
in paragraph (h)(6)(ii) of this section, then such allowance system is
not automatically approved as set forth in paragraph (h)(6)(i) or (ii)
of this section and will be reviewed by the Administrator for
approvability in accordance with the other provisions of paragraphs
(h)(2) through (5) of this section and the other applicable
requirements for a State plan under this subpart, provided that the Hg
allowances issued under such allowance system shall not, and the State
plan under paragraph (h)(1) of this section shall state that such Hg
allowances shall not, qualify as Hg allowances under any allowance
system approved under paragraph (h)(6)(i) or (ii) of this section.
(8) The terms used in this paragraph (h) shall have the following
meanings:
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 of the amount of Hg allowances to be initially credited
to a source.
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.
Bottoming-cycle cogeneration unit means a cogeneration unit in
which the energy input to the unit is first used to produce useful
thermal energy and at least some of the reject heat from the useful
thermal energy application or process is then used for electricity
production.
Coal means any solid fuel classified as anthracite, bituminous,
subbituminous, or lignite by the American Society of Testing and
Materials (ASTM) Standard Specification for Classification of Coals by
Rank D388-77, 90, 91, 95, 98a, or 99 (Reapproved 2004) [epsiv]\1\
(incorporated by reference, see Sec. 60.17).
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 means combusting any amount of coal or coal-derived
fuel, alone or in combination with any amount of any other fuel, during
any year.
Cogeneration unit means a stationary, coal-fired boiler or
stationary, coal-fired combustion turbine:
(1) Having equipment used to produce electricity and useful thermal
energy for industrial, commercial, heating, or cooling purposes through
the sequential use of energy; and
(2) Producing during the 12-month period starting on the date the
unit first produces electricity and during any calendar year after
which the unit first produces electricity:
(i) For a topping-cycle cogeneration unit,
(A) Useful thermal energy not less than 5 percent of total energy
output; and
(B) Useful power that, when added to one-half of useful thermal
energy produced, is not less then 42.5 percent of total energy input,
if useful thermal energy produced is 15 percent or more of total energy
output, or not less than 45 percent of total energy input, if useful
thermal energy produced is less than 15 percent of total energy output.
[[Page 28651]]
(ii) For a bottoming-cycle cogeneration unit, useful power not less
than 45 percent of total energy input.
Combustion turbine means:
(1) An enclosed device comprising a compressor, a combustion, and a
turbine and in which the flue gas resulting from the combustion of fuel
in the combustion passes through the turbine, rotating the turbine; and
(2) If the enclosed device under paragraph (1) of this definition
is combined cycle, any associated heat recovery steam generator and
steam turbine.
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.
Electric generating unit or EGU means:
(1) Except as provided in paragraph (2) of this definition, a
stationary, coal-fired boiler or stationary, coal-fired combustion
turbine in the State serving at any time, since the start-up of a
unit's combustion chamber, a generator with nameplate capacity of more
than 25 megawatts electric (MW) producing electricity for sale.
(2) For a unit that qualifies as a cogeneration unit during the 12-
month period starting on the date the unit first produces electricity
and continues to qualify as a cogeneration unit, a cogeneration unit in
the State serving at any time a generator with nameplate capacity of
more than 25 MW and supplying in any calendar year more than one-third
of the unit's potential electric output capacity or 219,000 MWh,
whichever is greater, to any utility power distribution system for
sale. If a unit qualifies as a cogeneration unit during the 12-month
period starting on the date the unit first produces electricity but
subsequently no longer qualifies as a cogeneration unit, the unit shall
be subject to paragraph (1) of this definition starting on the day on
which the unit first no longer qualifies as a cogeneration unit.
Generator means a device that produces electricity.
Gross electrical output means, with regard to a cogeneration unit,
electricity made available for use, including any such electricity used
in the power production process (which process includes, but is not
limited to, any on-site processing or treatment of fuel combusted at
the unit and any on-site emission controls).
Gross thermal energy means, with regard to a cogeneration unit,
useful thermal energy output plus, where such output is made available
for an industrial or commercial process, any heat contained in
condensate return or makeup water.
Heat input means, with regard to a specified period of time, the
product (in million British thermal units per unit time, MMBTU/time) of
the gross calorific value of the fuel (in Btu per pound, 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 designated representative
and determined by the Administrator in accordance with Sec. Sec.
60.4170 through 60.4176 and excluding the heat derived from preheated
combustion air, reticulated flue gases, or exhaust from other sources.
Hg allowance means a limited authorization issued by the permitting
authority to emit one ounce of Hg during a control period of the
specified calendar year for which the authorization is allocated or of
any calendar year thereafter.
Life-of-the-unit, firm power contractual arrangement means a unit
participation power sales agreement under which a customer reserves, or
is entitled to receive, a specified amount or percentage of nameplate
capacity and associated energy generated by 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 no less 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, starting from the initial
installation of a unit, the maximum amount of fuel per hour (in Btu/hr)
that a unit is capable of combusting on a steady-state basis as
specified by the manufacturer of the unit, or, starting from the
completion of any subsequent physical change in the unit resulting in a
decrease in the maximum amount of fuel per hour (in Btu per hour, Btu/
hr) that a unit is capable of combusting on a steady-state basis, such
decreased maximum amount as specified by the person conducting the
physical change.
Nameplate capacity means, starting from the initial installation of
a generator, the maximum electrical generating output (in MW) that the
generator is capable of producing on a steady-state basis and during
continuous operation (when not restricted by seasonal or other derates)
as specified by the manufacturer of the generator or, starting from the
completion of any subsequent physical change in the generator resulting
in an increase in the maximum electrical generating output (in MW) that
the generator is capable of producing on a steady-state basis and
during continuous operation (when not restricted by seasonal or other
derates), such increased maximum amount as specified by the person
conducting the physical change.
Operator means any person who operates, controls, or supervises an
EGU or a source that includes an EGU and shall include, but not be
limited to, any holding company, utility system, or plant manager of
such EGU or source.
Ounce means 2.84 x 107 micrograms.
Owner means any of the following persons:
(1) With regard to a Hg Budget source or a Hg Budget unit at a
source, respectively:
(i) Any holder of any portion of the legal or equitable title in a
Hg Budget unit at the source or the Hg Budget unit;
(ii) Any holder of a leasehold interest in a Hg Budget unit at the
source or the Hg Budget unit; or
(iii) Any purchaser of power from a Hg Budget unit at the source or
the Hg Budget unit under a life-of-the-unit, firm power contractual
arrangement; provided that, 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) on the revenues
or income from such Hg Budget unit; or
(2) With regard 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 the person's ownership
interest with respect to Hg allowances.
Potential electrical output capacity means 33 percent of a unit's
maximum design heat input, divided by 3,413 Btu per kilowatt-hour (Btu/
kWh), divided by 1,000 kWh per megawatt-hour (kWh/MWh), and multiplied
by 8,760 hr/yr.
Sequential use of energy means:
(1) For a topping-cycle cogeneration unit, the use of reject heat
from electricity production in a useful thermal energy application or
process; or
(2) For a bottoming-cycle cogeneration unit, the use of reject heat
from seful
[[Page 28652]]
thermal energy application or process in electricity production.
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.
State means:
(1) For purposes of referring to a governing entity, one of the
States in the United States, the District of Columbia, or, if approved
for treatment as a State under part 49 of this chapter, the Navajo
Nation or Ute Indian Tribe that adopts the Hg Budget Trading Program
pursuant to Sec. 60.24(h)(6); or
(2) For purposes of referring to a geographic area, one of the
States in the United States, the District of Columbia, the Navajo
Nation Indian country, or the Ute Tribe Indian country.
Topping-cycle cogeneration unit means a cogeneration unit in which
the energy input to the unit is first used to produce useful power,
including electricity, and at least some of the reject heat from the
electricity production is then used to provide useful thermal energy.
Total energy input means, with regard to a cogeneration unit, total
energy of all forms supplied to the cogeneration unit, excluding energy
produced by the cogeneration unit itself.
Total energy output means, with regard to a cogeneration unit, the
sum of useful power and useful thermal energy produced by the
cogeneration unit.
Unit means a stationary coal-fired boiler or a stationary coal-
fired combustion turbine.
Useful power means, with regard to a cogeneration unit, electricity
or mechanical energy made available for use, excluding any such energy
used in the power production process (which process includes, but is
not limited to, any on-site processing or treatment of fuel combusted
at the unit and any on-site emission controls).
Useful thermal energy means, with regard to a cogeneration unit,
thermal energy that is:
(1) Made available to an industrial or commercial process (not a
power production process), excluding any heat contained in condensate
return or makeup water;
(2) Used in a heat application (e.g., space heating or domestic hot
water heating); or
(3) Used in a space cooling application (i.e., thermal energy used
by an absorption chiller).
Utility power distribution system means the portion of an
electricity grid owned or operated by a utility and dedicated to
delivering electricity to customers.
Subpart Da--[Amended]
0
5. Section 60.41a is amended by revising the definition of ``Electric
utility steam generating unit,'' and by adding in alphabetical order
the definitions of ``Bituminous coal,'' ``Coal,'' ``Coal-fired electric
utility steam generating unit,'' ``Cogeneration,'' ``Dry flue gas
desulfurization technology or dry FGD,'' ``Electrostatic
precipitator,'' ``Emission limitation,'' ``Emission rate period,''
``Federally enforceable,'' ``Gaseous fuel,'' ``Integrated gasification
combined cycle electric utility steam generating unit,'' ``Natural
gas,'' and ``Responsible official'' and ``Wet flue gas desulfurization
technology or wet FGD'' to read as follows:
Sec. 60.41a Definitions.
* * * * *
Bituminous coal means coal that is classified as bituminous
according to the American Society of Testing and Materials (ASTM)
Standard Specification for Classification of Coals by Rank D388-77, 90,
91, 95, 98a, or 99 (Reapproved 2004)[epsiv]\1\ (incorporated by
reference, see Sec. 60.17).
* * * * *
Coal means all solid fuels classified as anthracite, bituminous,
subbituminous, or lignite by the American Society of Testing and
Materials (ASTM) Standard Specification for Classification of Coals by
Rank D388-77, 90, 91, 95, 98a, or 99 (Reapproved 2004)[epsiv]\1\
(incorporated by reference, see Sec. 60.17), coal refuse, and
petroleum coke. Synthetic fuels derived from coal for the purpose of
creating useful heat, including but not limited to solvent-refined
coal, gasified coal, coal-oil mixtures, and coal-water mixtures are
included in this definition for the purposes of this subpart.
Coal-fired electric utility steam generating unit means an electric
utility steam generating unit that burns coal, coal refuse, or a
synthetic gas derived from coal either exclusively, in any combination
together, or in any combination with other supplemental fuels in any
amount. Examples of supplemental fuels include, but are not limited to,
petroleum coke and tire-derived fuels.
* * * * *
Cogeneration means a facility that simultaneously produces both
electrical (or mechanical) and useful thermal energy from the same
primary energy source.
* * * * *
Dry flue gas desulfurization technology or dry FGD means a sulfur
dioxide control system that is located downstream of the steam
generating unit and removes sulfur oxides from the combustion gases of
the steam generating unit by contacting the combustion gases with an
alkaline slurry or solution and forming a dry powder material. This
definition includes devices where the dry powder material is
subsequently converted to another form. Alkaline slurries or solutions
used in dry FGD technology include, but are not limited to, lime and
sodium.
* * * * *
Electric utility steam generating unit means any fossil fuel-fired
combustion unit of more than 25 megawatts electric (MW) that serves a
generator that produces electricity for sale. A unit that cogenerates
steam and electricity and supplies more than one-third of its potential
electric output capacity and more than 25 MW output to any utility
power distribution system for sale is also considered an electric
utility steam generating unit.
Electrostatic precipitator or ESP means an add-on air pollution
control device used to capture particulate matter by charging the
particles using an electrostatic field, collecting the particles using
a grounded collecting surface, and transporting the particles into a
hopper.
* * * * *
Emission limitation means any emissions limit or operating limit.
Emission rate period means any calendar month included in a 12-
month rolling average period.
Federally enforceable means all limitations and conditions that are
enforceable by the Administrator, including the requirements of 40 CFR
parts 60 and 61, requirements within any applicable State
implementation plan, and any permit requirements established under 40
CFR 52.21 or 40 CFR 51.18 and 40 CFR 51.24.
* * * * *
Gaseous fuel means any fuel derived from coal or petroleum that is
present as a gas at standard conditions and includes, but is not
limited to, refinery fuel gas, process gas, and coke-oven gas.
* * * * *
Integrated gasification combined cycle electric utility steam
generating unit or IGCC means a coal-fired electric utility steam
generating unit that burns a synthetic gas derived from coal in a
combined-cycle gas turbine. No coal is directly burned in the unit
during operation.
* * * * *
Natural gas means:
[[Page 28653]]
(1) A naturally occurring mixture of hydrocarbon and nonhydrocarbon
gases found in geologic formations beneath the earth's surface, of
which the principal constituent is methane; or
(2) Liquid petroleum gas, as defined by the American Society of
Testing and Materials (ASTM) Standard Specification for Liquid
Petroleum Gases D1835-87, 91, 97, or 03a (incorporated by reference,
see Sec. 60.17).
* * * * *
Responsible official means responsible official as defined in 40
CFR 70.2.
* * * * *
Wet flue gas desulfurization technology or wet FGD means a sulfur
dioxide control system that is located downstream of the steam
generating unit and removes sulfur oxides from the combustion gases of
the steam generating unit by contacting the combustion gases with an
alkaline slurry or solution and forming a liquid material. This
definition applies to devices where the aqueous liquid material product
of this contact is subsequently converted to other forms. Alkaline
reagents used in wet FGD technology include, but are not limited to,
lime, limestone, and sodium.
* * * * *
0
6. Subpart Da is amended by:
0
a. Redesignating Sec. 60.49a as Sec. 60.51a;
0
b. Redesignating Sec. 60.48a as Sec. 60.50a;
0
c. Redesignating Sec. 60.47a as Sec. 60.49a;
0
d. Redesignating Sec. 60.46a as Sec. 60.48a;
0
e. Redesignating Sec. 60.45a as Sec. 60.47a;
0
f. Adding new Sec. Sec. 60.45a; and
0
g. Adding and reserving new Sec. 60.46a to read as follows:
Sec. 60.45a Standard for mercury.
(a) For each coal-fired electric utility steam generating unit
other than an integrated gasification combined cycle (IGCC) electric
utility steam generating unit, on and after the date on which the
initial performance test required to be conducted under Sec. 60.8 is
completed, no owner or operator subject to the provisions of this
subpart shall cause to be discharged into the atmosphere from any
affected facility for which construction or reconstruction commenced
after January 30, 2004, any gases which contain mercury (Hg) emissions
in excess of each Hg emissions limit in paragraphs (a)(1) through (5)
of this section that applies to you. The Hg emissions limits in
paragraphs (a)(1) through (5) of this section are based on a 12-month
rolling average using the procedures in Sec. 60.50a(h).
(1) For each coal-fired electric utility steam generating unit that
burns only bituminous coal, you must not discharge into the atmosphere
any gases from a new affected source which contain Hg in excess of 21 x
10-\6\ pound per megawatt hour (lb/MWh) or 0.021 lb/
gigawatt-hour (GWh) on an output basis. The International System of
Units (SI) equivalent is 0.0026 nanograms per joule (ng/J).
(2) For each coal-fired electric utility steam generating unit that
burns only subbituminous coal:
(i) If you utilize wet FGD technology to limit SO2
emissions from your steam generating unit, you must not discharge into
the atmosphere any gases from a new affected source which contain Hg in
excess of 42 x 10-\6\ lb/MWh or 0.042 lb/GWh on an output
basis. The SI equivalent is 0.0053 ng/J.
(ii) If you utilize dry FGD technology to limit SO2
emissions from your steam generating unit, you must not discharge into
the atmosphere any gases from a new affected source which contain Hg in
excess of 78 x 10-\6\ lb/MWh or 0.078 lb/GWh on an output
basis. The SI equivalent is 0.0098 ng/J.
(3) For each coal-fired electric utility steam generating unit that
burns only lignite, you must not discharge into the atmosphere any
gases from a new affected source which contain Hg in excess of 145 x
10-\6\ lb/MWh or 0.145 lb/GWh on an output basis. The SI
equivalent is 0.0183 ng/J.
(4) For each coal-burning electric utility steam generating unit
that burns only coal refuse, you must not discharge into the atmosphere
any gases from a new affected source which contain Hg in excess of 1.4
x 10-6 lb/MWh or 0.0014 lb/GWh on an output basis. The SI
equivalent is 0.00018 ng/J.
(5) For each coal-fired electric utility steam generating unit that
burns a blend of coals from different coal ranks (i.e., bituminous
coal, subbituminous coal, lignite) or a blend of coal and coal refuse,
you must not discharge into the atmosphere any gases from a new
affected source that contain Hg in excess of the monthly unit-specific
Hg emissions limit established according to paragraph (a)(5)(i) or (ii)
of this section, as applicable to the affected unit.
(i) If you operate a coal-fired electric utility steam generating
unit that burns a blend of coals from different coal ranks or a blend
of coal and coal refuse, you must not discharge into the atmosphere any
gases from a new affected source that contain Hg in excess of the
computed weighted Hg emissions limit based on the proportion of energy
output (in British thermal units, Btu) contributed by each coal rank
burned during the compliance period and its applicable Hg emissions
limit in paragraphs (a)(1) through (4) of this section as determined
using Equation 1 of this section. You must meet the weighted Hg
emissions limit calculated using Equation 1 of this section by
calculating the unit emission rate based on the total Hg loading of the
unit and the total Btu or megawatt hours contributed by all fuels
burned during the compliance period.
[GRAPHIC] [TIFF OMITTED] TR18MY05.000
Where:
ELb = Total allowable Hg in lb/MWh that can be emitted to
the atmosphere from any affected source being averaged under the
blending provision.
ELi = Hg emissions limit for the subcategory i (coal rank)
that applies to affected source, lb/MWh.
HHi = Electricity output from affected source during the
production period related to use of the corresponding subcategory i
(coal rank) that falls within the compliance period, gross MWh
generated by the electric utility steam generating unit.
n = Number of subcategories (coal ranks) being averaged for an affected
source.
(ii) If you operate a coal-fired electric utility steam generating
unit that burns a blend of coals from different coal ranks or a blend
of coal and coal refuse together with one or more non-regulated,
supplementary fuels, you must not discharge into the atmosphere any
gases from the unit that contain Hg in excess of the computed weighted
Hg emission limit based on the proportion of electricity output (in
MWh) contributed by each coal rank burned during the compliance period
and its applicable Hg emissions limit in paragraphs (a)(1) through (4)
of this section as determined using Equation 1 of this section. You
must meet the weighted Hg emissions limit calculated using Equation 1
of this section by calculating the unit emission rate based on the
total Hg loading of the unit and the total megawatt hours contributed
by both regulated and nonregulated fuels burned during the compliance
period.
(b) For each IGCC electric utility steam generating unit, on and
after the date on which the initial performance test required to be
conducted under Sec. 60.8 is completed, no owner or operator subject
to the provisions of this subpart shall cause to be discharged into
[[Page 28654]]
the atmosphere from any affected facility for which construction or
reconstruction commenced after January 30, 2004, any gases which
contain Hg emissions in excess of 20 x 10-6 lb/MWh or 0.020
lb/GWh on an output basis. The SI equivalent is 0.0025 ng/J. This Hg
emissions limit is based on a 12-month rolling average using the
procedures in Sec. 60.50a(g).
Sec. 60.46a [Reserved]
0
7. Newly redesignated Sec. 60.48a is amended by:
0
a. Revising paragraph (c);
0
b. In paragraph (h) by revising the existing references from ``Sec.
60.47a'' to ``Sec. 60.49a'';
0
c. In paragraph (i) by revising the existing references for
``Sec. Sec. 60.47a(c),'' ``60.47a(l),'' and ``60.47a(k)'' to
``Sec. Sec. 60.49a(c),'' ``60.49a(l),'' and ``60.49a(k),''
respectively;
0
d. In paragraph (j)(2) by revising the existing references from ``Sec.
60.47a'' to ``Sec. 60.49a'' twice;
0
e. In paragraph (k)(2)(ii) by revising the existing references from
``Sec. 60.47a'' and ``60.47a(l)'' to ``Sec. 60.49a'' and
``60.49a(l),'' respectively;
0
f. In paragraph (k)(2)(iii) by revising the existing references from
``Sec. 60.47a(k)'' to ``Sec. 60.49a(k)'';
0
g. In paragraph (k)(2)(iv) by revising the existing references from
``Sec. 60.47a(l)'' to ``Sec. 60.49a(l)''; and
0
h. Adding new paragraph (l).
The revision and additions read as follows:
Sec. 60.48a Compliance provisions.
* * * * *
(c) The particulate matter emission standards under Sec. 60.42a,
the nitrogen oxides emission standards under Sec. 60.44a, and the Hg
emission standards under Sec. 60.45a apply at all times except during
periods of startup, shutdown, or malfunction.
* * * * *
(l) Compliance provisions for sources subject to Sec. 60.45a. The
owner or operator of an affected facility subject to Sec. 60.45a (new
sources constructed or reconstructed after January 30, 2004) shall
calculate the Hg emission rate (lb/MWh) for each calendar month of the
year, using hourly Hg concentrations measured according to the
provisions of Sec. 60.49a(p) in conjunction with hourly stack gas
volumetric flow rates measured according to the provisions of Sec.
60.49a(l) or (m), and hourly gross electrical outputs, determined
according to the provisions in Sec. 60.49a(k). Compliance with the
applicable standard under Sec. 60.45a is determined on a 12-month
rolling average basis.
0
8. Newly redesignated Sec. 60.49a is amended by:
0
a. In paragraph (c)(2) by revising the existing references from ``Sec.
60.49a'' to ``Sec. 60.51a'' twice;
0
b. In paragraph (g) by revising the existing reference from ``Sec.
60.46a'' to ``Sec. 60.48a'' and
0
c. Adding new paragraphs (p) through (s).
The revision and additions read as follows:
Sec. 60.49a Emission monitoring.
* * * * *
(p) The owner or operator of an affected facility demonstrating
compliance with an Hg limit in Sec. 60.45a shall install and operate a
continuous emissions monitoring system (CEMS) to measure and record the
concentration of Hg in the exhaust gases from each stack according to
the requirements in paragraphs (p)(1) through (p)(3) of this section.
Alternatively, for an affected facility that is also subject to the
requirements of subpart I of part 75 of this chapter, the owner or
operator may install, certify, maintain, operate and quality-assure the
data from a Hg CEMS according to Sec. 75.10 of this chapter and
appendices A and B to part 75 of this chapter, in lieu of following the
procedures in paragraphs (p)(1) through (p)(3) of this section.
(1) The owner or operator must install, operate, and maintain each
CEMS according to Performance Specification 12A in appendix B to this
part.
(2) The owner or operator must conduct a performance evaluation of
each CEMS according to the requirements of Sec. 60.13 and Performance
Specification 12A in appendix B to this part.
(3) The owner or operator must operate each CEMS according to the
requirements in paragraphs (p)(3)(i) through (iv) of this section.
(i) As specified in Sec. 60.13(e)(2), each CEMS must complete a
minimum of one cycle of operation (sampling, analyzing, and data
recording) for each successive 15-minute period.
(ii) The owner or operator must reduce CEMS data as specified in
Sec. 60.13(h).
(iii) The owner or operator shall use all valid data points
collected during the hour to calculate the hourly average Hg
concentration.
(iv) The owner or operator must record the results of each required
certification and quality assurance test of the CEMS.
(4) Mercury CEMS data collection must conform to paragraphs
(p)(4)(i) through (iv) of this section.
(i) For each calendar month in which the affected unit operates,
valid hourly Hg concentration data, stack gas volumetric flow rate
data, moisture data (if required), and electrical output data (i.e.,
valid data for all of these parameters) shall be obtained for at least
75 percent of the unit operating hours in the month.
(ii) Data reported to meet the requirements of this subpart shall
not include hours of unit startup, shutdown, or malfunction. In
addition, for an affected facility that is also subject to subpart I of
part 75 of this chapter, data reported to meet the requirements of this
subpart shall not include data substituted using the missing data
procedures in subpart D of part 75 of this chapter, nor shall the data
have been bias adjusted according to the procedures of part 75 of this
chapter.
(iii) If valid data are obtained for less than 75 percent of the
unit operating hours in a month, you must discard the data collected in
that month and replace the data with the mean of the individual monthly
emission rate values determined in the last 12 months. In the 12-month
rolling average calculation, this substitute Hg emission rate shall be
weighted according to the number of unit operating hours in the month
for which the data capture requirement of Sec. 60.49a(p)(4)(i) was not
met.
(iv) Notwithstanding the requirements of paragraph (p)(4)(iii) of
this section, if valid data are obtained for less than 75 percent of
the unit operating hours in another month in that same 12-month rolling
average cycle, discard the data collected in that month and replace the
data with the highest individual monthly emission rate determined in
the last 12 months. In the 12-month rolling average calculation, this
substitute Hg emission rate shall be weighted according to the number
of unit operating hours in the month for which the data capture
requirement of Sec. 60.49a(p)(4)(i) was not met.
(q) As an alternative to the CEMS required in paragraph (p) of this
section, the owner or operator may use a sorbent trap monitoring system
(as defined in Sec. 72.2 of this chapter) to monitor Hg concentration,
according to the procedures described in Sec. 75.15 of this chapter
and appendix K to part 75 of this chapter.
(r) For Hg CEMS that measure Hg concentration on a dry basis or for
sorbent trap monitoring systems, the emissions data must be corrected
for the stack gas moisture content. A certified continuous moisture
monitoring system that meets the requirements of Sec. 75.11(b) of this
chapter is acceptable for this purpose. Alternatively, the appropriate
[[Page 28655]]
default moisture value, as specified in Sec. 75.11(b) or Sec.
75.12(b) of this chapter, may be used.
(s) The owner or operator shall prepare and submit to the
Administrator for approval a unit-specific monitoring plan for each
monitoring system, at least 45 days before commencing certification
testing of the monitoring systems. The owner or operator shall comply
with the requirements in your plan. The plan must address the
requirements in paragraphs (s)(1) through (6) of this section.
(1) Installation of the CEMS sampling probe or other interface at a
measurement location relative to each affected process unit such that
the measurement is representative of the exhaust emissions (e.g., on or
downstream of the last control device);
(2) Performance and equipment specifications for the sample
interface, the pollutant concentration or parametric signal analyzer,
and the data collection and reduction systems;
(3) Performance evaluation procedures and acceptance criteria
(e.g., calibrations, relative accuracy test audits (RATA), etc.);
(4) Ongoing operation and maintenance procedures in accordance with
the general requirements of Sec. 60.13(d) or part 75 of this chapter
(as applicable);
(5) Ongoing data quality assurance procedures in accordance with
the general requirements of Sec. 60.13 or part 75 of this chapter (as
applicable); and
(6) Ongoing record keeping and reporting procedures in accordance
with the requirements of this subpart.
0
9. Newly redesignated Sec. 60.50a is amended by:
0
a. In paragraph (c)(5) by revising the existing references from ``Sec.
60.47a(b) and (d)'' to ``Sec. 60.49a(b) and (d)'';
0
b. In paragraph (d)(2) by revising the existing references from ``Sec.
60.47a(c) and (d)'' to ``Sec. 60.49a(c) and (d)'';
0
c. In paragraph (e)(2) by revising the existing reference from ``Sec.
60.46a(d)(1)'' to ``Sec. 60.48a(d)(1)''; and
0
d. Adding new paragraphs (g) through (i).
The additions read as follows:
Sec. 60.50a Compliance determination procedures and methods.
* * * * *
(g) For the purposes of determining compliance with the emission
limits in Sec. Sec. 60.45a and 60.46a, the owner or operator of an
electric utility steam generating unit which is also a cogeneration
unit shall use the procedures in paragraphs (g)(1) and (2) of this
section to calculate emission rates based on electrical output to the
grid plus half of the equivalent electrical energy in the unit's
process stream.
(1) All conversions from Btu/hr unit input to MW unit output must
use equivalents found in 40 CFR 60.40(a)(1) for electric utilities
(i.e., 250 million Btu/hr input to a electric utility steam generating
unit is equivalent to 73 MW input to the electric utility steam
generating unit); 73 MW input to the electric utility steam generating
unit is equivalent to 25 MW output from the boiler electric utility
steam generating unit; therefore, 250 million Btu input to the electric
utility steam generating unit is equivalent to 25 MW output from the
electric utility steam generating unit).
(2) Use Equation 1 below in lieu of Equation 5 in paragraph (h) of
this section, to determine the monthly average Hg emission rates for a
cogeneration unit.
[GRAPHIC] [TIFF OMITTED] TR18MY05.001
Where:
ERCOGEN = Cogeneration Hg emission rate for a particular
month (lb/MWh;
M = Mass of Hg emitted from the stack over the same month, from
Equation 2 or Equation 3 in paragraph h of this section (lb);
Vgrid = Amount of energy sent to the grid over the same
month (MWh); and
Vprocess = Amount of energy converted to steam for process
use over the same month (MWh).
(h) The owner or operator shall determine compliance with the Hg
limit in Sec. 60.45a according to the procedures in paragraphs (h)(1)
through (3) of this section.
(1) The initial performance test shall be commenced by the
applicable date specified in Sec. 60.8(a). The required continuous
monitoring systems must be certified prior to commencing the test. The
performance test consists of collecting hourly Hg emission data (lb/
MWh) with the continuous monitoring systems for 12 successive months of
unit operation (excluding hours of unit startup, shutdown and
malfunction). The average Hg emission rate is calculated for each
month, and then the weighted, 12-month average Hg emission rate is
calculated according to paragraph (h)(2) or (h)(3) of this section, as
applicable. If, for any month in the initial performance test, the
minimum data capture requirement in Sec. 60.49a(p)(4)(i) is not met,
the owner or operator shall report a substitute Hg emission rate for
that month, as follows. For the first such month, the substitute
monthly Hg emission rate shall be the arithmetic average of all valid
hourly Hg emission rates recorded to date. For any subsequent month(s)
with insufficient data capture, the substitute monthly Hg emission rate
shall be the highest valid hourly Hg emission rate recorded to date.
When the 12-month average Hg emission rate for the initial performance
test is calculated, for each month in which there was insufficient data
capture, the substitute monthly Hg emission rate shall be weighted
according to the number of unit operating hours in that month.
Following the initial performance test, the owner or operator shall
demonstrate compliance by calculating the weighted average of all
monthly Hg emission rates (in lb/MWh) for each 12 successive calendar
months, excluding data obtained during startup, shutdown, or
malfunction.
(2) If a CEMS is used to demonstrate compliance, follow the
procedures in paragraphs (h)(2)(i) through (iii) of this section to
determine the 12-month rolling average.
(i) Calculate the total mass of Hg emissions over a month (M), in
pounds (lb), using either Equation 2 in paragraph (h)(2)(i)(A) of this
section or Equation 3 in paragraph (h)(2)(i)(B) of this section, in
conjunction with Equation 4 in paragraph (h)(2)(i)(C) of this section.
(A) If the Hg CEMS measures Hg concentration on a wet basis, use
Equation 2 below to calculate the Hg mass emissions for each valid
hour:
[GRAPHIC] [TIFF OMITTED] TR18MY05.020
Where:
Eh = Hg mass emissions for the hour, (lb)
K = Units conversion constant, 6.24 x 10-11 lb-
scm/[mu]g-scf
Ch = Hourly Hg concentration, wet basis, ([mu]g/scm)
Qh = Hourly stack gas volumetric flow rate, (scfh)
th = Unit operating time, i.e., the fraction of the hour for
which the unit operated. For example, th = 0.50 for a half-
hour of unit operation and 1.00 for a full hour of operation.
(B) If the Hg CEMS measures Hg concentration on a dry basis, use
Equation 3 below to calculate the Hg mass emissions for each valid
hour:
[GRAPHIC] [TIFF OMITTED] TR18MY05.002
Where:
Eh = Hg mass emissions for the hour, (lb)
K = Units conversion constant, 6.24 x 10-11 lb-
scm/[mu]g-scf
Ch = Hourly Hg concentration, dry basis, ([mu]g/dscm)
[[Page 28656]]
Qh = Hourly stack gas volumetric flow rate, (scfh)
th = Unit operating time, i.e., the fraction of the hour for
which the unit operated
Bws = Stack gas moisture content, expressed as a decimal
fraction (e.g., for 8 percent H2O, Bws = 0.08)
(C) Use Equation 4, below, to calculate M, the total mass of Hg
emitted for the month, by summing the hourly masses derived from
Equation 2 or 3 (as applicable):
[GRAPHIC] [TIFF OMITTED] TR18MY05.003
Where:
M = Total Hg mass emissions for the month, (lb)
Eh = Hg mass emissions for hour ``h'', from Equation 2 or 3
of this section, (lb)
n = The number of unit operating hours in the month with valid CEM and
electrical output data, excluding hours of unit startup, shutdown and
malfunction
(ii) Calculate the monthly Hg emission rate on an output basis (lb/
MWh) using Equation 5, below. For a cogeneration unit, use Equation 1
in paragraph (g) of this section instead.
[GRAPHIC] [TIFF OMITTED] TR18MY05.004
Where:
ER = Monthly Hg emission rate, (lb/MWh)
M = Total mass of Hg emissions for the month, from Equation 4, above,
(lb)
P = Total electrical output for the month, for the hours used to
calculate M, (MWh)
(iii) Until 12 monthly Hg emission rates have been accumulated,
calculate and report only the monthly averages. Then, for each
subsequent calendar month, use Equation 6 below to calculate the 12-
month rolling average as a weighted average of the Hg emission rate for
the current month and the Hg emission rates for the previous 11 months,
with one exception. Calendar months in which the unit does not operate
(zero unit operating hours) shall not be included in the 12-month
rolling average.
[GRAPHIC] [TIFF OMITTED] TR18MY05.005
Where:
Eavg = Weighted 12-month rolling average Hg emission rate,
(lb/MWh)
(ER)i = Monthly Hg emission rate, for month ``i'', (lb/MWh)
n = The number of unit operating hours in month ``i'' with valid CEM
and electrical output data, excluding hours of unit startup, shutdown,
and malfunction
(3) If a sorbent trap monitoring system is used in lieu of a Hg
CEMS, as described in Sec. 75.15 of this chapter and in appendix K to
part 75 of this chapter, calculate the monthly Hg emission rates using
Equations 3 through 5 of this section, except that for a particular
pair of sorbent traps, Ch in Equation 3 shall be the flow-
proportional average Hg concentration measured over the data collection
period.
(i) Daily calibration drift (CD) tests and quarterly accuracy
determinations shall be performed for Hg CEMS in accordance with
Procedure 1 of appendix F to this part. For the CD assessments, you may
use either elemental mercury or mercuric chloride (Hg[deg] or
HgCl2) standards. The four quarterly accuracy determinations
shall consist of one RATA and three measurement error (ME) tests using
HgCl2 standards, as described in section 8.3 of Performance
Specification 12-A in appendix B to this part (note: Hg[deg] standards
may be used if the Hg monitor does not have a converter).
Alternatively, the owner or operator may implement the applicable
daily, weekly, quarterly, and annual quality assurance (QA)
requirements for Hg CEMS in appendix B to part 75 of this chapter, in
lieu of the QA procedures in appendices B and F to this part. Annual
RATA of sorbent trap monitoring systems shall be performed in
accordance with appendices A and B to part 75 of this chapter, and all
other quality assurance requirements specified in appendix K to part 75
of this chapter shall be met for sorbent trap monitoring systems.
0
10. Newly redesignated Sec. 60.51a is amended by:
0
a. Revising paragraph (a);
0
b. In paragraph (c) introductory text by revising the existing
references from ``Sec. 60.47a'' and ``Sec. 60.46a(h)'' to ``Sec.
60.49a'' and ``Sec. 60.48a(h),'' respectively;
0
c. In paragraph (d)(1) by revising the existing reference from ``Sec.
60.46a(d)'' to ``Sec. 60.48a(d)''; and
0
d. In paragraph (e)(1) by revising the existing reference from ``Sec.
60.48a'' to ``Sec. 60.50a.''
0
e. Redesignating paragraphs (g),(h), (i), and (j) as paragraphs (h),
(i), (j), and (k), respectively, and adding a new paragraph (g); and
0
f. Revising the first sentence of newly redesignated paragraph (k).
The revisions and additions read as follows:
Sec. 60.51a Reporting requirements.
(a) For sulfur dioxide, nitrogen oxides, particulate matter, and Hg
emissions, the performance test data from the initial and subsequent
performance test and from the performance evaluation of the continuous
monitors (including the transmissometer) are submitted to the
Administrator.
* * * * *
(g) For Hg, the following information shall be reported to the
Administrator:
(1) Company name and address;
(2) Date of report and beginning and ending dates of the reporting
period;
(3) The applicable Hg emission limit (lb/MWh); and
(4) For each month in the reporting period:
(i) The number of unit operating hours;
(ii) The number of unit operating hours with valid data for Hg
concentration, stack gas flow rate, moisture (if required), and
electrical output;
(iii) The monthly Hg emission rate (lb/MWh);
(iv) The number of hours of valid data excluded from the
calculation of the monthly Hg emission rate, due to unit startup,
shutdown and malfunction; and
(v) The 12-month rolling average Hg emission rate (lb/MWh); and
(5) The data assessment report (DAR) required by appendix F to this
part, or an equivalent summary of QA test results if the QA of part 75
of this chapter are implemented.
* * * * *
(k) The owner or operator of an affected facility may submit
electronic quarterly reports for SO2 and/or NOX
and/or opacity and/or Hg in lieu of submitting the written reports
required under paragraphs (b), (g), and (i) of this section. * * *
0
11. Section 60.52a is added to subpart Da to read as follows;
Sec. 60.52a Recordkeeping requirements.
The owner or operator of an affected facility subject to the
emissions limitations in Sec. 60.45a or Sec. 60.46a shall provide
notifications in accordance with Sec. 60.7(a) and shall maintain
records of all information needed to demonstrate compliance including
performance tests, monitoring data, fuel analyses, and calculations,
consistent with the requirements of Sec. 60.7(f).
[[Page 28657]]
Subpart GGGG--[Added]
0
12. Part 60 is amended by adding and reserving subpart GGGG to read as
follows:
Subpart GGGG--[Reserved]
0
13. Part 60 is amended by adding subpart HHHH to read as follows:
Subpart HHHH--Emission Guidelines and Compliance Times for Coal-
Fired Electric 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.
60.4108 Appeal procedures.
Hg Designated Representative for Hg Budget Sources
60.4110 Authorization and responsibilities of Hg Designated
Representative.
60.4111 Alternate Hg Designated Representative.
60.4112 Changing Hg Designated Representative and Alternate Hg
Designated Representative; changes in owners and operators.
60.4113 Certificate of Representation.
60.4114 Objections concerning Hg Designated 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 and term.
60.4124 Hg budget permit revisions.
60.4130 [Reserved]
Hg Allowance Allocations
60.4140 State trading budgets.
60.4141 Timing requirements for Hg allowance allocations.
60.4142 Hg allowance allocations.
Hg Allowance Tracking System
60.4150 [Reserved]
60.4151 Establishment of accounts.
60.4152 Responsibilities of Hg Authorized Account Representative.
60.4153 Recordation of Hg allowance allocations.
60.4154 Compliance with Hg budget emissions limitation.
60.4155 Banking.
60.4156 Account error.
60.4157 Closing of general accounts.
Hg Allowance Transfers
60.4160 Submission of Hg allowance transfers.
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.
Hg Budget Trading Program General Provisions
Sec. 60.4101 Purpose.
This subpart establishes the model rule comprising general
provisions and the designated representative, permitting, allowance,
and monitoring provisions for the State mercury (Hg) Budget Trading
Program, under section 111 of the Clean Air Act (CAA) and Sec.
60.24(h)(6), as a means of reducing national Hg emissions. The owner or
operator of a unit or a source shall comply with the requirements of
this subpart as a matter of Federal law only if the State with
jurisdiction over the unit and the source incorporates by reference
this subpart or otherwise adopts the requirements of this subpart in
accordance with Sec. 60.24(h)(6), the State submits to the
Administrator one or more revisions of the State plan that include such
adoption, and the Administrator approves such revisions. If the State
adopts the requirements of this subpart in accordance with Sec.
60.24(h)(6), then the State authorizes the Administrator to assist the
State in implementing the Hg Budget Trading Program by carrying out the
functions set forth for the Administrator in this subpart.
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.
Acid rain emissions limitation means a limitation on emissions of
sulfur dioxide or nitrogen oxides under the Acid Rain Program.
Acid Rain Program means a multi-state sulfur dioxide and nitrogen
oxides air pollution control and emission reduction program established
by the Administrator under title IV of the CAA and parts 72 through 78
of this chapter.
Administrator means the Administrator of the United States
Environmental Protection Agency or the Administrator's duly authorized
representative.
Allocate or allocation means the determination by the permitting
authority or the Administrator of the amount of Hg allowances to be
initially credited to a Hg Budget unit or a new unit set-aside under
Sec. Sec. 60.4140 through 60.4142.
Allowance transfer deadline means, for a control period, midnight
of March 1, if it is a business day, or, if March 1 is not a business
day, midnight of the first business day thereafter immediately
following the control period and is the deadline by which a Hg
allowance transfer must be submitted for recordation in a Hg Budget
source's compliance account in order to be used to meet the source's Hg
Budget emissions limitation for such control period in accordance with
Sec. 60.4154.
Alternate Hg designated representative means, for a Hg Budget
source and each Hg Budget unit at the source, the natural person who is
authorized by the owners and operators of the source and all such units
at the source in accordance with Sec. Sec. 60.4110 through 60.4114, to
act on behalf of the Hg designated representative in matters pertaining
to the Hg Budget Trading Program.
Automated data acquisition and handling system or DAHS means that
component of the continuous emission monitoring system (CEMS), or other
emissions monitoring system approved for use under Sec. Sec. 60.4170
though 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 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.
Bottoming-cycle cogeneration unit means a cogeneration unit in
which the energy input to the unit is first used to produce useful
thermal energy and at least some of the reject heat from the useful
thermal energy application or process is then used for electricity
production.
CAIR NOX Annual Trading Program means a multi-state nitrogen oxides
air pollution control and emission reduction program approved and
administered by the Administrator in accordance with subparts AA
through II of part 96 of this chapter and Sec. 51.123 of this chapter,
as a means of mitigating
[[Page 28658]]
interstate transport of fine particulates and nitrogen oxides.
CAIR NOX Ozone Season Trading Program means a multi-state nitrogen
oxides air pollution control and emission reduction program approved
and administered by the Administrator in accordance with subparts AAAA
through IIII of part 96 of this chapter and Sec. 51.123 of this
chapter, as a means of mitigating interstate transport of ozone and
nitrogen oxides.
CAIR SO2 Trading Program means a multi-state sulfur dioxide air
pollution control and emission reduction program approved and
administered by the Administrator in accordance with subparts AAA
through III of part 96 of this chapter and Sec. 51.124 of this
chapter, as a means of mitigating interstate transport of fine
particulates and sulfur dioxide.
Clean Air Act or CAA means the Clean Air Act, 42 U.S.C. 7401, et
seq.
Coal means any solid fuel classified as anthracite, bituminous,
subbituminous, or lignite by the American Society of Testing and
Materials (ASTM) Standard Specification for Classification of Coals by
Rank D388-77, 90, 91, 95, 98a, or 99 (Reapproved 2004)[epsiv]\1\
(incorporated by reference, see Sec. 60.17).
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 means combusting any amount of coal or coal-derived
fuel, alone or in combination with any amount of any other fuel, during
any year.
Cogeneration unit means a stationary, coal-fired boiler or
stationary, coal-fired combustion turbine:
(1) Having equipment used to produce electricity and useful thermal
energy for industrial, commercial, heating, or cooling purposes through
the sequential use of energy; and
(2) Producing during the 12-month period starting on the date the
unit first produces electricity and during any calendar year after
which the unit first produces electricity:
(i) For a topping-cycle cogeneration unit,
(A) Useful thermal energy not less than 5 percent of total energy
output; and
(B) Useful power that, when added to one-half of useful thermal
energy produced, is not less then 42.5 percent of total energy input,
if useful thermal energy produced is 15 percent or more of total energy
output, or not less than 45 percent of total energy input, if useful
thermal energy produced is less than 15 percent of total energy output.
(ii) For a bottoming-cycle cogeneration unit, useful power not less
than 45 percent of total energy input.
Combustion turbine means:
(1) An enclosed device comprising a compressor, a combustor, and a
turbine and in which the flue gas resulting from the combustion of fuel
in the combustor passes through the turbine, rotating the turbine; and
(2) If the enclosed device under paragraph (1) of this definition
is combined cycle, any associated heat recovery steam generator and
steam turbine.
Commence commercial operation means, with regard to a unit serving
a generator:
(1) 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.
(i) For a unit that is a Hg Budget unit under Sec. 60.4104 on the
date the unit commences commercial operation as defined in paragraph
(1) of this definition and that subsequently undergoes a physical
change (other than replacement of the unit by a unit at the same
source), such date shall remain the unit's date of commencement of
commercial operation.
(ii) For a unit that is a Hg Budget unit under Sec. 60.4104 on the
date the unit commences commercial operation as defined in paragraph
(1) of this definition and that is subsequently replaced by a unit at
the same source (e.g., repowered), the replacement unit shall be
treated as a separate unit with a separate date for commencement of
commercial operation as defined in paragraph (1) or (2) of this
definition as appropriate.
(2) Notwithstanding paragraph (1) of this definition and except as
provided in Sec. 60.4105, for a unit that is not a Hg Budget unit
under Sec. 60.4104 on the date the unit commences commercial operation
as defined in paragraph (1) of this definition, the unit's date for
commencement of commercial operation shall be the date on which the
unit becomes a Hg Budget unit under Sec. 60.4104.
(i) For a unit with a date for commencement of commercial operation
as defined in paragraph (2) of this definition and that subsequently
undergoes a physical change (other than replacement of the unit by a
unit at the same source), such date shall remain the unit's date of
commencement of commercial operation.
(ii) For a unit with a date for commencement of commercial
operation as defined in paragraph (2) of this definition and that is
subsequently replaced by a unit at the same source (e.g., repowered),
the replacement unit shall be treated as a separate unit with a
separate date for commencement of commercial operation as defined in
paragraph (1) or (2) of this definition as appropriate.
Commence operation means:
(1) 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.
(i) For a unit that is a Hg Budget unit under Sec. 60.4104 on the
date the unit commences operation as defined in paragraph (1) of this
definition and that subsequently undergoes a physical change (other
than replacement of the unit by a unit at the same source), such date
shall remain the unit's date of commencement of operation.
(ii) For a unit that is a Hg Budget unit under Sec. 60.4104 on the
date the unit commences operation as defined in paragraph (1) of this
definition and that is subsequently replaced by a unit at the same
source (e.g., repowered), the replacement unit shall be treated as a
separate unit with a separate date for commencement of operation as
defined in paragraph (1) or (2) of this definition as appropriate.
(2) Notwithstanding paragraph (1) of this definition and except as
provided in Sec. 60.4105, for a unit that is not a Hg Budget unit
under Sec. 60.4104 on the date the unit commences operation as defined
in paragraph (1) of this definition, the unit's date for commencement
of operation shall be the date on which the unit becomes a Hg Budget
unit under Sec. 60.4104.
(i) For a unit with a date for commencement of operation as defined
in paragraph (2) of this definition and that subsequently undergoes a
physical change (other than replacement of the unit by a unit at the
same source), such date shall remain the unit's date of commencement of
operation.
(ii) For a unit with a date for commencement of operation as
defined in paragraph (2) of this definition and that is subsequently
replaced by a unit at the same source (e.g., repowered), the
replacement unit shall be treated as a separate unit with a separate
date for commencement of operation as defined in paragraph (1) or (2)
of this definition as appropriate.
Common stack means a single flue through which emissions from 2 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 any Hg
[[Page 28659]]
allowance allocations for the Hg Budget units at the source are
initially recorded and in which are held any Hg allowances available
for use for a control period in order to meet the source's Hg Budget
emissions limitation in accordance with Sec. 60.4154.
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 Hg emissions, stack gas volumetric flow
rate, stack gas moisture content, and oxygen or carbon dioxide
concentration (as applicable), in a manner consistent with part 75 of
this chapter. The following systems are the principal types of CEMS
required under Sec. Sec. 60.4170 through 60.4176:
(1) A flow monitoring system, consisting of a stack flow rate
monitor and an automated data acquisition and handling system and
providing 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 data acquisition and
handling system and providing a permanent, continuous record of Hg
emissions in units of micrograms per dry standard cubic meter ([mu]g/
dscm);
(3) A moisture monitoring system, as defined in Sec. 75.11(b)(2)
of this chapter and providing a permanent, continuous record of the
stack gas moisture content, in percent H2O.
(4) A carbon dioxide monitoring system, consisting of a
CO2 concentration monitor (or an oxygen monitor plus
suitable mathematical equations from which the CO2
concentration is derived) and an automated data acquisition and
handling system and providing a permanent, continuous record of
CO2 emissions, in percent CO2; and
(5) An oxygen monitoring system, consisting of an O2
concentration monitor and an automated data acquisition and handling
system and providing a permanent, continuous record of O2,
in percent O2.
Control period means the period beginning January 1 of a calendar
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 designated representative and as determined by
the Administrator in accordance with Sec. Sec. 60.4170 through
60.4176.
Excess emissions means any ounce 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 Sec. 60.4151, that is not a compliance account.
Generator means a device that produces electricity.
Gross electrical output means, with regard to a cogeneration unit,
electricity made available for use, including any such electricity used
in the power production process (which process includes, but is not
limited to, any on-site processing or treatment of fuel combusted at
the unit and any on-site emission controls).
Heat input means, with regard to a specified period of 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 designated
representative and determined by the Administrator in accordance with
Sec. Sec. 60.4170 through 60.4176 and excluding 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 issued by the permitting
authority or the Administrator under Sec. Sec. 60.4140 through 60.4142
to emit one ounce of mercury during a control period of the specified
calendar year for which the authorization is allocated or of any
calendar year thereafter under the Hg Budget Trading Program. An
authorization to emit mercury that is not issued under the provisions
of a State plan that adopt the requirements of this subpart and are
approved by the Administrator in accordance with Sec. 60.24(h)(6)
shall not be a ``Hg allowance.''
Hg allowance deduction or deduct Hg allowances means the permanent
withdrawal of Hg allowances by the Administrator from a compliance
account in order to account for a specified number of ounces of total
mercury emissions from all Hg Budget units at a Hg Budget source for a
control period, determined in accordance with Sec. Sec. 60.4150 though
60.4157 and Sec. Sec. 60.4170 through 60.4176, or to account for
excess emissions.
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 means the system by which the
Administrator records allocations, deductions, and transfers of Hg
allowances under the Hg Budget Trading Program. Such allowances will be
allocated, held, deducted, or transferred only as whole allowances.
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 authorized account representative means, with regard to a
general account, a responsible natural person who is authorized, in
accordance with Sec. 60.4152, to transfer and otherwise dispose of Hg
allowances held in the general account and, with regard to a compliance
account, the Hg designated representative of the source.
Hg Budget emissions limitation means, for a Hg Budget source, the
equivalent in ounces of the Hg allowances available for deduction for
the source under Sec. 60.4154(a) and (b) for a control period.
Hg Budget permit means the legally binding and Federally
enforceable written document, or portion of such document, issued by
the permitting authority under Sec. Sec. 60.4120 through 60.4124,
including any permit revisions, specifying the Hg Budget Trading
Program requirements applicable to a Hg Budget source, to each Hg
Budget unit at the source, and to the owners and operators and the Hg
designated representative of the source and each such unit.
Hg Budget source means a source that includes one or more Hg Budget
units.
Hg Budget Trading Program means a multi-state Hg air pollution
control and emission reduction program approved and administered by the
Administrator in accordance with this subpart and Sec. 60.24(h)(6), as
a means of reducing national Hg emissions.
Hg Budget unit means a unit that is subject to the Hg Budget
Trading Program under Sec. 60.4104.
Hg designated representative means, for a Hg Budget source and each
Hg
[[Page 28660]]
Budget unit at the source, the natural person who is authorized by the
owners and operators of the source and all such units at the source, in
accordance with Sec. Sec. 60.4110 through 60.4114, to represent and
legally bind each owner and operator in matters pertaining to the Hg
Budget Trading Program.
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 generated by 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 no less 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.
Lignite means coal that is classified as lignite A or B according
to the American Society of Testing and Materials (ASTM) Standard
Specification for Classification of Coals by Rank D388-77, 90, 91, 95,
98a, or 99 (Reapproved 2004)[epsiv]\1\ (incorporated by reference, see
Sec. 60.17).
Maximum design heat input means, starting from the initial
installation of a unit, the maximum amount of fuel per hour (in Btu/hr)
that a unit is capable of combusting on a steady-state basis as
specified by the manufacturer of the unit, or, starting from the
completion of any subsequent physical change in the unit resulting in a
decrease in the maximum amount of fuel per hour (in Btu/hr) that a unit
is capable of combusting on a steady-state basis, such decreased
maximum amount as specified by the person conducting the physical
change.
Monitoring system means any monitoring system that meets the
requirements of Sec. Sec. 60.4170 through 60.4176, including a
continuous emissions monitoring system, an alternative monitoring
system, or an excepted monitoring system under part 75 of this chapter.
Nameplate capacity means, starting from the initial installation of
a generator, the maximum electrical generating output (in MWe) that the
generator is capable of producing on a steady-state basis and during
continuous operation (when not restricted by seasonal or other
deratings) as specified by the manufacturer of the generator or,
starting from the completion of any subsequent physical change in the
generator resulting in an increase in the maximum electrical generating
output (in MWe) that the generator is capable of producing on a steady-
state basis and during continuous operation (when not restricted by
seasonal or other deratings), such increased maximum amount as
specified by the person conducting the physical change.
Operator means any person who operates, controls, or supervises a
Hg Budget unit or a Hg Budget source and shall include, but not be
limited to, any holding company, utility system, or plant manager of
such a unit or source.
Ounce means 2.84 x 10\7\ micrograms. For the purpose of determining
compliance with the Hg Budget emissions limitation, total ounces of
mercury emissions for a control period shall be calculated as the sum
of all recorded hourly emissions (or the mass equivalent of the
recorded hourly emission rates) in accordance with Sec. Sec. 60.4170
through 60.4176, but with any remaining fraction of an ounce equal to
or greater than 0.50 ounces deemed to equal one ounce and any remaining
fraction of an ounce less than 0.50 ounces deemed to equal zero ounces.
Owner means any of the following persons:
(1) With regard to a Hg Budget source or a Hg Budget unit at a
source, respectively:
(i) Any holder of any portion of the legal or equitable title in a
Hg Budget unit at the source or the Hg Budget unit;
(ii) Any holder of a leasehold interest in a Hg Budget unit at the
source or the Hg Budget unit; or
(iii) Any purchaser of power from a Hg Budget unit at the source or
the Hg Budget unit under a life-of-the-unit, firm power contractual
arrangement; provided that, 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) on the revenues
or income from such Hg Budget unit; or
(2) With regard 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 the person's ownership
interest with respect to Hg allowances.
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 or, if no such agency has been so authorized, the
Administrator.
Potential electrical output capacity means 33 percent of a unit's
maximum design heat input, divided by 3,413 Btu/kWh, divided by 1,000
kWh/MWh, and multiplied by 8,760 hr/yr.
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 hard copy 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 into or
between Hg Allowance Tracking System accounts, 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.
Repowered means, with regard to a unit, replacement of a coal-fired
boiler with one of the following coal-fired technologies at the same
source as the coal-fired boiler:
(1) Atmospheric or pressurized fluidized bed combustion;
(2) Integrated gasification combined cycle;
(3) Magnetohydrodynamics;
(4) Direct and indirect coal-fired turbines;
(5) Integrated gasification fuel cells; or
(6) As determined by the Administrator in consultation with the
Secretary of Energy, a derivative of one or more of the technologies
under paragraphs (1) through (5) of this definition and any other coal-
fired technology capable of controlling multiple combustion emissions
simultaneously with improved boiler or generation efficiency and with
significantly greater waste reduction relative to the performance of
technology in widespread commercial use as of January 1, 2005.
Serial number means, for a Hg allowance, the unique identification
number assigned to each Hg allowance by the Administrator.
[[Page 28661]]
Sequential use of energy means:
(1) For a topping-cycle cogeneration unit, the use of reject heat
from electricity production in a useful thermal energy application or
process; or
(2) For a bottoming-cycle cogeneration unit, the use of reject heat
from useful thermal energy application or process in electricity
production.
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 CAA,
a ``source,'' including a ``source'' with multiple units, shall be
considered a single ``facility.''
State means:
(1) For purposes of referring to a governing entity, one of the
States in the United States, the District of Columbia, or, if approved
for treatment as a State under part 49 of this chapter, the Navajo
Nation or Ute Indian Tribe that adopts the Hg Budget Trading Program
pursuant to Sec. 60.24(h)(6); or
(2) For purposes of referring to geographic areas, one of the
States in the United States, the District of Columbia, the Navajo
Nation Indian country, or the Ute Tribe Indian country.
Subbituminous means coal that is classified as subbituminous A, B,
or C, according to the American Society of Testing and Materials (ASTM)
Standard Specification for Classification of Coals by Rank D388-77, 90,
91, 95, 98a, or 99 (Reapproved 2004)[epsiv]\1\ (incorporated by
reference, see Sec. 60.17).
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'' or ``service'' 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
CAA 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 CAA and part 70 or 71 of this chapter.
Topping-cycle cogeneration unit means a cogeneration unit in which
the energy input to the unit is first used to produce useful power,
including electricity, and at least some of the reject heat from the
electricity production is then used to provide useful thermal energy.
Total energy input means, with regard to a cogeneration unit, total
energy of all forms supplied to the cogeneration unit, excluding energy
produced by the cogeneration unit itself.
Total energy output means, with regard to a cogeneration unit, the
sum of useful power and useful thermal energy produced by the
cogeneration unit.
Unit means a stationary coal-fired boiler or a stationary coal-
fired combustion turbine.
Unit operating day means a calendar day in which a unit combusts
any fuel.
Unit operating hour or hour of unit operation means an hour in
which a unit combusts any fuel.
Useful power means, with regard to a cogeneration unit, electricity
or mechanical energy made available for use, excluding any such energy
used in the power production process (which process includes, but is
not limited to, any on-site processing or treatment of fuel combusted
at the unit and any on-site emission controls).
Useful thermal energy means, with regard to a cogeneration unit,
thermal energy that is:
(1) Made available to an industrial or commercial process (not a
power production process), excluding any heat contained in condensate
return or makeup water;
(2) Used in a heat application (e.g., space heating or domestic hot
water heating); or
(3) Used in a space cooling application (i.e., thermal energy used
by an absorption chiller).
Utility power distribution system means the portion of an
electricity grid owned or operated by a utility and dedicated to
delivering electricity to customers.
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.
H2O--water.
Hg--mercury.
hr--hour.
kW--kilowatt electrical.
kWh--kilowatt hour.
lb--pound.
MMBtu--million Btu.
MWe--megawatt electrical.
MWh--megawatt hour.
NOX--nitrogen oxides.
O2--oxygen.
ppm--parts per million.
scfh--standard cubic feet per hour.
SO2--sulfur dioxide.
yr--year.
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 subpart:
(a) Except as provided in paragraph (b) of this section, a unit
serving at any time, since the start-up of the unit's combustion
chamber, a generator with nameplate capacity of more than 25 MWe
producing electricity for sale.
(b) For a unit that qualifies as a cogeneration unit during the 12-
month period starting on the date the unit first produces electricity
and continues to qualify as a cogeneration unit, a cogeneration unit
serving at any time a generator with nameplate capacity of more than 25
MWe and supplying in any calendar year more than one-third of the
unit's potential electric output capacity or 219,000 MWh, whichever is
greater, to any utility power distribution system for sale. If a unit
qualifies as a cogeneration unit during the 12-month period starting on
the date the unit first produces electricity but subsequently no longer
qualifies as a cogeneration unit, the unit shall be subject to
paragraph (a) of this section starting on the day on which the unit
first no longer qualifies as a cogeneration unit.
Sec. 60.4105 Retired unit exemption.
(a)(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.
60.4106(c)(4) through (8), Sec. 60.4107, and Sec. Sec. 60.4150
through 60.4162.
(2) The exemption under paragraph (a)(1) of this section shall
become effective the day on which the Hg Budget unit is permanently
retired. Within 30 days of the unit's permanent retirement, the Hg
designated representative shall submit a statement to the permitting
authority otherwise responsible for administering any Hg Budget permit
for the unit and 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 was permanently retired on a
specific date and will comply with the requirements of paragraph (b) of
this section.
(3) After receipt of the statement under paragraph (a)(2) of this
section, the permitting authority will amend any permit under
Sec. Sec. 60.4120 through 60.4124 covering the source at which the
unit is located to add the provisions and requirements of the exemption
[[Page 28662]]
under paragraphs (a)(1) and (b) of this section.
(b) Special provisions. (1) A unit exempt under paragraph (a) of
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 paragraph (a)
of 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 paragraph (a) of 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 before 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
designated representative of a unit exempt under paragraph (a) of 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 paragraph (a) of 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 designated 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 (a) of this section shall lose its exemption:
(i) The date on which the Hg designated representative submits a Hg
Budget permit application for the unit under paragraph (b)(5) of this
section;
(ii) The date on which the Hg designated representative is required
under paragraph (b)(5) of this section to submit a Hg Budget permit
application for the unit; or
(iii) The date on which the unit resumes operation, if the Hg
designated representative is not required to submit a Hg Budget permit
application for the unit.
(7) For the purpose of applying monitoring, reporting, and
recordkeeping requirements under Sec. Sec. 60.4170 through 60.4176, a
unit that loses its exemption under paragraph (a) of this section shall
be treated as a unit that commences operation and commercial operation
on the first date on which the unit resumes operation.
Sec. 60.4106 Standard requirements.
(a) Permit Requirements. (1) The Hg designated 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(a) and (b); and
(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 under Sec. Sec. 60.4120
through 60.4124 for the source and operate the source and the unit in
compliance with such Hg Budget permit.
(3) The owners and operators of a Hg Budget source that is not
required to have a title V operating permit and each Hg Budget unit
that is not 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 and such Hg Budget unit.
(b) Monitoring, reporting, and recordkeeping requirements. (1) The
owners and operators, and the Hg designated representative, of each Hg
Budget source and each Hg Budget unit at the source shall comply with
the monitoring, reporting, and recordkeeping 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 each Hg Budget source with the Hg Budget emissions
limitation under paragraph (c) of this section.
(c) Mercury emission requirements. (1) As of the 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, in the
source's compliance account, Hg allowances available for compliance
deductions for the control period under Sec. 60.4154(a) in an amount
not less than the ounces of total mercury emissions for the control
period from all Hg Budget units at the source, as determined in
accordance with Sec. Sec. 60.4170 through 60.4176.
(2) 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 deadline for meeting the unit's monitor certification
requirements under Sec. 60.4170(b)(1) or (2).
(3) A Hg allowance shall not be deducted, for compliance with the
requirements under paragraph (c)(1) of this section, for a control
period in a calendar year before the year for which the Hg allowance
was allocated.
(4) Hg allowances shall be held in, deducted from, or transferred
into or among Hg Allowance Tracking System accounts in accordance with
Sec. Sec. 60.4160 through 60.4162.
(5) A Hg allowance 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, or an exemption under Sec. 60.4105 and no provision
of law shall be construed to limit the authority of the State or the
United States to terminate or limit such authorization.
(6) A Hg allowance does not constitute a property right.
(7) 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 source that
includes the Hg Budget unit.
(d) Excess emissions requirements. (1) If a Hg Budget source emits
mercury during any control period in excess of the Hg Budget emissions
limitation, then:
(i) The owners and operators of the source and each Hg Budget unit
at the source shall surrender the Hg allowances required for deduction
under Sec. 60.4154(d)(1) and pay any fine, penalty, or assessment or
comply with any other remedy imposed, for the same violations, under
the Clean Air Act or applicable State law; and
(ii) Each ounce of such excess emissions and each day of such
control period shall constitute a separate violation of this subpart,
the Clean Air Act, and applicable State law.
(2) [Reserved]
(e) Recordkeeping and reporting requirements. (1) Unless otherwise
provided, the owners and operators of
[[Page 28663]]
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 before the end of 5 years, in writing
by the permitting authority or the Administrator.
(i) The certificate of representation under Sec. 60.4113 for the
Hg designated representative for the source and each Hg Budget unit at
the source and all documents that demonstrate the truth of the
statements in the 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 certificate of representation under Sec.
60.4113 changing the Hg designated 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 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 designated representative of a Hg Budget source and each
Hg Budget unit at the source shall submit the reports required under
the Hg Budget Trading Program, including those under Sec. Sec. 60.4170
through 60.4176.
(f) Liability. (1) Each Hg Budget source and each Hg Budget unit
shall meet the requirements of the Hg Budget Trading Program.
(2) Any provision of the Hg Budget Trading Program that applies to
a Hg Budget source or the Hg designated 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.
(3) Any provision of the Hg Budget Trading Program that applies to
a Hg Budget unit or the Hg designated representative of a Hg Budget
unit shall also apply to the owners and operators of such unit.
(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 the Hg designated
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 CAA.
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.
Sec. 60.4108 Appeal procedures.
The appeal procedures for decisions of the Administrator under the
Hg Budget Trading Program shall be the procedures set forth in part 78
of this chapter. The terms ``subpart HHHH of this part,'' ``Sec.
60.4141(b)(2) or (c)(2),'' ``Sec. 60.4154,'' ``Sec. 60.4156,''
``Sec. 60.4161,'' ``Sec. 60.4175,'' ``Hg allowances,'' ``Hg Allowance
Tracking System Account,'' ``Hg designated representative,'' ``Hg
authorized account representative,'' and ``Sec. 60.4106'' apply
instead of the terms ``subparts AA through II of part 96 of this
chapter,'' ``Sec. 96.141(b)(2) or (c)(2),'' ``Sec. 96.154,'' ``Sec.
96.156,'' ``Sec. 96.161,'' ``Sec. 96.175,'' ``CAIR NOX
allowances,'' ``CAIR NOX Allowance Tracking System
account,'' ``CAIR designated representative,'' ``CAIR authorized
account representative,'' and ``Sec. 96.106.''
Hg Designated Representative for Hg Budget Sources
Sec. 60.4110 Authorization and Responsibilities of Hg Designated
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 designated 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 designated 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 and shall act in
accordance with the certification statement in Sec. 60.4113(a)(4)(iv).
(c) Upon receipt by the Administrator of a complete certificate of
representation under Sec. 60.4113, the Hg designated 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 represented and each Hg Budget unit at the source in
all matters pertaining to the Hg Budget Trading Program,
notwithstanding any agreement between the Hg designated representative
and such owners and operators. The owners and operators shall be bound
by any decision or order issued to the Hg designated representative by
the permitting authority, the Administrator, or a court regarding the
source or unit.
(d) No Hg Budget permit will be issued, no emissions data reports
will be accepted, and no Hg Allowance Tracking System account will be
established for a Hg Budget unit at a source, until the Administrator
has received a complete certificate of representation under Sec.
60.4113 for a Hg designated 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 designated 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 designated representative: ``I am authorized to
make this submission on behalf of the owners and operators of the
source or 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.
[[Page 28664]]
Sec. 60.4111 Alternate Hg Designated Representative.
(a) A certificate of representation under Sec. 60.4113 may
designate one and only one alternate Hg designated representative, who
may act on behalf of the Hg designated representative. The agreement by
which the alternate Hg designated representative is selected shall
include a procedure for authorizing the alternate Hg designated
representative to act in lieu of the Hg designated representative.
(b) Upon receipt by the Administrator of a complete certificate of
representation under Sec. 60.4113, any representation, action,
inaction, or submission by the alternate Hg designated representative
shall be deemed to be a representation, action, inaction, or submission
by the Hg designated representative.
(c) Except in this section and Sec. Sec. 60.4102, 60.4110(a) and
(d), 60.4112, 60.4113, 60.4151, and 60.4174, whenever the term ``Hg
designated representative'' is used in this subpart, the term shall be
construed to include the Hg designated representative or any alternate
Hg designated representative.
Sec. 60.4112 Changing Hg Designated Representative and Alternate Hg
Designated Representative; changes in owners and operators.
(a) Changing Hg designated representative. The Hg designated
representative may be changed at any time upon receipt by the
Administrator of a superseding complete certificate of representation
under Sec. 60.4113. Notwithstanding any such change, all
representations, actions, inactions, and submissions by the previous Hg
designated representative before the time and date when the
Administrator receives the superseding certificate of representation
shall be binding on the new Hg designated representative and the owners
and operators of the Hg Budget source and the Hg Budget units at the
source.
(b) Changing alternate Hg designated representative. The alternate
Hg designated representative may be changed at any time upon receipt by
the Administrator of a superseding complete certificate of
representation under Sec. 60.4113. Notwithstanding any such change,
all representations, actions, inactions, and submissions by the
previous alternate Hg designated representative before the time and
date when the Administrator receives the superseding certificate of
representation shall be binding on the new alternate Hg designated
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 in the certificate of
representation under Sec. 60.4113, such new owner or operator shall be
deemed to be subject to and bound by the certificate of representation,
the representations, actions, inactions, and submissions of the Hg
designated representative and any alternate Hg designated
representative of the source or unit, and the decisions and orders of
the permitting authority, the Administrator, or a court, 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 designated representative or any
alternate Hg designated representative shall submit a revision to the
certificate of representation under Sec. 60.4113 amending the list of
owners and operators to include the change.
Sec. 60.4113 Certificate of Representation.
(a) A complete certificate of representation for a Hg designated
representative or an alternate Hg designated 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 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 designated
representative and any alternate Hg designated 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 statements by the Hg designated
representative and any alternate Hg designated representative:
(i) ``I certify that I was selected as the Hg designated
representative or alternate Hg designated representative, as
applicable, by an agreement binding on the owners and operators of the
source and each Hg Budget unit at the source.''
(ii) ``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 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.''
(iii) ``I certify that the owners and operators of the source and
of each Hg Budget unit at the source shall be bound by any order issued
to me by the Administrator, the permitting authority, or a court
regarding the source or unit.''
(iv) ``Where there are multiple holders of a legal or equitable
title to, or a leasehold interest in, a Hg Budget unit, or where a
customer purchases power from a Hg Budget unit under a life-of-the-
unit, firm power contractual arrangement, I certify that: I have given
a written notice of my selection as the `Hg designated representative'
or `alternate Hg designated representative,' as applicable, and of the
agreement by which I was selected to each owner and operator of the
source and of each Hg Budget unit at the source; and Hg allowances and
proceeds of transactions involving Hg allowances will be deemed to be
held or distributed in proportion to each holder's legal, equitable,
leasehold, or contractual reservation or entitlement, except that, if
such multiple holders have expressly provided for a different
distribution of Hg allowances by contract, Hg allowances and proceeds
of transactions involving Hg allowances will be deemed to be held or
distributed in accordance with the contract.''
(5) The signature of the Hg designated representative and any
alternate Hg designated representative and the dates signed.
(b) Unless otherwise required by the permitting authority or the
Administrator, documents of agreement referred to in the 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 Designated Representative.
(a) Once a complete certificate of representation under Sec.
60.4113 has been submitted and received, the permitting authority and
the Administrator will rely on the certificate of representation unless
and until a superseding complete 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,
[[Page 28665]]
action, inaction, or submission, of the Hg designated representative
shall affect any representation, action, inaction, or submission of the
Hg designated 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
designated 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 section and Sec. Sec. 60.4121 through
60.4124.
(b) Each Hg Budget permit shall contain, with regard to the Hg
Budget source and the Hg Budget units at the source covered by the Hg
Budget permit, all applicable Hg Budget Trading Program requirements
and shall be a complete and separable portion of the title V operating
permit.
Sec. 60.4121 Submission of Hg budget permit applications.
(a) Duty to apply. The Hg designated 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 for the source covering each Hg Budget unit at the
source 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.
(b) Duty to Reapply. For a Hg Budget source required to have a
title V operating permit, the Hg designated representative shall submit
a complete Hg Budget permit application under Sec. 60.4122 for the
source covering each Hg Budget unit at the source to renew the Hg
Budget permit in accordance with the permitting authority's title V
operating permits regulations addressing 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;
(b) Identification of each Hg Budget unit at the Hg Budget source;
and
(c) The standard requirements under Sec. 60.4106.
Sec. 60.4123 Hg budget permit contents and term.
(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 account of the Hg Budget source covered by the permit.
(c) The term of the Hg Budget permit will be set by the permitting
authority, as necessary to facilitate coordination of the renewal of
the Hg Budget permit with issuance, revision, or renewal of the Hg
Budget source's title V operating 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.
Sec. 60.4130 [Reserved]
Hg Allowance Allocations
Sec. 60.4140 State trading budgets.
The State trading budgets for annual allocations of Hg allowances
for the control periods in 2010 through 2017 and in 2018 and thereafter
are respectively as follows:
------------------------------------------------------------------------
State trading budget
(tons)
State -------------------------
2018 and
2010-2017 thereafter
------------------------------------------------------------------------
Alaska........................................ 0.005 0.002
Alabama....................................... 1.289 0.509
Arkansas...................................... 0.516 0.204
Arizona....................................... 0.454 0.179
California.................................... 0.041 0.016
Colorado...................................... 0.706 0.279
Connecticut................................... 0.053 0.021
Delaware...................................... 0.072 0.028
District of Columbia.......................... 0 0
Florida....................................... 1.233 0.487
Georgia....................................... 1.227 0.484
Hawaii........................................ 0.024 0.009
Idaho......................................... 0 0
Iowa.......................................... 0.727 0.287
Illinois...................................... 1.594 0.629
Indiana....................................... 2.098 0.828
Kansas........................................ 0.723 0.285
Kentucky...................................... 1.525 0.602
Louisiana..................................... 0.601 0.237
Massachusetts................................. 0.172 0.068
Maryland...................................... 0.49 0.193
Maine......................................... 0.001 0.001
Michigan...................................... 1.303 0.514
Minnesota..................................... 0.695 0.274
Missouri...................................... 1.393 0.55
Mississippi................................... 0.291 0.115
Montana....................................... 0.378 0.149
Navajo Nation Indian country.................. 0.601 0.237
North Carolina................................ 1.133 0.447
North Dakota.................................. 1.564 0.617
Nebraska...................................... 0.421 0.166
New Hampshire................................. 0.063 0.025
New Jersey.................................... 0.153 0.06
New Mexico.................................... 0.299 0.118
Nevada........................................ 0.285 0.112
New York...................................... 0.393 0.155
Ohio.......................................... 2.057 0.812
Oklahoma...................................... 0.721 0.285
Oregon........................................ 0.076 0.03
Pennsylvania.................................. 1.78 0.702
Rhode Island.................................. 0 0
South Carolina................................ 0.58 0.229
South Dakota.................................. 0.072 0.029
Tennessee..................................... 0.944 0.373
Texas......................................... 4.657 1.838
Utah.......................................... 0.506 0.2
Ute Indian Tribe Indian country............... 0.06 0.024
Virginia...................................... 0.592 0.234
Vermont....................................... 0 0
Washington.................................... 0.198 0.078
Wisconsin..................................... 0.89 0.351
West Virginia................................. 1.394 0.55
Wyoming....................................... 0.952 0.376
------------------------------------------------------------------------
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 a format prescribed
by the Administrator and in accordance with Sec. 60.4142(a) and (b),
for the control periods in 2010, 2011, 2012, 2013, and 2014.
(b)(1) By October 31, 2008 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(a) and (b), for the control period in
the sixth year after the year of
[[Page 28666]]
the applicable deadline for submission under this paragraph.
(2) If the permitting authority fails to submit to the
Administrator the Hg allowance allocations in accordance with paragraph
(b)(1) of this section, the Administrator will assume that the
allocations of Hg allowances for the applicable control period are the
same as for the control period that immediately precedes the applicable
control period, except that, if the applicable control period is in
2018, the Administrator will assume that the allocations equal the
allocations for the control period in 2017, multiplied by the amount of
ounces (i.e., tons multiplied by 32,000 ounces/ton) of Hg emissions in
the applicable State trading budget under Sec. 60.4140 for 2018 and
thereafter and divided by such amount of ounces of Hg emissions for
2010 through 2017.
(c)(1) By October 31, 2010 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(a), (c), and (d), for the control
period in the year of the applicable deadline for submission under this
paragraph.
(2) If the permitting authority fails to submit to the
Administrator the Hg allowance allocations in accordance with paragraph
(c)(1) of this section, the Administrator will assume that the
allocations of Hg allowances for the applicable control period are the
same as for the control period that immediately precedes the applicable
control period, except that, if the applicable control period is in
2018, the Administrator will assume that the allocations equal the
allocations for the control period in 2017, multiplied by the amount of
ounces (i.e., tons multiplied by 32,000 ounces/ton) of Hg emissions in
the applicable State trading budget under Sec. 60.4140 for 2018 and
thereafter and divided by such amount of ounces of Hg emissions for
2010 through 2017 and except that any Hg Budget unit that would
otherwise be allocated Hg allowances under Sec. 60.4142(a) and (b), as
well as under Sec. 60.4142(a), (c), and (d), for the applicable
control period will be assumed to be allocated no Hg allowances under
Sec. 60.4142(a), (c), and (d) for the applicable control period.
Sec. 60.4142 Hg allowance allocations.
(a)(1) The baseline heat input (in MMBtu) used with respect to Hg
allowance allocations under paragraph (b) of this section for each Hg
Budget unit will be:
(i) For units commencing operation before January 1, 2001, the
average of the three highest amounts of the unit's adjusted control
period heat input for 2000 through 2004, with the adjusted control
period heat input for each year calculated as the sum of the following:
(A) Any portion of the unit's control period heat input for the
year that results from the unit's combustion of lignite, multiplied by
3.0;
(B) Any portion of the unit's control period heat input for the
year that results from the unit's combustion of subbituminous coal,
multiplied by 1.25; and
(C) Any portion of the unit's control period heat input for the
year that is not covered by paragraph (a)(1)(i)(A) or (B) of this
section, multiplied by 1.0.
(ii) For units commencing operation on or after January 1, 2001 and
operating each calendar year during a period of 5 or more consecutive
calendar years, the average of the 3 highest amounts of the unit's
total converted control period heat input over the first such 5 years.
(2)(i) A unit's control period heat input for a calendar year under
paragraphs (a)(1)(i) of this section, and a unit's total ounces of Hg
emissions during a calendar year under paragraph (c)(3) of this
section, will be determined in accordance with part 75 of this chapter,
to the extent the 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, to
the extent the unit was not otherwise subject to the requirements of
part 75 of this chapter for the year. The unit's types and amounts of
fuel combusted, under paragraph (a)(1)(i) of this section, will be
based on the best available data reported to the permitting authority
for the unit.
(ii) A unit's converted control period heat input for a calendar
year specified under paragraph (a)(1)(ii) of this section equals:
(A) Except as provided in paragraph (a)(2)(ii)(B) or (C) of this
section, the control period gross electrical output of the generator or
generators served by the unit multiplied by 7,900 Btu/kWh and divided
by 1,000,000 Btu/MMBtu, provided that if a generator is served by 2 or
more units, then the gross electrical output of the generator will be
attributed to each unit in proportion to the unit's share of the total
control period heat input of such units for the year;
(B) For a unit that is a boiler and has equipment used to produce
electricity and useful thermal energy for industrial, commercial,
heating, or cooling purposes through the sequential use of energy, the
total heat energy (in Btu) of the steam produced by the boiler during
the control period, divided by 0.8 and by 1,000,000 Btu/MMBtu; or
(C) For a unit that is a combustion turbine and has equipment used
to produce electricity and useful thermal energy for industrial,
commercial, heating, or cooling purposes through the sequential use of
energy, the control period gross electrical output of the enclosed
device comprising the compressor, combustor, and turbine multiplied by
3,413 Btu/kWh, plus the total heat energy (in Btu) of the steam
produced by any associated heat recovery steam generator during the
control period divided by 0.8, and with the sum divided by 1,000,000
Btu/MMBtu.
(b)(1) For each control period in 2010 and thereafter, the
permitting authority will allocate to all Hg Budget units in the State
that have a baseline heat input (as determined under paragraph (a) of
this section) a total amount of Hg allowances equal to 95 percent for a
control period in 2010 through 2014, and 97 percent for a control
period in 2015 and thereafter, of the amount of ounces (i.e., tons
multiplied by 32,000 ounces/ton) of Hg emissions in the applicable
State trading budget under Sec. 60.4140 (except as provided in
paragraph (d) of this section).
(2) The permitting authority will allocate Hg allowances to each Hg
Budget unit under paragraph (b)(1) of this section in an amount
determined by multiplying the total amount of Hg allowances allocated
under paragraph (b)(1) of this section by the ratio of the baseline
heat input of such Hg Budget unit to the total amount of baseline heat
input of all such Hg Budget units in the State and rounding to the
nearest whole allowance as appropriate.
(c) For each control period in 2010 and thereafter, the permitting
authority will allocate Hg allowances to Hg Budget units in the State
that commenced operation on or after January 1, 2001 and do not yet
have a baseline heat input (as determined under paragraph (a) of this
section), in accordance with the following procedures:
(1) The permitting authority will establish a separate new unit
set-aside for each control period. Each new unit set-aside will be
allocated Hg allowances equal to 5 percent for a control period in 2010
through 2014, and 3 percent for a control period in 2015 and
thereafter, of the amount of ounces (i.e., tons multiplied by 32,000
ounces/ton) of Hg emissions in the
[[Page 28667]]
applicable State trading budget under Sec. 60.4140.
(2) The Hg designated representative of such a Hg Budget unit may
submit to the permitting authority a request, in a format specified by
the permitting authority, to be allocated Hg allowances, starting with
the later of the control period in 2010 or the first control period
after the control period in which the Hg Budget unit commences
commercial operation and until the first control period for which the
unit is allocated Hg allowances under paragraph (b) of this section.
The Hg allowance allocation request must be submitted on or before July
1 of the first control period for which the Hg allowances are requested
and after the date on which the Hg Budget unit commences commercial
operation.
(3) In a Hg allowance allocation request under paragraph (c)(2) of
this section, the Hg designated representative may request for a
control period Hg allowances in an amount not exceeding the Hg Budget
unit's total ounces of Hg emissions during the control period
immediately before such control period.
(4) The permitting authority will review each Hg allowance
allocation request under paragraph (c)(2) of this section and will
allocate Hg allowances for each control period pursuant to such request
as follows:
(i) The permitting authority will accept an allowance allocation
request only if the request meets, or is adjusted by the permitting
authority as necessary to meet, the requirements of paragraphs (c)(2)
and (3) of this section.
(ii) On or after July 1 of the control period, the permitting
authority will determine the sum of the Hg allowances requested (as
adjusted under paragraph (c)(4)(i) of this section) in all allowance
allocation requests accepted under paragraph (c)(4)(i) of this section
for the control period.
(iii) If the amount of Hg allowances in the new unit set-aside for
the control period is greater than or equal to the sum under paragraph
(c)(4)(ii) of this section, then the permitting authority will allocate
the amount of Hg allowances requested (as adjusted under paragraph
(c)(4)(i) of this section) to each Hg Budget unit covered by an
allowance allocation request accepted under paragraph (c)(4)(i) of this
section.
(iv) If the amount of Hg allowances in the new unit set-aside for
the control period is less than the sum under paragraph (c)(4)(ii) of
this section, then the permitting authority will allocate to each Hg
Budget unit covered by an allowance allocation request accepted under
paragraph (c)(4)(i) of this section the amount of the Hg allowances
requested (as adjusted under paragraph (c)(4)(i) of this section),
multiplied by the amount of Hg allowances in the new unit set-aside for
the control period, divided by the sum determined under paragraph
(c)(4)(ii) of this section, and rounded to the nearest whole allowance
as appropriate.
(v) The permitting authority will notify each Hg designated
representative that submitted an allowance allocation request of the
amount of Hg allowances (if any) allocated for the control period to
the Hg Budget unit covered by the request.
(d) If, after completion of the procedures under paragraph (c)(4)
of this section for a control period, any unallocated Hg allowances
remain in the new unit set-aside for the control period, the permitting
authority will allocate to each Hg Budget unit that was allocated Hg
allowances under paragraph (b) of this section 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 95 percent for 2010 through 2014, and 97
percent for 2014 and thereafter, of the amount of ounces (i.e., tons
multiplied by 32,000 ounces/ton) of Hg emissions in the applicable
State trading budget under Sec. 60.4140, and rounded to the nearest
whole allowance as appropriate.
Hg Allowance Tracking System
Sec. 60.4150 [Reserved]
Sec. 60.4151 Establishment of accounts.
(a) Compliance accounts. Upon receipt of a complete certificate of
representation under Sec. 60.4113, the Administrator will establish a
compliance account for the Hg Budget source for which the certificate
of representation was submitted unless the source already has a
compliance account.
(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 Hg 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.
(ii) 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) Organization name and type of organization, if applicable;
(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 Hg 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 alternate Hg authorized account
representative, as applicable, by an agreement that is binding on all
persons who have an ownership interest with respect to Hg 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.
(iii) 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. (i) Upon
receipt by the Administrator of a complete application for a general
account under paragraph (b)(1) of this section:
(A) The Administrator will establish a general account for the
person or persons for whom the application is submitted.
(B) The Hg authorized account representative and any alternate Hg
authorized account representative for
[[Page 28668]]
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,
notwithstanding 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.
(C) 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.
(ii) 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 authorized 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.''
(iii) 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)(ii) 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 before 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 before
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 application for a general account, such
new person shall be deemed to be subject to and bound by the
application for a general account, the representation, actions,
inactions, and submissions of the Hg authorized account representative
and any alternate Hg authorized account representative of the account,
and the decisions and orders of the Administrator or a court, 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 Responsibilities of Hg Authorized Account
Representative.
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.
Sec. 60.4153 Recordation of Hg allowance allocations.
(a) By December 1, 2006, the Administrator will record in the Hg
Budget source's compliance account the Hg allowances allocated for the
Hg Budget units at a source, as submitted by the permitting authority
in accordance with Sec. 60.4141(a), for the control periods in 2010,
2011, 2012, 2013, and 2014.
(b) By December 1, 2008, the Administrator will record in the Hg
Budget source's compliance account the Hg allowances allocated for the
Hg Budget units at the source, as submitted
[[Page 28669]]
by the permitting authority or as determined by the Administrator in
accordance with Sec. 60.4141(b), for the control period in 2015.
(c) In 2011 and each year thereafter, after the Administrator has
made all deductions (if any) from a Hg Budget source's compliance
account under Sec. 60.4154, the Administrator will record in the Hg
Budget source's compliance account the Hg allowances allocated for the
Hg Budget units at the source, as submitted by the permitting authority
or determined by the Administrator in accordance with Sec. 60.4141(b),
for the control period in the sixth year after the year of the control
period for which such deductions were or could have been made.
(d) By December 1, 2010 and December 1 of each year thereafter, the
Administrator will record in the Hg Budget source's compliance account
the Hg allowances allocated for the Hg Budget units at the source, as
submitted by the permitting authority or determined by the
Administrator in accordance with Sec. 60.4141(c), for the control
period in the year of the applicable deadline for recordation under
this paragraph.
(e) Serial numbers for allocated Hg allowances. When recording the
allocation of Hg allowances for a Hg Budget unit in a compliance
account, the Administrator will assign each Hg allowance a unique
identification number that will include digits identifying the year of
the control period for which the Hg allowance is allocated.
Sec. 60.4154 Compliance with Hg budget emissions limitation.
(a) 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 calendar year only if the Hg
allowances:
(1) Were allocated for the control period in the year or a prior
year;
(2) Are held in the compliance account as of the allowance transfer
deadline for the control period or are transferred into the compliance
account by a Hg allowance transfer correctly submitted for recordation
under Sec. Sec. 60.4160 through 60.4162 by the allowance transfer
deadline for the control period; and
(3) Are not necessary for deductions for excess emissions for a
prior control period under paragraph (d) of this section.
(b) Deductions for compliance. Following the recordation, in
accordance with Sec. Sec. 60.4160 through 60.4162, of Hg allowance
transfers submitted for recordation in a source's compliance account by
the allowance transfer deadline for a control period, the Administrator
will deduct from the compliance account Hg allowances available under
paragraph (a) of this section in order to determine whether the source
meets the Hg Budget emissions limitation for the control period, as
follows:
(1) Until the amount of Hg allowances deducted 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; or
(2) If there are insufficient Hg allowances to complete the
deductions in paragraph (b)(1) of this section, 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 a source's compliance account may
request that specific Hg allowances, identified by serial number, in
the compliance account be deducted for emissions or excess emissions
for a control period in accordance with paragraph (b) or (d) of this
section. Such request shall be submitted to the Administrator by the
allowance transfer deadline for the control period and include, in a
format prescribed by the Administrator, the identification of the Hg
Budget source and the appropriate serial numbers.
(2) First-in, first-out. The Administrator will deduct Hg
allowances under paragraph (b) or (d) of this section 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) Any Hg allowances that were allocated to the units at the
source, in the order of recordation; and then
(ii) Any Hg allowances that were allocated to any unit and
transferred and recorded in the compliance account pursuant to
Sec. Sec. 60.4160 through 60.4162, in the order of recordation.
(d) Deductions for excess emissions. (1) After making the
deductions for compliance under paragraph (b) of this section for a
control period in a calendar year in which the Hg Budget source has
excess emissions, the Administrator will deduct from the source's
compliance account an amount of Hg allowances, allocated for the
control period in the immediately following calendar year, equal to 3
times the number of ounces of the source's excess emissions.
(2) Any allowance deduction required under paragraph (d)(1) of this
section shall not affect the liability of the owners and operators of
the Hg Budget source or the Hg Budget units at the source 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.
(e) Recordation of deductions. The Administrator will record in the
appropriate compliance account all deductions from such an account
under paragraph (b) or (d) of this section.
(f) Administrator's action on submissions. (1) The Administrator
may review and conduct independent audits concerning any submission
under the Hg Budget Trading Program and make appropriate adjustments of
the information in the submissions.
(2) The Administrator may deduct Hg allowances from or transfer Hg
allowances to a source's compliance account based on the information in
the submissions, as adjusted under paragraph (f)(1) of this section.
Sec. 60.4155 Banking.
(a) Hg allowances may be banked for future use or transfer in a
compliance account or a general account in accordance with paragraph
(b) of this section.
(b) 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. 60.4154, 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 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 submit to the Administrator a request to close the account, which
shall include a correctly submitted allowance transfer under Sec.
60.4160 through 60.4162 for any Hg allowances in the account to one or
more other Hg Allowance Tracking System accounts.
(b) If a general account has no allowance transfers in or out of
the account for a 12-month period or longer and does not contain any Hg
allowances, the Administrator may notify the Hg authorized account
[[Page 28670]]
representative for the account that the account will be closed
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 through 60.4162 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.
An 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 account numbers for both the transferor and transferee
accounts;
(b) The serial number of each Hg allowance that is in the
transferor account and is to be transferred; and
(c) The 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 (except as provided in paragraph (b) of
this section) of receiving a Hg allowance transfer, 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 after
the allowance transfer deadline for a control period and that includes
any Hg allowances allocated for any control period before such
allowance transfer deadline will not be recorded until after the
Administrator completes the deductions under Sec. 60.4154 for the
control period immediately before such allowance transfer deadline.
(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
designated representative, of a Hg Budget unit, shall comply with the
monitoring, recordkeeping, and reporting requirements as provided in
this section, Sec. Sec. 60.4171 through 60.4176, and 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 designated 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 same monitoring, recordkeeping,
and reporting requirements as a Hg Budget unit.
(a) Requirements for installation, certification, and data
accounting. The owner or operator of each Hg Budget unit shall:
(1) Install all monitoring systems required under this section and
Sec. Sec. 60.4171 through 60.4176 for monitoring Hg mass emissions and
individual unit heat input (including all systems required to monitor
Hg concentration, stack gas moisture content, stack gas flow rate, and
CO2 or O2 concentration, as applicable, 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 section,
Sec. Sec. 60.4171 through 60.4176, and subpart I of part 75 of this
chapter applicable to the monitoring systems under paragraph (a)(1) of
this section; and
(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
monitoring system certification and other requirements of paragraphs
(a)(1) and (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
commercial operation before July 1, 2008, by January 1, 2009.
(2) For the owner or operator of a Hg Budget unit that commences
commercial 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 for which
construction of a new stack or flue or installation of add-on Hg
emission controls, a flue gas desulfurization system, a selective
catalytic reduction system, or a compact hybrid particulate collector
system is completed after the applicable deadline under paragraph
(b)(1) or (2) of this section, by 90 unit operating days or 180
calendar days, whichever occurs first, after the date on which
emissions first exit to the atmosphere through the new stack or flue,
add-on Hg emissions controls, flue gas desulfurization system,
selective catalytic reduction system, or compact hybrid particulate
collector system.
(c) Reporting data. (1) Except as provided in paragraph (c)(2) of
this section, 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 for any monitoring system under paragraph (a)(1) of this
section shall, for each such monitoring system, determine, record, and
report maximum potential (or, as appropriate, minimum potential) values
for Hg concentration, stack gas flow rate, stack gas moisture content,
and any other parameters required to determine Hg mass emissions and
heat input in accordance with Sec. 75.80(g) of this chapter.
(2) The owner or operator of a Hg Budget unit that does not meet
the
[[Page 28671]]
applicable compliance date set forth in paragraph (b)(3) of this
section for any monitoring system under paragraph (a)(1) of this
section shall, for each such monitoring system, determine, record, and
report substitute data using the applicable missing data procedures in
subpart D of part 75 of this chapter, in lieu of the maximum potential
(or, as appropriate, minimum potential) values, for a parameter if the
owner or operator demonstrates that there is continuity between the
data streams for that parameter before and after the construction or
installation under paragraph (b)(3) of this section.
(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 to any requirement of this section and
Sec. Sec. 60.4171 through 60.4176 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 section, Sec. Sec. 60.4171 through
60.4176, and subpart I of 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 section, Sec. Sec. 60.4171 through
60.4176, and subpart I of 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 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 section, Sec. Sec. 60.4171 through
60.4176, and subpart I of 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 designated 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)(3)(i).
Sec. 60.4171 Initial certification and recertification procedures.
(a) The owner or operator of a Hg Budget unit shall be exempt from
the initial certification requirements of this section for a monitoring
system under Sec. 60.4170(a)(1) if the following conditions are met:
(1) The monitoring system has been previously certified in
accordance with part 75 of this chapter; and
(2) The applicable quality-assurance and quality-control
requirements of Sec. 75.21 of this chapter and appendix B to part 75
of this chapter are fully met for the certified monitoring system
described in paragraph (a)(1) of this section.
(b) The recertification provisions of this section shall apply to a
monitoring system under Sec. 60.4170(a)(1) exempt from initial
certification requirements under paragraph (a) of this section.
(c) Except as provided in paragraph (a) of this section, the owner
or operator of a Hg Budget unit shall comply with the following initial
certification and recertification procedures for a continuous
monitoring system (e.g., a continuous emission monitoring system and an
excepted monitoring system (sorbent trap monitoring system) under Sec.
75.15) under Sec. 60.4170(a)(1). The owner or operator of a unit that
qualifies to use the Hg low mass emissions excepted monitoring
methodology under Sec. 75.81(b) of this chapter or that qualifies to
use an alternative monitoring system under subpart E of part 75 of this
chapter shall comply with the procedures in paragraph (d) or (e) of
this section respectively.
(1) Requirements for initial certification. The owner or operator
shall ensure that each monitoring system under Sec. 60.4170(a)(1)
(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). In addition, whenever the owner or operator
installs a monitoring system to meet the requirements of this subpart
in a location where no such monitoring system was previously installed,
initial certification in accordance with Sec. 75.20 of this chapter is
required.
(2) Requirements for recertification. Whenever the owner or
operator makes a replacement, modification, or change in any certified
continuous emission monitoring system, or an excepted monitoring system
(sorbent trap monitoring system) under Sec. 75.15, under Sec.
60.4170(a)(1) 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 quality-assurance and quality-control 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 each continuous emission monitoring system, and each excepted
monitoring system (sorbent trap monitoring system) under Sec. 75.15,
whose accuracy is potentially affected by the change, in accordance
with Sec. 75.20(b) of this chapter. Examples of changes to a
continuous emission monitoring system 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.
(3) Approval process for initial certification and recertification.
Paragraphs (c)(3)(i) through (iv) of this section apply to both initial
certification and recertification of a continuous monitoring system
under Sec. 60.4170(a)(1). For recertifications, apply the word
``recertification'' instead of the words ``certification'' and
``initial certification'' and apply the word ``recertified'' instead of
the word ``certified,'' and follow the procedures in Sec. 75.20(b)(5)
of this chapter in lieu of the procedures in paragraph (c)(3)(v) of
this section.
(i) Notification of certification. The Hg designated representative
shall submit to the permitting authority, the appropriate EPA Regional
Office, and the Administrator written notice of the dates of
certification testing, in accordance with Sec. 60.4173.
(ii) Certification application. The Hg designated representative
shall submit to the permitting authority a certification application
for each monitoring system. A complete certification application shall
include the information specified in Sec. 75.63 of this chapter.
[[Page 28672]]
(iii) 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)(3)(ii) 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 the date of receipt of the complete
certification application by the permitting authority.
(iv) Certification application 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)(3)(ii) 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.
(A) 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.
(B) Incomplete application notice. 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
designated representative must submit the additional information
required to complete the certification application. If the Hg
designated 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)(3)(iv)(C) of this
section. The 120-day review period shall not begin before receipt of a
complete certification application.
(C) Disapproval notice. If the certification application shows that
any monitoring system does not meet the performance requirements of
part 75 of this chapter or if the certification application is
incomplete and the requirement for disapproval under paragraph
(c)(3)(iv)(B) of this section is 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)(3)(v) of this
section for each monitoring system that is disapproved for initial
certification.
(D) 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).
(v) Procedures for loss of certification. If the permitting
authority issues a notice of disapproval of a certification application
under paragraph (c)(3)(iv)(C) of this section or a notice of
disapproval of certification status under paragraph (c)(3)(iv)(D) of
this section, then:
(A) The owner or operator shall substitute the following values,
for each disapproved monitoring system, for each hour of unit operation
during the period of invalid data specified under Sec.
75.20(a)(4)(iii), or Sec. 75.21(e) of this chapter and continuing
until the applicable date and hour specified under Sec. 75.20(a)(5)(i)
of this chapter:
(1) For a disapproved Hg pollutant concentration monitors and
disapproved flow monitor, respectively, the maximum potential
concentration of Hg and the maximum potential flow rate, as defined in
sections 2.1.7.1 and 2.1.4.1 of appendix A to part 75 of this chapter;
and
(2) For a disapproved moisture monitoring system and disapproved
diluent gas monitoring system, respectively, the minimum potential
moisture percentage and either the maximum potential CO2
concentration or the minimum potential O2 concentration (as
applicable), as defined in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of
appendix A to part 75 of this chapter.
(3) For a disapproved excepted monitoring system (sorbent trap
monitoring system) under Sec. 75.15 and disapproved flow monitor,
respectively, the maximum potential concentration of Hg and maximum
potential flow rate, as defined in sections 2.1.7.1 and 2.1.4.1 of
appendix A to part 75 of this chapter.
(B) The Hg designated representative shall submit a notification of
certification retest dates and a new certification application in
accordance with paragraphs (c)(3)(i) and (ii) of this section.
(C) 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) Initial certification and recertification procedures for units
using the Hg low mass emission excepted methodology under Sec.
75.81(b) of this chapter. The owner or operator of a unit qualified to
use the Hg low mass emissions (HgLME) excepted methodology under Sec.
75.81(b) of this chapter shall meet the applicable certification and
recertification requirements in Sec. 75.81(c) through (f) of this
chapter.
(e) Certification/recertification procedures for alternative
monitoring systems. The Hg designated 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 notification and application procedures of Sec.
75.20(f) of this chapter.
Sec. 60.4172 Out of control periods.
(a) Whenever any monitoring system fails to meet the quality-
assurance and quality-control requirements or data validation
requirements of part 75 of this chapter, data shall be substituted
using the applicable missing data 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 monitoring 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 monitoring
system. For the purposes of this paragraph, an audit
[[Page 28673]]
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 monitoring system. The data measured and
recorded by the monitoring 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 monitoring system. The owner or operator
shall follow the applicable initial certification or recertification
procedures in Sec. 60.4171 for each disapproved monitoring system.
Sec. 60.4173 Notifications.
The Hg designated 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 designated representative shall
comply with all recordkeeping and reporting requirements in this
section and the requirements of Sec. 60.4110(e)(1).
(2) If a Hg Budget unit is subject to an Acid Rain emission
limitation or the CAIR NOX Annual Trading Program, CAIR
SO2 Trading Program, or CAIR NOX Ozone Season
Trading Program, and the Hg designated 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 section, Sec. Sec. 60.4170 through 60.4173, Sec. 60.4175, Sec.
60.4176, or subpart I of part 75 of this chapter is not the same person
as the designated representative or alternative designated
representative, or the CAIR designated representative or alternate CAIR
designated representative, for the unit under part 72 of this chapter
and the CAIR NOX Annual Trading Program, CAIR SO2
Trading Program, or CAIR NOX Ozone Season Trading Program,
then the submission must also be signed by the designated
representative or alternative designated representative, or the CAIR
designated representative or alternate CAIR designated representative,
as applicable.
(b) Monitoring plans. The owner or operator of a Hg Budget unit
shall comply with requirements of Sec. 75.84(e) of this chapter.
(c) Certification applications. The Hg designated representative
shall 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
Sec. 75.63 of this chapter.
(d) Quarterly reports. The Hg designated representative shall
submit quarterly reports, as follows:
(1) The Hg designated representative shall report the Hg mass
emissions data and heat input data for the Hg Budget unit, in an
electronic quarterly report in a format prescribed by the
Administrator, 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; 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 applicable 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.
(2) The Hg designated 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 Sec. 75.84(f) of this chapter.
(3) For Hg Budget units that are also subject to an Acid Rain
emissions limitation or the CAIR NOX Annual Trading Program,
CAIR SO2 Trading Program, or CAIR NOX Ozone
Season Trading Program, quarterly reports shall include the applicable
data and information required by subparts F through H of part 75 of
this chapter as applicable, in addition to the Hg mass emission data,
heat input data, and other information required by this section,
Sec. Sec. 60.4170 through 60.4173, Sec. 60.4175, and Sec. 60.4176.
(e) Compliance certification. The Hg designated representative
shall submit to the Administrator a compliance certification (in a
format prescribed by the Administrator) 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:
(1) The monitoring data submitted were recorded in accordance with
the applicable requirements of this section, Sec. Sec. 60.4170 through
60.4173, Sec. 60.4175, Sec. 60.4176, and part 75 of this chapter,
including the quality assurance procedures and specifications; and
(2) For a unit with add-on Hg emission controls, a flue gas
desulfurization system, a selective catalytic reduction system, or a
compact hybrid particulate collector system and for all hours where Hg
data are substituted in accordance with Sec. 75.34(a)(1) of this
chapter, the Hg add-on emission controls, flue gas desulfurization
system, selective catalytic reduction system, or compact hybrid
particulate collector system were operating within the range of
parameters listed in the quality assurance/quality control program
under appendix B to part 75 of this chapter, or quality-assured
SO2 emission data recorded in accordance with part 75 of
this chapter document that the flue gas desulfurization system, or
quality-assured NOX emission data recorded in accordance
with part 75 of this chapter document that the selective catalytic
reduction system, was operating properly, as applicable, and the
substitute data values do not systematically underestimate Hg
emissions.
Sec. 60.4175 Petitions.
The Hg designated representative of a Hg unit may submit a petition
under Sec. 75.66 of this chapter to the Administrator requesting
approval to apply an alternative to any requirement of Sec. Sec.
60.4170 through 60.4174 and Sec. 60.4176. Application of an
alternative to any requirement of Sec. Sec. 60.4170 through 60.4174
and Sec. 60.4176 is in accordance with this section and Sec. Sec.
60.4170 through 60.4174 and Sec. 60.4176 only to the extent that the
petition is approved in writing by the Administrator, in consultation
with the permitting authority.
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 monitoring system and a flow
monitoring system shall also monitor and report heat input rate at the
unit level using the procedures set forth in part 75 of this chapter.
0
14. Appendix B to part 60 is amended by adding in numerical order new
Performance Specification 12A to read as follows:
[[Page 28674]]
Appendix B to Part 60--Performance Specifications
* * * * *
PERFORMANCE SPECIFICATION 12A--SPECIFICATIONS AND TEST PROCEDURES
FOR TOTAL VAPOR PHASE MERCURY CONTINUOUS EMISSION MONITORING SYSTEMS
IN STATIONARY SOURCES
1.0 Scope and Application
1.1 Analyte.
------------------------------------------------------------------------
Analyte CAS No.
------------------------------------------------------------------------
Mercury (Hg)................................................ 7439-97-6
------------------------------------------------------------------------
1.2 Applicability.
1.2.1 This specification is for evaluating the acceptability of
total vapor phase Hg continuous emission monitoring systems (CEMS)
installed on the exit gases from fossil fuel fired boilers at the
time of or soon after installation and whenever specified in the
regulations. The Hg CEMS must be capable of measuring the total
concentration in [mu]g/m3 (regardless of speciation) of
vapor phase Hg, and recording that concentration on a wet or dry
basis. Particle bound Hg is not included in the measurements.
This specification is not designed to evaluate an installed
CEMS's performance over an extended period of time nor does it
identify specific calibration techniques and auxiliary procedures to
assess the CEMS's performance. The source owner or operator,
however, is responsible to calibrate, maintain, and operate the CEMS
properly. The Administrator may require, under Clean Air Act (CAA)
section 114, the operator to conduct CEMS performance evaluations at
other times besides the initial test to evaluate the CEMS
performance. See Sec. 60.13(c).
1.2.2 For an affected facility that is also subject to the
requirements of subpart I of part 75 of this chapter, the owner or
operator may conduct the performance evaluation of the Hg CEMS
according to Sec. 75.20(c)(1) of this chapter and section 6 of
appendix A to part 75 of this chapter, in lieu of following the
procedures in this performance specification.
2.0 Summary of Performance Specification.
Procedures for measuring CEMS relative accuracy, measurement
error and drift are outlined. CEMS installation and measurement
location specifications, and data reduction procedures are included.
Conformance of the CEMS with the Performance Specification is
determined.
3.0 Definitions.
3.1 Continuous Emission Monitoring System (CEMS) means the total
equipment required for the determination of a pollutant
concentration. The system consists of the following major
subsystems:
3.2 Sample Interface means that portion of the CEMS used for one
or more of the following: sample acquisition, sample transport,
sample conditioning, and protection of the monitor from the effects
of the stack effluent.
3.3 Hg Analyzer means that portion of the Hg CEMS that measures
the total vapor phase Hg mass concentration and generates a
proportional output.
3.4 Data Recorder means that portion of the CEMS that provides a
permanent electronic record of the analyzer output. The data
recorder may provide automatic data reduction and CEMS control
capabilities.
3.5 Span Value means the upper limit of the intended Hg
concentration measurement range. The span value is a value equal to
two times the emission standard. Alternatively, for an affected
facility that is also subject to the requirements of subpart I of
part 75 of this chapter, the Hg span value(s) may be determined
according to section 2.1.7 of appendix A to part 75 of this chapter.
3.6 Measurement Error (ME) means the absolute value of the
difference between the concentration indicated by the Hg analyzer
and the known concentration generated by a reference gas, expressed
as a percentage of the span value, when the entire CEMS, including
the sampling interface, is challenged. An ME test procedure is
performed to document the accuracy and linearity of the Hg CEMS at
several points over the measurement range.
3.7 Upscale Drift (UD) means the absolute value of the
difference between the CEMS output response and an upscale Hg
reference gas, expressed as a percentage of the span value, when the
entire CEMS, including the sampling interface, is challenged after a
stated period of operation during which no unscheduled maintenance,
repair, or adjustment took place.
3.8 Zero Drift (ZD) means the absolute value of the difference
between the CEMS output response and a zero-level Hg reference gas,
expressed as a percentage of the span value, when the entire CEMS,
including the sampling interface, is challenged after a stated
period of operation during which no unscheduled maintenance, repair,
or adjustment took place.
3.9 Relative Accuracy (RA) means the absolute mean difference
between the pollutant concentration(s) determined by the CEMS and
the value determined by the reference method (RM) plus the 2.5
percent error confidence coefficient of a series of tests divided by
the mean of the RM tests. Alternatively, for low concentration
sources, the RA may be expressed as the absolute value of the
difference between the mean CEMS and RM values.
4.0 Interferences. [Reserved]
5.0 Safety.
The procedures required under this performance specification may
involve hazardous materials, operations, and equipment. This
performance specification may not address all of the safety problems
associated with these procedures. It is the responsibility of the
user to establish appropriate safety and health practices and
determine the applicable regulatory limitations prior to performing
these procedures. The CEMS user's manual and materials recommended
by the RM should be consulted for specific precautions to be taken.
6.0 Equipment and Supplies.
6.1 CEMS Equipment Specifications.
6.1.1 Data Recorder Scale. The Hg CEMS data recorder output
range must include zero and a high level value. The high level value
must be approximately two times the Hg concentration corresponding
to the emission standard level for the stack gas under the
circumstances existing as the stack gas is sampled. A lower high
level value may be used, provided that the measured values do not
exceed 95 percent of the high level value. Alternatively, for an
affected facility that is also subject to the requirements of
subpart I of part 75 of this chapter, the owner or operator may set
the full-scale range(s) of the Hg analyzer according to section
2.1.7 of appendix A to part 75 of this chapter.
6.1.2 The CEMS design should also provide for the determination
of calibration drift at a zero value (zero to 20 percent of the span
value) and at an upscale value (between 50 and 100 percent of the
high-level value).
6.2 Reference Gas Delivery System. The reference gas delivery
system must be designed so that the flowrate of reference gas
introduced to the CEMS is the same at all three challenge levels
specified in Section 7.1 and at all times exceeds the flow
requirements of the CEMS.
6.3 Other equipment and supplies, as needed by the applicable
reference method used. See Section 8.6.2.
7.0 Reagents and Standards.
7.1 Reference Gases. Reference gas standards are required for
both elemental and oxidized Hg (Hg and mercuric chloride,
HgCl2). The use of National Institute of Standards and
Technology (NIST)-certified or NIST-traceable standards and reagents
is required. The following gas concentrations are required.
7.1.1 Zero-level. 0 to 20 percent of the span value.
7.1.2 Mid-level. 50 to 60 percent of the span value.
7.1.3 High-level. 80 to 100 percent of the span value.
7.2 Reference gas standards may also be required for the
reference methods. See Section 8.6.2.
8.0 Performance Specification (PS) Test Procedure.
8.1 Installation and Measurement Location Specifications.
8.1.1 CEMS Installation. Install the CEMS at an accessible
location downstream of all pollution control equipment. Since the Hg
CEMS sample system normally extracts gas from a single point in the
stack, use a location that has been shown to be free of
stratification for SO2 and NOX through
concentration measurement traverses for those gases. If the cause of
failure to meet the RA test requirement is determined to be the
measurement location and a satisfactory correction technique cannot
be established, the Administrator may require the CEMS to be
relocated.
Measurement locations and points or paths that are most likely
to provide data that will meet the RA requirements are listed below.
8.1.2 Measurement Location. The measurement location should be
(1) at least two equivalent diameters downstream of the nearest
control device, point of pollutant
[[Page 28675]]
generation or other point at which a change of pollutant
concentration may occur, and (2) at least half an equivalent
diameter upstream from the effluent exhaust. The equivalent duct
diameter is calculated as per 40 CFR part 60, appendix A, Method 1.
8.1.3 Hg CEMS Sample Extraction Point. Use a sample extraction
point (1) no less than 1.0 meter from the stack or duct wall, or (2)
within the centroidal velocity traverse area of the stack or duct
cross section.
8.2 RM Measurement Location and Traverse Points. Refer to PS 2
of this appendix. The RM and CEMS locations need not be immediately
adjacent.
8.3 ME Test Procedure. The Hg CEMS must be constructed to permit
the introduction of known concentrations of Hg and HgCl2
separately into the sampling system of the CEMS immediately
preceding the sample extraction filtration system such that the
entire CEMS can be challenged. Sequentially inject each of the three
reference gases (zero, mid-level, and high level) for each Hg
species. Record the CEMS response and subtract the reference value
from the CEMS value, and express the absolute value of the
difference as a percentage of the span value (see example data sheet
in Figure 12A-1). For each reference gas, the absolute value of the
difference between the CEMS response and the reference value shall
not exceed 5 percent of the span value. If this specification is not
met, identify and correct the problem before proceeding.
8.4 UD Test Procedure.
8.4.1 UD Test Period. While the affected facility is operating
at more than 50 percent of normal load, or as specified in an
applicable subpart, determine the magnitude of the UD once each day
(at 24-hour intervals, to the extent practicable) for 7 consecutive
unit operating days according to the procedure given in Sections
8.4.2 through 8.4.3. The 7 consecutive unit operating days need not
be 7 consecutive calendar days. Use either Hg[deg] or
HgCl2 standards for this test.
8.4.2 The purpose of the UD measurement is to verify the ability
of the CEMS to conform to the established CEMS response used for
determining emission concentrations or emission rates. Therefore, if
periodic automatic or manual adjustments are made to the CEMS zero
and response settings, conduct the UD test immediately before these
adjustments, or conduct it in such a way that the UD can be
determined.
8.4.3 Conduct the UD test at either the mid-level or high-level
point specified in Section 7.1. Introduce the reference gas to the
CEMS. Record the CEMS response and subtract the reference value from
the CEMS value, and express the absolute value of the difference as
a percentage of the span value (see example data sheet in Figure
12A-1). For the reference gas, the absolute value of the difference
between the CEMS response and the reference value shall not exceed 5
percent of the span value. If this specification is not met,
identify and correct the problem before proceeding.
8.5 ZD Test Procedure.
8.5.1 ZD Test Period. While the affected facility is operating
at more than 50 percent of normal load, or as specified in an
applicable subpart, determine the magnitude of the ZD once each day
(at 24-hour intervals, to the extent practicable) for 7 consecutive
unit operating days according to the procedure given in Sections
8.5.2 through 8.5.3. The 7 consecutive unit operating days need not
be 7 consecutive calendar days. Use either nitrogen, air, Hg[deg] ,
or HgCl2 standards for this test.
8.5.2 The purpose of the ZD measurement is to verify the ability
of the CEMS to conform to the established CEMS response used for
determining emission concentrations or emission rates. Therefore, if
periodic automatic or manual adjustments are made to the CEMS zero
and response settings, conduct the ZD test immediately before these
adjustments, or conduct it in such a way that the ZD can be
determined.
8.5.3 Conduct the ZD test at the zero level specified in Section
7.1. Introduce the zero gas to the CEMS. Record the CEMS response
and subtract the zero value from the CEMS value and express the
absolute value of the difference as a percentage of the span value
(see example data sheet in Figure 12A-1). For the zero gas, the
absolute value of the difference between the CEMS response and the
reference value shall not exceed 5 percent of the span value. If
this specification is not met, identify and correct the problem
before proceeding.
8.6 RA Test Procedure.
8.6.1 RA Test Period. Conduct the RA test according to the
procedure given in Sections 8.6.2 through 8.6.6 while the affected
facility is operating at normal full load, or as specified in an
applicable subpart. The RA test may be conducted during the ZD and
UD test period.
8.6.2 RM. Unless otherwise specified in an applicable subpart of
the regulations, use either Method 29 in appendix A to this part, or
American Society of Testing and Materials (ASTM) Method D 6784-02
(incorporated by reference, see Sec. 60.17) as the RM for Hg
concentration. Alternatively, an instrumental RM may be used,
subject to the approval of the Administrator. Do not include the
filterable portion of the sample when making comparisons to the CEMS
results. When Method 29 or ASTM D6784-02 is used, conduct the RM
test runs with paired or duplicate sampling systems. When an
approved instrumental method is used, paired sampling systems are
not required. If the RM and CEMS measure on a different moisture
basis, data derived with Method 4 in appendix A to this part shall
also be obtained during the RA test.
8.6.3 Sampling Strategy for RM Tests. Conduct the RM tests in
such a way that they will yield results representative of the
emissions from the source and can be compared to the CEMS data. It
is preferable to conduct moisture measurements (if needed) and Hg
measurements simultaneously, although moisture measurements that are
taken within an hour of the Hg measurements may be used to adjust
the Hg concentrations to a consistent moisture basis. In order to
correlate the CEMS and RM data properly, note the beginning and end
of each RM test period for each paired RM run (including the exact
time of day) on the CEMS chart recordings or other permanent record
of output.
8.6.4 Number and length of RM Tests. Conduct a minimum of nine
RM test runs. When Method 29 or ASTM D6784-02 is used, only test
runs for which the data from the paired RM trains meet the relative
deviation (RD) criteria of this PS shall be used in the RA
calculations. In addition, for Method 29 and ASTM D 6784-02, use a
minimum sample run time of 2 hours.
Note: More than nine sets of RM tests may be performed. If this
option is chosen, paired RM test results may be excluded so long as
the total number of paired RM test results used to determine the
CEMS RA is greater than or equal to nine. However, all data must be
reported, including the excluded data.
8.6.5 Correlation of RM and CEMS Data. Correlate the CEMS and
the RM test data as to the time and duration by first determining
from the CEMS final output (the one used for reporting) the
integrated average pollutant concentration for each RM test period.
Consider system response time, if important, and confirm that the
results are on a consistent moisture basis with the RM test. Then,
compare each integrated CEMS value against the corresponding RM
value. When Method 29 or ASTM D6784-02 is used, compare each CEMS
value against the corresponding average of the paired RM values.
8.6.6 Paired RM Outliers.
8.6.6.1 When Method 29 or ASTM D6784-02 is used, outliers are
identified through the determination of relative deviation (RD) of
the paired RM tests. Data that do not meet this criteria should be
flagged as a data quality problem. The primary reason for performing
paired RM sampling is to ensure the quality of the RM data. The
percent RD of paired data is the parameter used to quantify data
quality. Determine RD for two paired data points as follows:
[GRAPHIC] [TIFF OMITTED] TR18MY05.021
where Ca and Cb are concentration values
determined from each of the two samples respectively.
8.6.6.2 A minimum performance criteria for RM Hg data is that RD
for any data pair must be <=10 percent as long as the mean Hg
concentration is greater than 1.0 [mu]g/m3. If the mean
Hg concentration is less than or equal to 1.0 [mu]g/m3,
the RD must be <=20 percent. Pairs of RM data exceeding these RD
criteria should be eliminated from the data set used
[[Page 28676]]
to develop a Hg CEMS correlation or to assess CEMS RA.
8.6.7 Calculate the mean difference between the RM and CEMS
values in the units of micrograms per cubic meter ([mu]g/
m3), the standard deviation, the confidence coefficient,
and the RA according to the procedures in Section 12.0.
8.7 Reporting. At a minimum (check with the appropriate EPA
Regional Office, State or local Agency for additional requirements,
if any), summarize in tabular form the results of the RD tests and
the RA tests or alternative RA procedure, as appropriate. Include
all data sheets, calculations, charts (records of CEMS responses),
reference gas concentration certifications, and any other
information necessary to confirm that the performance of the CEMS
meets the performance criteria.
9.0 Quality Control. [Reserved]
10.0 Calibration and Standardization. [Reserved]
11.0 Analytical Procedure.
Sample collection and analysis are concurrent for this PS (see
Section 8.0). Refer to the RM employed for specific analytical
procedures.
12.0 Calculations and Data Analysis.
Summarize the results on a data sheet similar to that shown in
Figure 2-2 for PS 2.
12.1 Consistent Basis. All data from the RM and CEMS must be
compared in units of [mu]g/m3, on a consistent and
identified moisture and volumetric basis (STP = 20[deg]C, 760
millimeters (mm) Hg).
12.1.1 Moisture Correction (as applicable). If the RM and CEMS
measure Hg on a different moisture basis, use Equation 12A-2 to make
the appropriate corrections to the Hg concentrations.
[GRAPHIC] [TIFF OMITTED] TR18MY05.006
In Equation 12-A-2, Bws is the moisture content of
the flue gas from Method 4, expressed as a decimal fraction (e.g.,
for 8.0 percent H2O, Bws = 0.08).
12.2 Arithmetic Mean. Calculate the arithmetic mean of the
difference, d, of a data set as follows:
[GRAPHIC] [TIFF OMITTED] TR18MY05.007
Where:
n = Number of data points.
12.3 Standard Deviation. Calculate the standard deviation,
Sd, as follows:
[GRAPHIC] [TIFF OMITTED] TR18MY05.008
Where:
[GRAPHIC] [TIFF OMITTED] TR18MY05.009
12.4 Confidence Coefficient (CC). Calculate the 2.5 percent
error confidence coefficient (one-tailed), CC, as follows:
[GRAPHIC] [TIFF OMITTED] TR18MY05.010
12.5 RA. Calculate the RA of a set of data as follows:
[GRAPHIC] [TIFF OMITTED] TR18MY05.011
Where:
[GRAPHIC] [TIFF OMITTED] TR18MY05.032
13.0 Method Performance.
13.1 ME. ME is assessed at zero-level, mid-level and high-level
values as given below using standards for both Hg0 and
HgCl2. The mean difference between the indicated CEMS
concentration and the reference concentration value for each
standard shall be no greater than 5 percent of the span value.
13.2 UD. The UD shall not exceed 5 percent of the span value on
any of the 7 days of the UD test.
13.3 ZD. The ZD shall not exceed 5 percent of the span value on
any of the 7 days of the ZD test.
13.4 RA. The RA of the CEMS must be no greater than 20 percent
of the mean value of the RM test data in terms of units of [mu]g/
m3. Alternatively, if the mean RM is less than 5.0 [mu]g/
m3, the results are acceptable if the absolute value of
the difference between the mean RM and CEMS values does not exceed
1.0 [mu]g/m3.
14.0 Pollution Prevention. [Reserved]
15.0 Waste Management. [Reserved]
16.0 Alternative Procedures. [Reserved]
17.0 Bibliography.
17.1 40 CFR part 60, appendix B, ``Performance Specification 2--
Specifications and Test Procedures for SO2 and
NOX Continuous Emission Monitoring Systems in Stationary
Sources.''
[[Page 28677]]
17.2 40 CFR part 60, appendix A, ``Method 29--Determination of
Metals Emissions from Stationary Sources.''
17.3 ASTM Method D6784-02, ``Standard Test Method for Elemental,
Oxidized, Particle-Bound and Total Mercury in Flue Gas Generated
from Coal-Fired Stationary Sources (Ontario Hydro Method).''
18.0 Tables and Figures.
Table 12A-1.--T-Values
----------------------------------------------------------------------------------------------------------------
na t0.975 na t0.975 na t0.975
----------------------------------------------------------------------------------------------------------------
2........................................................ 12.706 7 2.447 12 2.201
3........................................................ 4.303 8 2.365 13 2.179
4........................................................ 3.182 9 2.306 14 2.160
5........................................................ 2.776 10 2.262 15 2.145
6........................................................ 2.571 11 2.228 16 2.131
----------------------------------------------------------------------------------------------------------------
\a\ The values in this table are already corrected for n-1 degrees of freedom. Use n equal to the number of
individual values.
Figure 12A-1.--ME, ZD and UD Determination
--------------------------------------------------------------------------------------------------------------------------------------------------------
Drift or
Date Time Reference Gas value CEMS measured value Absolute difference measurement error
[mu]g/m\3\ [mu]g/m\3\ (% of span value)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Zero level..........
-----------------------
-----------------------
-----------------------
=======================
Mid level...........
-----------------------
-----------------------
-----------------------
=======================
High level..........
-----------------------
-----------------------
-----------------------
--------------------------------------------------------------------------------------------------------------------------------------------------------
* * * * *
PART 72--PERMITS REGULATION
0
15. The authority citation for part 72 continues to read as follows:
Authority: 42 U.S.C. 7601 and 7651, et seq.
0
16. Section 72.2 is amended in the definition of ``Continuous emission
monitoring system or CEMS'' by revising the introductory text and
adding paragraph (7); 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, Hg, 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 75.81 of this chapter indicate which type(s)
of CEMS is required for specific applications:
* * * * *
(7) 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 standard cubic meter ([mu]g/
scm).
* * * * *
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). This excepted 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. Using the sample
volume measured by the dry gas meter and the results of the analyses of
the sorbent traps, the average Hg concentration in the stack gas for
the sampling period 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 average Hg
concentration for that period, in conjunction with contemporaneous
hourly measurements
[[Page 28678]]
of the stack gas flow rate, corrected for the stack gas moisture
content.
* * * * *
PART 75--CONTINUOUS EMISSION MONITORING
0
17. The authority citation for Part 75 continues to read as follows:
Authority: 42 U.S.C. 7601, 7651k, and 7651k note.
0
18. 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.
* * * * *
0
19. Section 75.6 is amended as follows:
0
a. In the introductory text, by removing ``1916 Race Street,
Philadelphia, Pennsylvania 19103;'' and adding ``100 Barr harbor Drive,
P.O. Box C-700, West Conshohocken, Pennsylvania 19428-2959;'' in its
place;
0
b. Redesignate paragraphs (a)(38) through (a)(41) as (a)(39) through
(a)(42);
0
c. Add new paragraphs (a)(38), (a)(43), and (a)(44); and
0
d. Revise paragraphs (b), (c), (d), and (e) to read as follows:
Sec. 75.6 Incorporation by Reference.
* * * * *
(a) * * *
(38) ASTM D4840-99 (reapproved 2004), ``Standard Guide for Sample
Chain-of-Custody Procedures,'' for appendix K of this part, section
7.2.9.
* * * * *
(43) ASTM D6784-02, ``Standard Test Method for Elemental, Oxidized,
Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired
Stationary Sources (Ontario Hydro Method),'' for Sec. 75.22(a)(7) and
(b)(5).
(44) ASTM D6911-03, ``Guide for Packaging and Shipping
Environmental Samples for Laboratory Analysis,'' for appendix K of this
part, section 7.2.8.
* * * * *
(b) The following materials are available for purchase from the
American Society of Mechanical Engineers (ASME), 22 Law Drive, P.O. Box
2900, Fairfield, New Jersey 07007-2900:
* * * * *
(c) The following materials are available for purchase from the
American National Standards Institute (ANSI), 25 West 43rd Street,
Fourth Floor, New York, New York 10036:
(1) ISO 8316: 1987(E) Measurement of Liquid Flow in closed
Conduits-Method by Collection of the Liquid in a Volumetric Tank, for
appendices D and E of this part.
(2) [Reserved]
* * * * *
(d) The following materials are available for purchase from the
following address: Gas Processors Association (GPA), 6526 East 60th
Street, Tulsa, Oklahoma 74143:
* * * * *
(e) The following American Gas Association materials are available
for purchase from the following address: ILI Infodisk, 610 Winters
Avenue, Paramus, New Jersey 07652:
* * * * *
0
20. Section 75.10 is amended by revising the second sentence of
paragraph (d)(1) and revising the first sentence 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, and Hg concentration data
collected by the monitors to hourly averages. * * *
* * * * *
(3) Failure of an SO2, CO2, or O2
emissions concentration monitor, NOX concentration monitor,
Hg concentration monitor, flow monitor, moisture monitor, or
NOX-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. * * *
* * * * *
0
21. Section 75.15 is added to read as follows:
Sec. 75.15 Special provisions for measuring Hg mass emissions using
the excepted sorbent trap monitoring methodology.
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, the guidelines in paragraphs (a) through
(j) of this section shall be followed for this excepted monitoring
methodology:
(a) For each sorbent trap monitoring system (whether primary or
redundant backup), the use of paired sorbent traps, as described in
appendix K to this part, is required;
(b) Each sorbent trap shall have both a main section, a backup
section, and a third section to allow spiking with a calibration gas of
known Hg concentration, as described in appendix K to this part;
(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(a)(4));
(e) Each sorbent trap monitoring system shall be installed and
operated in accordance with appendix K to this part. The automated data
acquisition and handling system shall ensure that the sampling rate is
proportional to the stack gas volumetric flow rate.
(f) At the beginning and end of each sample collection period, and
at least once in each unit operating hour during the collection period,
the dry gas meter reading shall be recorded.
(g) After each sample collection period, the mass of Hg adsorbed in
each sorbent trap (in all three sections) shall be determined according
to the applicable procedures in appendix K to this part.
(h) The hourly Hg mass emissions for each collection period are
determined using the results of the analyses in conjunction with
contemporaneous hourly data recorded by a certified stack flow monitor,
corrected for the stack gas moisture content. For each pair of sorbent
traps analyzed, the average of the two Hg concentrations shall be used
for reporting purposes under Sec. 75.84(f). Notwithstanding this
requirement, if, due to circumstances beyond the control of the owner
or operator, one of the paired traps is accidentally lost, damaged, or
broken and cannot be analyzed, the results of the analysis of the other
trap, if valid, may be used for reporting purposes.
(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 appendix K to this
part) 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 CEMS or sorbent trap monitoring
system or from an applicable reference method under Sec. 75.22. If no
quality-assured Hg concentration are
[[Page 28679]]
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, in sections 1.5 and 2.3 of appendix B to this part, and in
appendix K to this part.
0
22. Section 75.20 is amended by:
0
a. Revising paragraph (a)(5)(i);
0
b. Revising the first sentence of paragraph (b) introductory text;
0
c. Revising paragraph (c)(1);
0
d. Redesignating existing paragraphs (c)(9) and (c)(10) as paragraphs
(c)(10) and (c)(11), respectively;
0
e. Adding a new paragraph (c)(9); and
0
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 concentration of Hg, as defined in
section 2.1.7 of appendix A to this part, to report Hg emissions in
[mu]g/scm (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, 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, and each NOX-diluent
continuous emission monitoring system:
(i) A 7-day calibration error test, where, for the NOX -
diluent continuous emission monitoring system, the test is performed
separately on the NOX pollutant concentration monitor and
the diluent gas monitor;
(ii) A linearity check, where, for the NOX-diluent
continuous emission monitoring system, the test is performed separately
on the NOX pollutant concentration monitor and the diluent
gas monitor. For Hg monitors, perform this check with elemental Hg
standards;
(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/scm basis;
(iv) A bias test;
(v) A cycle time test; and
(vi) For Hg monitors only, a 3-level system integrity check, using
a NIST-traceable source of oxidized Hg, as described in section 6.2 of
appendix A to this part. This test is not required for an Hg monitor
that does not have a converter.
* * * * *
(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.
* * * * *
0
23. 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
one of the Hg reference methods in Sec. 75.22, as applicable, instead
of the procedures specified in appendix B of this part.
* * * * *
0
24. Section 75.22 is amended by adding new paragraphs (a)(7) and
(b)(5), to read as follows:
Sec. 75.22 Reference test 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
[[Page 28680]]
Ontario Hydro Method) (incorporated by reference, see Sec. 75.6) is
the reference method for determining Hg concentration. When this method
is used, paired sampling trains are required, and to validate a RATA
run, the relative deviation (RD), calculated according to section 11.7
of appendix K to this part, must not exceed 10 percent. If the RD
criterion is met, use the average Hg concentration measured by the two
trains (vapor phase Hg, only) in the relative accuracy calculations.
Alternatively, an instrumental reference method capable of measuring
total vapor phase Hg may be used, subject to the approval of the
Administrator.
(b) * * *
(5) 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 and
incorporated by reference, see Sec. 75.6) for determining Hg
concentration. Alternatively, an instrumental reference method capable
of measuring total vapor phase Hg may be used, subject to the approval
of the Administrator.
* * * * *
0
25. 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 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.
* * * * *
0
26. Section 75.31 is amended by:
0
a. Revising the first sentence of paragraph (a);
0
b. Revising paragraph (b) introductory text; and
0
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, or moisture monitoring
system(s) at a particular unit or stack location (i.e., the date and
time at which quality-assured data begins to be recorded by CEMS(s)
installed at that location), and during the first 2,160 quality-assured
monitor operating hours following initial certification of the required
NOX-diluent, NOX concentration, or flow
monitoring system(s) at the unit or stack location, the owner or
operator shall provide substitute data required under this subpart
according to the procedures in paragraphs (b) and (c) of this section.
* * *
* * * * *
(b) SO2, CO2, or O2 concentration
data, Hg concentration data, and moisture data. For each hour of
missing SO2, Hg, or CO2 emissions concentration
data (including CO2 data converted from O2 data
using the procedures in appendix F of this part), 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, 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,
CO2, Hg, or O2 concentration data, or moisture
data exist, the owner or operator shall substitute, as applicable, for
each hour of missing data, the maximum potential SO2
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, 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.
* * * * *
0
27. 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, or Hg concentration, or moisture
monitoring system(s) at a particular unit or stack location (i.e., the
date and time at which quality-assured data begins to be recorded by
CEMS(s) at that location), the owner or operator shall begin
calculating the percent monitor data availability as described in
paragraph (a)(1) of this section, and shall, upon completion of the
first 720 quality-assured monitor operating hours, record, by means of
the automated data acquisition and handling system, the percent monitor
data availability for each monitored parameter. * * *
* * * * *
0
28. Table 1 in Sec. 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 (90 or more for Hg).. N <= 24.................. Average................. HB/HA.
N > 24................... For SO2, CO2, Hg, and
H2O **,the greater of:
Average................. HB/HA.
[[Page 28681]]
90th percentile......... 720 hours \*\.
For O2 and H2O \x\, the
lesser of:
Average................. HB/HA.
10th percentile......... 720 hours \*\.
90 or more, but below 95 (>= 80 N <= 8................... Average................. HB/HA.
but < 90 for Hg).
N > 8.................... For SO2, CO2, Hg, and
H2O \**\, the greater
of:
Average................. HB/HA.
95th percentile......... 720 hours \*\.
For O2 and H2O \x\, the
lesser of:
Average................. HB/HA.
5th percentile.......... 720 hours \*\.
80 or more, but below 90 (>=70 N > 0.................... For SO2, CO2, Hg, and
but < 80 for Hg). H2O \**\,
Maximum value \1\....... 720 hours \*\.
For O2 and H2O \x\:
Minimum value \1\....... 720 hours*.
Below 80 (Below 70 for Hg)...... N > 0.................... Maximum potential None
concentration or % (for
SO2, CO2, Hg, and H2O
\**\) or Minimum
potential concentration
or % (for O2 and H2O
\x\).
----------------------------------------------------------------------------------------------------------------
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 or Hg 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.
* * * * *
0
29. 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) Once 720 quality assured monitor operating hours of Hg
concentration data have been obtained following initial certification,
the owner or operator shall provide substitute data for Hg
concentration in accordance with the procedures in Sec. Sec.
75.33(b)(1) through (b)(4), except that the term ``Hg concentration''
shall apply rather than ``SO2 concentration,'' the term ``Hg
concentration 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'' 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. 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 80.0 percent, and a
missing data period occurs, the owner or operator may petition to
report the maximum controlled Hg concentration 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 the paired sorbent traps are
missing or invalid (as determined using the quality assurance
procedures in appendix K to this part). 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 (i.e., the hour at which
this pair of traps was placed in service).
[[Page 28682]]
(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) is >= 90.0
percent, report the average Hg concentration for all valid sorbent trap
analyses in the previous 12 months.
(2) If the PMA is >= 80.0 percent, but < 90.0 percent, report the
95th percentile Hg concentration obtained from all of the valid sorbent
trap analyses in the previous 12 months.
(3) If the PMA is >= 70.0 percent, but < 80.0 percent, report the
maximum Hg concentration obtained from all of the valid sorbent trap
analyses in the previous 12 months.
(4) If the PMA is < 70.0 percent, 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).
0
30. Section 75.53 is amended by:
0
a. Revising paragraph (e)(1)(i)(E);
0
b. Revising paragraph (e)(1)(iv) introductory text; and
0
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 sorbent trap monitoring system, 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, 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.
* * * * *
0
31. 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, and
(in certain cases) moisture, and diluent gas monitors, to determine Hg
mass emissions and (if applicable) unit heat input 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 Hg concentration ([mu]g/scm, rounded to the nearest
tenth). For a particular pair of sorbent traps, this will be the flow-
proportional average concentration for the data collection period;
(iv) The bias-adjusted hourly average Hg concentration ([mu]g/scm,
rounded to the nearest hundredth) if a bias adjustment factor is
required, as provided in Sec. 75.24(d);
(v) Method of determination for hourly Hg concentration using Codes
1-55 in Table 4a of this section; and
(vi) 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 (if
required), 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), 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);
[[Page 28683]]
(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) The percent monitor data availability (to the nearest tenth of
a percent) for the O2 or CO2 monitoring system
(if a separate O2 or CO2 monitoring system is
used for heat input determination), 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 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 three decimal
places);
(iii) Hourly Hg mass emissions (ounces, rounded to three decimal
places), 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 and (if required) unit
heat input 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 Hg concentration ([mu]g/dscm, rounded to the nearest
tenth). For a particular pair of sorbent traps, this will be the flow-
proportional average concentration for the data collection period;
(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), record the
information required under paragraphs (i)(2)(i) through (i)(2)(v) 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 paragraphs (i)(3)(i) through
(i)(3)(v) 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)(5) of this section.
(6) Record the average flow rate of stack gas through each sorbent
trap (in appropriate units, e.g., liters/min, cc/min, dscm/min).
(7) Record the dry gas meter reading (in dscm, rounded to the
nearest hundredth), at the beginning and end of the collection period
and at least once in each unit operating hour during the collection
period.
(8) Calculate and record the ratio of the bias-adjusted stack gas
flow rate to the sample flow rate, as described in section 11.2 of
appendix K to this part.
0
32. 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.
Alternatively, for units equipped with flue gas desulfurization (FGD)
systems, the owner or operator may use quality-assured data from a
certified SO2 monitor to demonstrate proper operation of the
emission controls during periods of missing Hg data;
(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;
* * * * *
0
33. Section 75.59 is amended by:
0
a. Revising the introductory text of paragraphs (a)(1), (a)(3), (a)(5),
(a)(5)(ii), (a)(6), and (a)(9);
0
b. Adding paragraphs (a)(7)(vii), (a)(7)(viii), and (a)(14);
0
c. Revising paragraph (a)(9)(vi); and
0
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 emissions
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, all daily system integrity
checks (Hg monitors, only), and all off-line calibration
demonstrations, including any follow-up tests after corrective action:
* * * * *
(3) For each SO2 or NOX pollutant
concentration monitor, CO2 emissions
[[Page 28684]]
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 or operator
shall record the following for the initial and all subsequent linearity
check(s) and 3-level system integrity checks (Hg monitors with
converters, only), including any follow-up tests after corrective
action:
* * * * *
(5) For each SO2 pollutant concentration monitor, flow
monitor, each CO2 emissions 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
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:
* * * * *
(ii) Individual test run data from the relative accuracy test audit
for the SO2 concentration monitor, flow monitor,
CO2 emissions 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, sorbent trap monitoring system, or
approved alternative monitoring system, including:
* * * * *
(6) For each SO2, NOX, Hg, or CO2
emissions concentration monitor, NOX-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)
(viii) Data elements for instrumental Hg reference method.
[Reserved]
* * * * *
(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 leak checks and
other applicable 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 leak
checks;
(vi) The analysis of the Hg collected by each sorbent trap; and
(vii) Information documenting the results of the other applicable
quality control procedures in Sec. 75.15 and in appendices B and K to
this part.
* * * * *
(c) Except as otherwise provided in Sec. 75.58(b)(3)(i), 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: * * *
* * * * *
0
34. 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.
Subpart I--Hg Mass Emission Provisions
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.
(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, moisture, diluent gas concentration, 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
[[Page 28685]]
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 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 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 in Sec.
75.15, appendix K to this part, and sections 1.5 and 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 an Hg concentration monitoring
system, substitute for missing data in accordance with the applicable
missing data procedures in Sec. Sec. 75.31 through 75.38 whenever the
unit combusts fuel and:
(i) A valid, quality-assured hour of Hg concentration data (in
[mu]g/scm) 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; 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 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 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, or when correction of the Hg concentration
for moisture is not necessary; or
(iv) 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 for allocating allowances under the
applicable State or Federal Hg mass emission reduction program that
adopts the requirements of this subpart.
(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) For Hg concentration and flow monitoring systems, 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; or
(2) For any unit, report data from the reference methods under
Sec. 75.22; or
[[Page 28686]]
(3) For any unit that is required to report heat input for purposes
of allocating allowances, report (as applicable) 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 in writing 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 in writing by the Administrator, in
consultation with 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 concentration monitoring system (as defined in Sec. 72.2
of this chapter) or a sorbent trap monitoring system (as defined in
Sec. 72.2 of this chapter) to measure Hg concentration; and
(2) A flow monitoring system; and
(3) A continuous moisture monitoring system (if correction of Hg
concentration for moisture is required), 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 monitor to measure heat input rate; or
(b) For an affected unit that emits 464 ounces (29 lb) of Hg per
year or less, use the following excepted monitoring methodology. To
implement this methodology for a qualifying unit, the owner or operator
shall meet the general operating requirements in Sec. 75.10 for the
continuous emission monitors described in paragraphs (a)(2) and (a)(4)
of this section, and perform Hg emission testing for initial
certification and on-going quality-assurance, as described in
paragraphs (c) through (e) of this section.
(c) To determine whether an affected unit is eligible to use the
monitoring provisions in paragraph (b) of this section:
(1) The owner or operator must perform Hg emission testing prior to
the compliance date in Sec. 75.80(b), to determine the Hg
concentration (i.e., total vapor phase Hg) in the effluent. The testing
shall be performed using one of the Hg reference methods listed in
Sec. 75.22, and shall consist of a minimum of 3 runs at the normal
unit operating load. The minimum time per run shall be 1 hour if an
instrumental reference method is used. If the Ontario Hydro Method is
used, the test runs must be long enough to ensure that sufficient Hg is
collected to analyze. If the unit is equipped with flue gas
desulfurization or add-on Hg emission controls, the controls must be
operating normally during the testing, and, for the purpose of
establishing proper operation of the controls, the owner or operator
shall record parametric data or SO2 concentration data in
accordance with Sec. 75.58(b)(3)(i).
(2) Based on the results of the emission testing, Equation 1 of
this section shall be used to provide a conservative estimate of the
annual Hg mass emissions from the unit:
Where:
E = Estimated annual Hg mass emissions from the affected unit, (ounces/
year)
K = Units conversion constant, 9.978 x 10-10 oz-scm/[mu]g-
scf
8760 = Number of hours in a year
CHg = The highest Hg concentration ([mu]g/scm) from any of
the test runs or 0.50 [mu]g/scm, whichever is greater
Qmax = Maximum potential flow rate, determined according to
section 2.1.4.1 of appendix A to this part, (scfh)
Equation 1 of this section assumes that the unit operates year-round at
its maximum potential flow rate. Also, note that if the highest Hg
concentration measured in any test run is less than 0.50 [mu]g/scm, a
default value of 0.50 [mu]g/scm must be used in the calculations.
(3) If the estimated annual Hg mass emissions from paragraph (c)(2)
of this section are 464 ounces per year or less, then the unit is
eligible to use the monitoring provisions in paragraph (b) of this
section, and continuous monitoring of the Hg concentration is not
required (except as otherwise provided in paragraphs (e) and (f) of
this section).
(d) If the owner or operator of an eligible unit under paragraph
(c)(3) of this section elects not to continuously monitor Hg
concentration, then the following requirements must be met:
(1) The results of the Hg emission testing performed under
paragraph (c) of this section shall be submitted as a certification
application to the Administrator and to the permitting authority, no
later than 45 days after the testing is completed. The calculations
demonstrating that the unit emits 464 ounces (or less) per year of Hg
shall also be provided, and the default Hg concentration that will be
used for reporting under Sec. 75.84 shall be specified in both the
electronic and hard copy portions of the monitoring plan for the unit.
The methodology is considered to be provisionally certified as of the
date and hour of completion of the Hg emission testing.
[[Page 28687]]
[GRAPHIC] [TIFF OMITTED] TR18MY05.022
(2) Following initial certification, the same default Hg
concentration value that was used to estimate the unit's annual Hg mass
emissions under paragraph (c) of this section shall be reported for
each unit operating hour, except as otherwise provided in paragraph
(d)(6) of this section. The default Hg concentration value shall be
updated as appropriate, according to paragraph (d)(5) of this section.
(3) The hourly Hg mass emissions shall be calculated according to
section 9.1.3 in appendix F to this part.
(4) The Hg emission testing described in paragraph (c) of this
section shall be repeated periodically, for the purposes of quality-
assurance, as follows:
(i) If the results of the certification testing under paragraph (c)
of this section show that the unit emits 144 ounces (9 lb) of Hg per
year or less, the first retest is required by the end of the fourth QA
operating quarter (as defined in Sec. 72.2 of this chapter) following
the calendar quarter of the certification testing; or
(ii) If the results of the certification testing under paragraph
(c) of this section show that the unit emits more than 144 ounces of Hg
per year, but less than or equal to 464 ounces per year, the first
retest is required by the end of the second QA operating quarter (as
defined in Sec. 72.2 of this chapter) following the calendar quarter
of the certification testing; and
(iii) Thereafter, retesting shall be required either semiannually
or annually (i.e., by the end of the second or fourth QA operating
quarter following the quarter of the previous test), depending on the
results of the previous test. To determine whether the next retest is
due within two or four QA operating quarters, substitute the highest Hg
concentration from the current test or 0.50 [mu]g/scm (whichever is
greater) into the equation in paragraph (c)(2) of this section. If the
estimated annual Hg mass emissions exceeds 144 ounces, the next test is
due within two QA operating quarters. If the estimated annual Hg mass
emissions is 144 ounces or less, the next test is due within four QA
operating quarters.
(5) The default Hg concentration used for reporting under Sec.
75.84 shall be updated after each required retest. The updated value
shall either be the highest Hg concentration measured in any of the
test runs or 0.50 [mu]g/scm, whichever is greater. The updated default
value shall be applied beginning with the first unit operating hour
after completion of the retest.
(6) If the unit is equipped with a flue gas desulfurization system
or add-on Hg controls, the owner or operator shall record the
information required under Sec. 75.58(b)(3) for each unit operating
hour, to document proper operation of the emission controls. For any
operating hour in which this documentation is unavailable, the maximum
potential Hg concentration, as defined in section 2.1.7 of appendix A
to this part, shall be reported.
(e) For units with common stack and multiple stack exhaust
configurations, the use of the monitoring methodology described in
paragraphs (b) through (d) of this section is restricted as follows:
(1) The methodology may not be used for reporting Hg mass emissions
at a common stack unless all of the units using the common stack are
affected units and each individual unit is demonstrated to emit 464
ounces of Hg per year, or less, in accordance with paragraphs (c) and
(d) of this section. If these conditions are met, the default Hg
concentration used for reporting at the common stack shall either be
the highest value obtained in any test run for any of the units serving
the common stack or 0.50 [mu]g/scm, whichever is greater.
(2) For units with multiple stack or duct configurations, Hg
emission testing must be performed separately on each stack or duct,
and the sum of the estimated annual Hg mass emissions from the stacks
or ducts must not exceed 464 ounces of Hg per year. For reporting
purposes, the default Hg concentration used for each stack or duct
shall either be the highest value obtained in any test run for that
stack or 0.50 [mu]g/scm, whichever is greater.
(3) For units with a main stack and bypass stack configuration, Hg
emission testing shall be performed only on the main stack. For
reporting purposes, the default Hg concentration used for the main
stack shall either be the highest value obtained in any test run for
that stack or 0.50 [mu]g/scm, whichever is greater. Whenever the main
stack is bypassed, the maximum potential Hg concentration, as defined
in section 2.1.7 of appendix A to this part, shall be reported.
(f) At the end of each calendar year, if the cumulative annual Hg
mass emissions from an affected unit have exceeded 464 ounces, then the
owner shall install, certify, operate, and maintain a Hg concentration
monitoring system or a sorbent trap monitoring system no later than 180
days after the end of the calendar year in which the annual Hg mass
emissions exceeded 464 ounces. For common stack and multiple stack
configurations, installation and certification of a Hg concentration or
sorbent trap monitoring system on each stack (except for bypass stacks)
is likewise required within 180 days after the end of the calendar
year, if:
(1) The annual Hg mass emissions at the common stack have exceeded
464 ounces times the number of affected units using the common stack;
or
(2) The sum of the annual Hg mass emissions from all of the
multiple stacks or ducts has exceeded 464 ounces; or
(3) The sum of the annual Hg mass emissions from the main and
bypass stacks has exceeded 464 ounces.
(g) For an affected unit that is using a Hg concentration CEMS or a
sorbent trap system under Sec. 75.81(a) to continuously monitor the Hg
mass emissions, the owner or operator may switch to the methodology in
Sec. 75.81(b), provided that the applicable conditions in paragraphs
(c) through (f) of this section are met.
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) at the common stack, record the combined Hg
mass emissions for the units exhausting to the common stack.
Alternatively, if, in accordance with Sec. 75.81(e), each of the units
using the common stack is demonstrated to emit less than 464 ounces of
Hg per year, the owner or operator may install, certify, operate and
maintain the monitoring systems and perform the Hg emission testing
described under Sec. 75.81(b). If reporting of the unit heat input
rate is required, determine the hourly unit heat input rates either by:
(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
and (if applicable) perform the Hg emission testing 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
[[Page 28688]]
with one or more nonaffected units, the owner or operator shall either:
(1) Install, certify, operate, and maintain the monitoring systems
and (if applicable) perform the Hg emission testing 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) in the common stack; and
(i) Install, certify, operate, and maintain the monitoring systems
and (if applicable) perform the Hg emission testing described in Sec.
75.81(a) or Sec. 75.81(b) 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) 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) 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
and (if applicable) perform the Hg emission testing 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 concentration (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. Sec. 75.31 through
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
and (if applicable) perform the Hg emission testing 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
and (if applicable) perform the Hg emission testing 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 3 years from the
date of each record. Except for the certification data required in
Sec. 75.57(a)(4) and the initial submission 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
[[Page 28689]]
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).
(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.
(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 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 parametric 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);
(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;
(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
[[Page 28690]]
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;
(J) For units using sorbent trap monitoring systems, the hourly dry
gas meter readings taken between the initial and final meter readings
for the data collection period; and
(iii) Ounces of Hg emitted during quarter and cumulative ounces of
Hg emitted in the year-to-date (rounded to the nearest thousandth); and
(iv) Unit or stack operating hours for quarter, cumulative unit or
stack operating hours for year-to-date; and
(v) 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:
(A) The monitoring data submitted were recorded in accordance with
the applicable requirements of this part, including the quality
assurance procedures and specifications; and
(B) 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 (or that quality-assured SO2
CEMS data were available to document proper operation of the emission
controls), 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).
0
35. Appendix A to 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, and NOX concentration monitoring system or
NOX-diluent CEMS (NOX pollutant concentration
monitor and diluent gas monitor), Hg concentration monitoring
system, or sorbent trap monitoring system will pass the relative
accuracy test (see section 6 of this appendix).
* * * * *
0
36. 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:
Appendix A to Part 75--Specification and Test Procedures
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/scm for
bituminous coal; 10 [mu]g/scm for sub-bituminous coal; 16 [mu]g/scm
for lignite, and 1 [mu]g/scm 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 one of the Hg reference methods in Sec.
75.22, 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 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 or data from a sorbent trap monitoring system, if the unit does
not have add-on Hg emission controls or a flue gas desulfurization
system (or if the CEMS or sorbent trap system is located upstream of
these control devices) and if the Hg CEMS or sorbent trap system has
been tested for relative accuracy against one of the Hg reference
methods in Sec. 75.22 and has met a relative accuracy specification
of 20.0% or less.
(b) 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/scm.
(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/scm or greater, define a second, low span value of 10
[mu]g/scm.
(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 gas concentrations currently being
used for calibration error tests, system integrity checks, and
linearity checks are unsuitable for use with the new span value and
new calibration materials must be ordered.
[[Page 28691]]
(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 gas concentrations currently
being used for calibration error tests, system integrity checks and
linearity checks are unsuitable for use with the new span value,
then a diagnostic linearity or 3-level system integrity check using
the new calibration gas concentrations 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. If the Hg monitor does not have a converter, the
HgCl2 injection capability is not required.
* * * * *
0
37. Appendix A to part 75 is further amended by:
0
a. Adding a new paragraph (c) to section 3.1;
0
b. Adding a new paragraph (3) to section 3.2; and
0
c. Adding new sections 3.3.8 and 3.4.3.
The revisions and additions read as follows:
Appendix A to Part 75--Specifications and Test Procedures
* * * * *
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/scm, 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/scm.
3.2 Linearity Check
* * * * *
(3) For Hg monitors:
(i) 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
(ii) 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/scm, whichever is less restrictive.
(iii) For the 3-level system integrity check required under
Sec. 75.20(c)(1)(vi), the system 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
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/scm, 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/scm, in cases where the relative accuracy specification of
20.0 percent is not achieved.
3.4 Bias
* * * * *
3.4.3 Hg Monitoring Systems
Mercury concentration 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.
* * * * *
0
38. 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:
Appendix A to Part 75--Specifications and Test Procedures
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 CEMS, a
moisture monitoring system, a Hg concentration 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, ounces/
hr, 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.
* * * * *
0
39. Appendix A to part 75 is further amended by adding new section
5.1.9, to read as follows:
Appendix A to Part 75--Specifications and Test Procedures
* * * * *
5. Calibration Gas.
* * * * *
5.1.9 Mercury Standards.
For 7-day calibration error tests of Hg concentration monitors
and for daily calibration error tests of Hg monitors, either
elemental Hg standards or a NIST-traceable source of oxidized Hg may
be used. For linearity checks, elemental Hg standards shall be used.
For 3-level and single-point system integrity checks under Sec.
75.20(c)(1)(vi), sections 6.2(g) and 6.3.1 of this appendix, and
sections 2.1.1, 2.2.1 and 2.6 of appendix B to this part, a NIST-
traceable source of oxidized Hg shall be used. Alternatively, other
NIST-traceable standards may be used for the required checks,
subject to the approval of the Administrator.
* * * * *
0
40. Appendix A to part 75 is further amended by:
0
a. Revising the first sentence of the introductory text to section 6.2;
0
b. Adding new paragraph (g) to section 6.2;
0
c. Revising the second sentence of section 6.3.1 and adding a new third
sentence;
[[Page 28692]]
0
d. Revising the first sentence of section 6.5;
0
e. Revising section 6.5(a);
0
f. Revising the second sentence of section 6.5(c);
0
g. Revising section 6.5(g);
0
h. Revising section 6.5.1(a);
0
i. Revising section 6.5.1(b);
0
j. Adding new paragraph (c) to section 6.5.6;
0
k. Revising the first sentence and adding three sentences at the end of
section 6.5.7(a); and
0
l. Revising sections 6.5.7(b) and 6.5.10.
The revisions read as follows:
Appendix A to Part 75--Specifications and Test Procedures
* * * * *
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 performing the 3-level system integrity checks
described in Sec. 75.20(c)(1)(vi) and section 2.6 of appendix B to
this part.
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
concentration 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. For Hg monitors, you may
perform this test using either elemental Hg standards or a NIST-
traceable source of oxidized Hg. * * *
* * * * *
6.5 Relative Accuracy and Bias Tests (General Procedures)
Perform the required relative accuracy test audits (RATAs) as
follows for each CO2 emissions concentration monitor
(including O2 monitors used to determine CO2
emissions concentration), each SO2 pollutant
concentration monitor, each NOX concentration monitoring
system used to determine NOX mass emissions, each flow
monitor, each NOX-diluent CEMS, each O2 or
CO2 diluent monitor used to calculate heat input, each Hg
concentration 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 CEMS 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 emissions
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 CEMS, each
Hg concentration 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 emissions concentration monitor,
each CO2 or O2 diluent monitor used to
determine heat input, each NOX-diluent CEMS, each
NOX concentration monitoring system used to determine
NOX mass emissions, as defined in Sec. 75.71(a)(2), each
Hg concentration 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 CEMS measurements. * * * For
the RATA of a Hg CEMS using the Ontario Hydro Method, or for the
RATA of a sorbent trap system (irrespective of the reference method
used), the time per run must be long enough to collect a sufficient
mass of Hg to analyze. For the RATA of a sorbent trap monitoring
system, use the same-size trap that is used for daily operation of
the monitoring system. Spike the third section of each sorbent trap
with elemental Hg, as described in section 7.1.2 of appendix K to
this part. Install a new pair of sorbent traps prior to each test
run. For each run, the sorbent trap data shall be validated
according to the quality assurance criteria in section 8 of appendix
K to this part.
(b) To properly correlate individual SO2, Hg, or
NOX CEMS 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 or an approved instrumental 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.
* * * * *
0
41. Appendix A to part 75 is further amended by:
0
a. Revising the title of section 7.3 and the first sentence of the
introductory text of section 7.3;
0
b. Revising the introductory text of section 7.6;
0
c. Revising the first sentence in paragraph (b) of section 7.6.5 and
adding a sentence at the end of paragraph (b); and
[[Page 28693]]
0
d. Revising paragraph (f) in section 7.6.5.
The revisions and additions read as follows:
Appendix A to Part 75--Specifications and Test Procedures
* * * * *
7. Calculations.
* * * * *
7.3 Relative Accuracy for SO2 and CO2
Emissions 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 emissions
concentration monitors, CO2 or O2 monitors
used only for heat input rate determination, NOX
concentration monitoring systems used to determine 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 CEMS, Hg concentration
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
* * * * *
(b) For single-load RATAs of SO2 pollutant
concentration monitors, NOX concentration monitoring
systems, NOX-diluent monitoring systems, Hg concentration
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, 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.
* * * * *
(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.
* * * * *
0
42. 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. 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 8 of appendix K
to this part.
1.5.3 Hg Analysis
Explain the chain of custody employed in packing, transporting,
and analyzing the sorbent traps (see sections 7.2.8 and 7.2.9 in
appendix K to this part). Keep records of all Hg analyses. The
analyses shall be performed in accordance with the procedures
described in section 10 of appendix K to this part.
1.5.4 Laboratory Certification
The QA Plan shall include documentation that the laboratory
performing the 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 17025. Alternatively,
if the laboratory performs the spike recovery study described in
section 10.3 of appendix K to this part and repeats that procedure
annually, ISO certification is not required.
1.5.5 Data Collection Period
State, and provide the rationale for, the minimum acceptable
data collection period (e.g., one day, one week, etc.) for the size
of sorbent trap selected for the monitoring. Include in the
discussion such factors as the Hg concentration in the stack gas,
the capacity of the sorbent trap, and the minimum mass of Hg
required for the 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.
* * * * *
0
43. Appendix B to part 75 is further amended by:
0
a. Revising the first sentence in section 2.1.1 and adding a new second
sentence;
0
b. Revising paragraph (a) of section 2.1.4;
0
c. Revising section 2.2.1;
0
d. Revising the first sentence of paragraph (a) of section 2.3.1.1 and
adding a new second sentence to paragraph (a);
0
e. Revising paragraph (a) of section 2.3.1.3;
0
f. Revising paragraph (i) of section 2.3.2;
0
g. Revising section 2.3.4;
0
h. Adding new section 2.6 before Figure 1;
0
i. Revising Figure 1 and the first two footnotes to Figure 1 (footnotes
1 and 2 remain unchanged);
0
j. Revising Figure 2;
The revisions and additions read as follows:
Appendix B to Part 75--Quality Assurance and Quality Control Procedures
* * * * *
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 monitoring system
(including moisture monitoring systems consisting of wet- and dry-
basis O2 analyzers) and each Hg monitoring system
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. For Hg monitors, the daily assessments may
be made using either elemental Hg standards or a NIST-traceable
source of oxidized Hg. * * *
* * * * *
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
[[Page 28694]]
calibration error of a CO2 or O2 monitor
(including O2 monitors used to measure CO2
emissions or percent moisture) exceeds 1.0 percent CO2 or
O2, 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]RA[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 5.0%
of the span value. Notwithstanding, the Hg monitor shall not be
considered out-of-control if [bond]R-A[bond] in Equation A-6 does
not exceed 1.0 [mu]g/scm. 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 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 CEMS 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. 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. For Hg monitors, perform the
linearity checks using elemental Hg standards. Alternatively, you
may perform 3-level system integrity checks at the same three
calibration gas levels (i.e., low, mid, and high), using a NIST-
traceable source of oxidized Hg. If you choose this option, the
performance specification in section 3.2(c)(3) of appendix A to this
part must be met at each gas level. For units using both a low and
high span value, a linearity check is required only on the range(s)
used to record and report emission data during the QA operating
quarter. Conduct the linearity checks no less than 30 days apart, to
the extent practicable. The data validation procedures in section
2.2.3(e) of this appendix shall be followed.
* * * * *
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 emissions 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, NOX-diluent CEMS, or SO2-
diluent CEMS. For each primary and redundant backup Hg concentration
monitoring system and each 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 emissions 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, 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 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 CEMS, NOX concentration
monitoring system used to calculate NOX mass emissions,
Hg concentration 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.
* * * * *
2.6 System Integrity Checks for Hg Monitors
For each Hg concentration monitoring system (except for a Hg
monitor that does not have a converter), perform a single-point
system integrity check weekly, i.e., at least once every 168 unit or
stack operating hours, using a NIST-traceable source of oxidized Hg.
Perform this check using a mid- or high-level gas concentration, as
defined in section 5.2 of appendix A to this part. The performance
specification in section 3.2(c)(3) of appendix A to this part must
be met, otherwise the monitoring system is considered out-of-control
until a subsequent system integrity check is passed. This weekly
check is not required if the daily calibration assessments in
section 2.1.1 of this appendix are performed using a NIST-traceable
source of oxidized Hg.
Figure 1 to Appendix B of Part 75--Quality Assurance Test Requirements
----------------------------------------------------------------------------------------------------------------
QA test frequency requirements*
Test ---------------------------------------------------------------------
Daily Weekly Quarterly Semiannual Annual
----------------------------------------------------------------------------------------------------------------
Calibration Error or System Integrity ............ ............ ............ ............ ............
Check** (2 pt.)..........................
Interference Check (flow)................. ............ ............ ............ ............ ............
Flow-to-Load Ratio........................ ............ ............ ............ ............ ............
Leak Check (DP flow monitors)............. ............ ............ ............ ............ ............
Linearity Check or System Integrity ............ ............ ............ ............ ............
Check** (3-point)........................
Single-point System Integrity Check**..... ............ ............ ............ ............ ............
RATA (SO2, NOX, CO2, O2, H2O) 1........... ............ ............ ............ ............ ............
RATA (all Hg monitoring systems).......... ............ ............ ............ ............ ............
[[Page 28695]]
RATA (flow ) 1,2.......................... ............ ............ ............ ............ ............
----------------------------------------------------------------------------------------------------------------
\*\ ``Daily'' means operating days, only. ``Weekly'' means once every 168 unit or stack operating hours.
``Quarterly'' means once every QA operating quarter. ``Semiannual'' means once every two QA operating
quarters. ``Annual'' means once every four QA operating quarters.
\**\ The system integrity check applies only to Hg monitors with converters. The single-point weekly check is
not required if daily system integrity checks are performed using a NIST-traceable source of oxidized Hg.
* * * * *
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 minus> 12.0 ppmX.
15.0 ppmX.
SO2-diluent................. 7.5% < RA <= 10.0% RA <= 7.5% or minus>0. 025 lb/
0.030 lb/MMBtuX. MMBtuX.
NOX-diluent................. 7.5% < RA <= 10.0% RA <= 7.5% or minus>0. 015 lb/
0.020 lb/MMBtuX. MMBtuX.
Flow........................ 7.5% < RA <= 10.0% RA <= 7.5%.
or 1.5
fpsX.
CO2 or O2................... 7.5% < RA <= 10.0% RA <= 7.5% or minus> 0.7% CO2/O2x
1.0% CO2/O2X.
HgX......................... .................... RA < 20.0% or 1.0 [mu]g/
dscmX.
Moisture.................... 7.5% < RA <= 10.0% RA <= 7.5% or minus> 1.0% H2OX.
1.5% H2OX.
------------------------------------------------------------------------
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. The specifications for Hg
monitors also apply to sorbent trap monitoring systems.
Y A NOX concentration monitoring system used to determine NOX mass
emissions under Sec. 75.71.
0
44. 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 that measures on a wet basis and a
flow monitor, use the following equation:
[GRAPHIC] [TIFF OMITTED] TR18MY05.023
Where:
Mh = Hg mass emissions for the hour, rounded off to three
decimal places, (ounces).
K = Units conversion constant, 9.978 x 10-10 oz-scm/
[mu]g-scf
Ch = Hourly Hg concentration, wet basis, adjusted for
bias if the bias-test procedures in appendix A to this part show
that a bias-adjustment factor is necessary, ([mu]g/wscm).
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)
th = Unit or stack operating time, as defined in Sec.
72.2, (hr)
9.1.2 To determine the hourly Hg mass emissions when using a Hg
concentration monitoring system that measures on a dry basis or a
sorbent trap monitoring system and a flow monitor, use the following
equation:
[GRAPHIC] [TIFF OMITTED] TR18MY05.024
Where:
Mh = Hg mass emissions for the hour, rounded off to three
decimal places, (ounces).
K = Units conversion constant, 9.978 x 10-10 oz-scm/
[mu]g-scf
Ch = Hourly Hg concentration, dry basis, adjusted for
bias if the bias-test procedures in appendix A to this part show
that a bias-adjustment factor is necessary, ([mu]g/dscm). For
sorbent trap systems, a single value of Ch (i.e., a flow-
proportional average concentration for the data collection period),
is applied to each hour in the data collection period, for a
particular pair of traps.
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 % H2O 100)
th = Unit or stack operating time, as defined in Sec.
72.2, (hr)
9.1.3 For units that are demonstrated under Sec. 75.81(d) to
emit less than 464 ounces of Hg per year, and for which the owner or
operator elects not to continuously monitor the Hg concentration,
calculate the hourly Hg mass emissions using Equation F-28 in
section 9.1.1 of this appendix, except that ``Ch'' shall
be the applicable default Hg concentration from Sec. 75.81(c), (d),
or (e), expressed in [mu]g/scm. Correction for the stack gas
moisture content is not required when this methodology is used.
9.2 Use the following equation to calculate quarterly and year-
to-date Hg mass emissions in ounces:
[GRAPHIC] [TIFF OMITTED] TR18MY05.025
Where:
Mtime period = Hg mass emissions for the given time
period i.e., quarter or year-to-date, rounded to the nearest
thousandth, (ounces).
Mh = Hg mass emissions for the hour, rounded to three
decimal places, (ounces).
n = 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 in
sections 5.3, 5.6 and 5.7 of this appendix.
0
45. Part 75 is amended by adding Appendix K, to read as follows:
Appendix K to Part 75--Quality Assurance and Operating Procedures for
Sorbent Trap Monitoring Systems
1.0 Scope and Application
This appendix specifies sampling, and analytical, and quality-
assurance criteria and
[[Page 28696]]
procedures for the performance-based monitoring of vapor-phase
mercury (Hg) emissions in combustion flue gas streams, using a
sorbent trap monitoring system (as defined in Sec. 72.2 of this
chapter). The principle employed is continuous sampling using in-
stack sorbent media coupled with analysis of the integrated samples.
The performance-based approach of this appendix allows for use of
various suitable sampling and analytical technologies while
maintaining a specified and documented level of data quality through
performance criteria. Persons using this appendix should have a
thorough working knowledge of Methods 1, 2, 3, 4 and 5 in appendices
A-1 through A-3 to part 60 of this chapter, as well as the
determinative technique selected for analysis.
1.1 Analytes.
The analyte measured by these procedures and specifications is
total vapor-phase Hg in the flue gas, which represents the sum of
elemental Hg (Hg\0\, CAS Number 7439-97-6) and oxidized forms of Hg,
in mass concentration units of micrograms per dry standard cubic
meter ([mu]g/dscm).
1.2 Applicability.
These performance criteria and procedures are applicable to
monitoring of vapor-phase Hg emissions under relatively low-dust
conditions (i.e., sampling in the stack after all pollution control
devices), from coal-fired electric utility steam generators which
are subject to subpart I of this part. Individual sample collection
times can range from 30 minutes to several days in duration,
depending on the Hg concentration in the stack. The monitoring
system must achieve the performance criteria specified in Section 8
of this appendix and the sorbent media capture ability must not be
exceeded. The sampling rate must be maintained at a constant
proportion to the total stack flowrate to ensure representativeness
of the sample collected. Failure to achieve certain performance
criteria will result in invalid Hg emissions monitoring data.
2.0 Principle.
Known volumes of flue gas are extracted from a stack or duct
through paired, in-stack, pre-spiked sorbent media traps at an
appropriate nominal flow rate. Collection of Hg on the sorbent media
in the stack mitigates potential loss of Hg during transport through
a probe/sample line. Paired train sampling is required to determine
measurement precision and verify acceptability of the measured
emissions data.
The sorbent traps are recovered from the sampling system,
prepared for analysis, as needed, and analyzed by any suitable
determinative technique that can meet the performance criteria. A
section of each sorbent trap is spiked with Hg\0\ prior to sampling.
This section is analyzed separately and the recovery value is used
to correct the individual Hg sample for measurement bias.
3.0 Clean Handling and Contamination.
To avoid Hg contamination of the samples, special attention
should be paid to cleanliness during transport, field handling,
sampling, recovery, and laboratory analysis, as well as during
preparation of the sorbent cartridges. Collection and analysis of
blank samples (field, trip, lab) is useful in verifying the absence
of contaminant Hg.
4.0 Safety.
4.1 Site hazards.
Site hazards must be thoroughly considered in advance of
applying these procedures/specifications in the field; advance
coordination with the site is critical to understand the conditions
and applicable safety policies. At a minimum, portions of the
sampling system will be hot, requiring appropriate gloves, long
sleeves, and caution in handling this equipment.
4.2 Laboratory safety policies.
Laboratory safety policies should be in place to minimize risk
of chemical exposure and to properly handle waste disposal.
Personnel shall wear appropriate laboratory attire according to a
Chemical Hygiene Plan established by the laboratory.
4.3 Toxicity or carcinogenicity.
The toxicity or carcinogenicity of any reagents used must be
considered. Depending upon the sampling and analytical technologies
selected, this measurement may involve hazardous materials,
operations, and equipment and this appendix does not address all of
the safety problems associated with implementing this approach. It
is the responsibility of the user to establish appropriate safety
and health practices and determine the applicable regulatory
limitations prior to performance. Any chemical should be regarded as
a potential health hazard and exposure to these compounds should be
minimized. Chemists should refer to the Material Safety Data Sheet
(MSDS) for each chemical used.
4.4 Wastes.
Any wastes generated by this procedure must be disposed of
according to a hazardous materials management plan that details and
tracks various waste streams and disposal procedures.
5.0 Equipment and Supplies.
The following list is presented as an example of key equipment
and supplies likely required to perform vapor-phase Hg monitoring
using a sorbent trap monitoring system. It is recognized that
additional equipment and supplies may be needed. Collection of
paired samples is required. Also required are a certified stack gas
volumetric flow monitor that meets the requirements of Sec. 75.10
and an acceptable means of correcting for the stack gas moisture
content, i.e., either by using data from a certified continuous
moisture monitoring system or by using an approved default moisture
value (see Sec. Sec. 75.11(b) and 75.12(b)).
5.1 Sorbent Trap Monitoring System.
A typical sorbent trap monitoring system is shown in Figure K-1.
The monitoring system shall include the following components:
BILLING CODE 6560-50-P
[[Page 28697]]
[GRAPHIC] [TIFF OMITTED] TR18MY05.019
BILLING CODE 6560-50-C
5.1.1 Sorbent Traps.
The sorbent media used to collect Hg must be configured in a
trap with three distinct and identical segments or sections,
connected in series, that are amenable to separate analyses. Section
1 is designated for primary capture of gaseous Hg. Section 2 is
designated as a backup section for determination of vapor-phase Hg
breakthrough. Section 3 is designated for QA/QC purposes where this
section shall be spiked with an known amount of gaseous
Hg0 prior to sampling and later analyzed to determine
recovery efficiency. The sorbent media may be any collection
material (e.g., carbon, chemically-treated filter, etc.) capable of
quantitatively capturing and recovering for subsequent analysis, all
gaseous forms of Hg for the intended application. Selection of the
sorbent media shall be based on the material's ability to achieve
the performance criteria contained in Section 8 of this appendix as
well as the sorbent's vapor-phase Hg capture efficiency for the
emissions matrix and the expected sampling duration at the test
site. The sorbent media must be obtained from a source that can
demonstrate the quality assurance and control necessary to ensure
consistent reliability. The paired sorbent traps are supported on a
probe (or probes) and inserted directly into the flue gas stream.
5.1.2 Sampling Probe Assembly.
Each probe assembly shall have a leak-free attachment to the
sorbent trap(s). Each sorbent trap must be mounted at the entrance
of or within the probe such that the gas sampled enters the trap
directly. Each probe/sorbent trap assembly must be heated to a
temperature sufficient to prevent liquid condensation in the sorbent
trap(s). Auxiliary heating is required only where the stack
temperature is too low to prevent condensation. Use a calibrated
thermocouple to monitor the stack temperature. A single probe
capable of operating the paired sorbent traps may be used.
Alternatively, individual probe/sorbent trap assemblies may be used,
provided that the individual sorbent traps are co-located to ensure
representative Hg monitoring and are sufficiently separated to
prevent aerodynamic interference.
5.1.3 Moisture Removal Device.
A robust moisture removal device or system, suitable for
continuous duty (such as a Peltier cooler), shall be used to remove
water vapor from the gas stream prior to entering the dry gas meter.
5.1.4 Vacuum Pump.
Use a leak-tight, vacuum pump capable of operating within the
candidate system's flow range.
5.1.5 Dry Gas Meter.
A dry gas meter shall be used to determine total sample volume.
The meter must be sufficiently accurate to measure the total sample
volume within 2 percent, must be calibrated at the selected flow
rate and conditions actually encountered during sampling, and shall
be equipped with a temperature sensor capable of measuring typical
meter temperatures accurately to within 3 [deg]C for correcting
final sample volume.
5.1.6 Sample Flow Rate Meter and Controller.
Use a flow rate indicator and controller for maintaining
necessary sampling flow rates.
5.1.7 Temperature Sensor.
Same as Section 6.1.1.7 of Method 5 in appendix A-3 to part 60
of this chapter.
5.1.8 Barometer.
Same as Section 6.1.2 of Method 5 in appendix A-3 to part 60 of
this chapter.
5.1.9 Data Logger (Optional).
Device for recording associated and necessary ancillary
information (e.g., temperatures, pressures, flow, time, etc.).
5.2 Gaseous Hg\0\ Sorbent Trap Spiking System.
A known mass of gaseous Hg\0\ must be spiked onto section 3 of
each sorbent trap prior to sampling. Any approach capable of
quantitatively delivering known masses of Hg\0\ onto sorbent traps
is acceptable. Several technologies or devices are available to meet
this objective. Their practicality is a function of Hg mass spike
levels. For low levels, NIST-certified or NIST-traceable gas
generators or tanks may be suitable, but will likely require long
preparation times. A more practical, alternative system, capable of
delivering almost any mass required, makes use of NIST-certified or
NIST-traceable Hg salt solutions (e.g.,
Hg(NO3)2). With this system, an aliquot of
known volume and concentration is added to a reaction vessel
containing a reducing agent (e.g., stannous chloride); the Hg salt
solution is reduced to Hg\0\ and purged onto section 3 of the
sorbent trap using an impinger sparging system.
5.3 Sample Analysis Equipment.
Any analytical system capable of quantitatively recovering and
quantifying total gaseous Hg from sorbent media is acceptable
provided that the analysis can meet the performance criteria in
Section 8 of this procedure. Candidate recovery
[[Page 28698]]
techniques include leaching, digestion, and thermal desorption.
Candidate analytical techniques include ultraviolet atomic
fluorescence (UV AF); ultraviolet atomic absorption (UV AA), with
and without gold trapping; and in situ X-ray fluorescence (XRF)
analysis.
6.0 Reagents and Standards.
Only NIST-certified or NIST-traceable calibration gas standards
and reagents shall be used for the tests and procedures required
under this appendix.
7.0 Sample Collection and Transport.
7.1 Pre-Test Procedures.
7.1.1 Selection of Sampling Site.
Sampling site information should be obtained in accordance with
Method 1 in appendix A-1 to part 60 of this chapter. Identify a
monitoring location representative of source Hg emissions. Locations
shown to be free of stratification through measurement traverses for
gases such as SO2 and NOX may be one such
approach. An estimation of the expected stack Hg concentration is
required to establish a target sample flow rate, total gas sample
volume, and the mass of Hg\0\ to be spiked onto section 3 of each
sorbent trap.
7.1.2 Pre-sampling Spiking of Sorbent Traps.
Based on the estimated Hg concentration in the stack, the target
sample rate and the target sampling duration, calculate the expected
mass loading for section 1 of each sorbent trap (for an example
calculation, see section 11.1 of this appendix). The pre-sampling
spike to be added to section 3 of each sorbent trap shall be within
50 percent of the expected section 1 mass loading.
Spike section 3 of each sorbent trap at this level, as described in
section 5.2 of this appendix. For each sorbent trap, keep an
official record of the mass of Hg\0\ added to section 3. This record
shall include, at a minimum, the ID number of the trap, the date and
time of the spike, the name of the analyst performing the procedure,
the mass of Hg\0\ added to section 3 of the trap ([mu]g), and the
supporting calculations. This record shall be maintained in a format
suitable for inspection and audit and shall be made available to the
regulatory agencies upon request.
7.1.3 Pre-test Leak Check.
Perform a leak check with the sorbent traps in place. Draw a
vacuum in each sample train. Adjust the vacuum in the sample train
to 15'' Hg. Using the dry gas meter, determine leak rate. The
leakage rate must not exceed 4 percent of the target sampling rate.
Once the leak check passes this criterion, carefully release the
vacuum in the sample train then seal the sorbent trap inlet until
the probe is ready for insertion into the stack or duct.
7.1.4 Determination of Flue Gas Characteristics.
Determine or measure the flue gas measurement environment
characteristics (gas temperature, static pressure, gas velocity,
stack moisture, etc.) in order to determine ancillary requirements
such as probe heating requirements (if any), initial sample rate,
proportional sampling conditions, moisture management, etc.
7.2 Sample Collection.
7.2.1 Remove the plug from the end of each sorbent trap and
store each plug in a clean sorbent trap storage container. Remove
the stack or duct port cap and insert the probe(s). Secure the
probe(s) and ensure that no leakage occurs between the duct and
environment.
7.2.2 Record initial data including the sorbent trap ID, start
time, starting dry gas meter readings, initial temperatures, set-
points, and any other appropriate information.
7.2.3 Flow Rate Control.
Set the initial sample flow rate at the target value from
section 7.1.1 of this appendix. Record the initial dry gas meter
reading, stack temperature, meter temperatures, etc. Then, for every
operating hour during the sampling period, record the date and time,
the sample flow rate, the gas meter reading, the stack temperature,
the flow meter temperatures, temperatures of heated equipment such
as the vacuum lines and the probes (if heated), and the sampling
system vacuum readings. Also record the stack gas flow rate, as
measured by the certified flow monitor, and the ratio of the stack
gas flow rate to the sample flow rate. Adjust the sampling flow rate
to maintain proportional sampling, i.e., keep the ratio of the stack
gas flow rate to sample flow rate constant, to within 25
percent of the reference ratio from the first hour of the data
collection period (see section 11 of this appendix).
7.2.4 Stack Gas Moisture Determination.
Determine stack gas moisture using 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 moisture default value provided in Sec. 75.11 or Sec.
75.12, or a site-specific moisture default value approved by
petition under Sec. 75.66.
7.2.5 Essential Operating Data.
Obtain and record any essential operating data for the facility
during the test period, e.g., the barometric pressure must be
obtained for correcting sample volume to standard conditions. At the
end of the data collection period, record the final dry gas meter
reading and the final values of all other essential parameters.
7.2.6 Post Test Leak Check.
When sampling is completed, turn off the sample pump, remove the
probe/sorbent trap from the port and carefully re-plug the end of
each sorbent trap. Perform a leak check with the sorbent traps in
place, at the maximum vacuum reached during the sampling period. Use
the same general approach described in section 7.1.3 of this
appendix. Record the leakage rate and vacuum. The leakage rate must
not exceed 4 percent of the average sampling rate for the data
collection period. Following the leak check, carefully release the
vacuum in the sample train.
7.2.7 Sample Recovery.
Recover each sampled sorbent trap by removing it from the probe,
sealing both ends. Wipe any deposited material from the outside of
the sorbent trap. Place the sorbent trap into an appropriate sample
storage container and store/preserve in appropriate manner.
7.2.8 Sample Preservation, Storage, and Transport.
While the performance criteria of this approach provide for
verification of appropriate sample handling, it is still important
that the user consider, determine, and plan for suitable sample
preservation, storage, transport, and holding times for these
measurements. Therefore, procedures in ASTM D6911-03 ``Standard
Guide for Packaging and Shipping Environmental Samples for
Laboratory Analysis'' (incorporated by reference, see Sec. 75.6)
shall be followed for all samples.
7.2.9 Sample Custody.
Proper procedures and documentation for sample chain of custody
are critical to ensuring data integrity. The chain of custody
procedures in ASTM D4840-99 (reapproved 2004) ``Standard Guide for
Sample Chain-of-Custody Procedures'' (incorporated by reference, see
Sec. 75.6) shall be followed for all samples (including field
samples and blanks).
8.0 Quality Assurance and Quality Control.
Table K-1 summarizes the QA/QC performance criteria that are
used to validate the Hg emissions data from sorbent trap monitoring
systems, including the relative accuracy test audit (RATA)
requirement (see Sec. 75.20(c)(9), section 6.5.7 of appendix A to
this part, and section 2.3 of appendix B to this part). Except as
provided in Sec. 75.15(h) and as otherwise indicated in Table K-1,
failure to achieve these performance criteria will result in
invalidation of Hg emissions data.
Table K-1.--Quality Assurance/Quality Control Criteria for Sorbent Trap Monitoring Systems
----------------------------------------------------------------------------------------------------------------
QA/QC test or specification Acceptance criteria Frequency Consequences if not met
----------------------------------------------------------------------------------------------------------------
Pre-test leak check.................. <=4% of target sampling Prior to sampling...... Sampling shall not
rate. commence until the
leak check is passed.
Post-test leak check................. <=4% of average After sampling......... Sample invalidated.**
sampling rate.
[[Page 28699]]
Ratio of stack gas flow rate to Maintain within 25% of initial data collection period. evaluation.
ratio from first hour
of data collection
period.
Sorbent trap section 2 breakthrough.. <= 5% of Section 1 Hg Every sample........... Sample invalidated.**
mass.
Paired sorbent trap agreement........ <=10% Relative Every sample........... Sample invalidated.**
Deviation (RD).
Spike recovery study................. Average recovery Prior to analyzing Field samples shall not
between 85% and 115% field samples and be analyzed until the
for each of the 3 prior to use of new percent recovery
spike concentration sorbent media. criteria has been met.
levels.
Multipoint analyzer calibration...... Each analyzer reading On the day of analysis, Recalibrate until
within before analyzing any successful.
10% of true value and samples.
r\2\ >=0.99.
Analysis of independent calibration Within 10% Following daily Recalibrate and repeat
standard. of true value. calibration, prior to independent standard
analyzing field analysis until
samples. successful.
Spike recovery from section 3 of 75-125% of spike amount Every sample........... Sample invalidated.**
sorbent trap.
RATA................................. RA <= 20.0% or Mean For initial Data from the system
difference <= 1.0 certification and are invalidated until
[mu]g/dscm for low annually thereafter. a RATA is passed.
emitters.
Dry gas meter calibration (At 3 Calibration factor (Y) Prior to initial use Recalibrate the meter
orifice initially, and 1 setting within 5% and at least quarterly at three orifice
thereafter). of average value from thereafter. settings to determine
the initial (3-point) a new value of Y.
calibration.
Temperature sensor calibration....... Absolute temperature Prior to initial use Recalibrate. Sensor may
measured by sensor and at least quarterly not be used until
within thereafter. specification is met.
1.5% of a reference
sensor.
Barometer calibration................ Absolute pressure Prior to initial use Recalibrate. Instrument
measured by instrument and at least quarterly may not be used until
within 10 thereafter. specification is met.
mm Hg of reading with
a mercury barometer.
----------------------------------------------------------------------------------------------------------------
And data from the pair of sorbent traps are also invalidated
9.0 Calibration and Standardization.
9.1 Only NIST-certified and NIST-traceable calibration standards
(i.e., calibration gases, solutions, etc.) shall be used for the
spiking and analytical procedures in this appendix.
9.2 Dry Gas Meter Calibration.
Prior to its initial use, perform a full calibration of the
metering system at three orifice settings to determine the average
dry gas meter coefficient (Y), as described in section 10.3.1 of
Method 5 in appendix A-3 to part 60 of this chapter. Thereafter,
recalibrate the metering system quarterly at one intermediate
orifice setting, as described in section 10.3.2 of Method 5 in
appendix A-3 to part 60 of this chapter. If a quarterly
recalibration shows that the value of Y has changed by more than 5
percent, repeat the full calibration of the metering system to
determine a new value of Y.
9.3 Thermocouples and Other Temperature Sensors.
Use the procedures and criteria in Section 10.3 of Method 2 in
appendix A-1 to part 60 of this chapter to calibrate in-stack
temperature sensors and thermocouples. Dial thermometers shall be
calibrated against mercury-in-glass thermometers. Calibrations must
be performed prior to initial use and at least quarterly thereafter.
At each calibration point, the absolute temperature measured by the
temperature sensor must agree to within 1.5 percent of
the temperature measured with the reference sensor, otherwise the
sensor may not continue to be used.
9.4 Barometer.
Calibrate against a mercury barometer. Calibration must be
performed prior to initial use and at least quarterly thereafter. At
each calibration point, the absolute pressure measured by the
barometer must agree to within 10 mm Hg of the pressure
measured by the mercury barometer, otherwise the barometer may not
continue to be used.
9.5 Other Sensors and Gauges.
Calibrate all other sensors and gauges according to the
procedures specified by the instrument manufacturer(s).
9.6 Analytical System Calibration.
See section 10.1 of this appendix.
10.0 Analytical Procedures.
The analysis of the Hg samples may be conducted using any
instrument or technology capable of quantifying total Hg from the
sorbent media and meeting the performance criteria in section 8 of
this appendix.
10.1 Analyzer System Calibration.
Perform a multipoint calibration of the analyzer at three or
more upscale points over the desired quantitative range (multiple
calibration ranges shall be calibrated, if necessary). The field
samples analyzed must fall within a calibrated, quantitative range
and meet the necessary performance criteria. For samples that are
suitable for aliquotting, a series of dilutions may be needed to
ensure that the samples fall within a calibrated range. However, for
sorbent media samples that are consumed during analysis (e.g.,
thermal desorption techniques), extra care must be taken to ensure
that the analytical system is appropriately calibrated prior to
sample analysis. The calibration curve range(s) should be determined
based on the anticipated level of Hg mass on the sorbent media.
Knowledge of estimated stack Hg concentrations and total sample
volume may be required prior to analysis. The calibration curve for
use with the various analytical techniques (e.g., UV AA, UV AF, and
XRF) can be generated by directly introducing standard solutions
into the analyzer or by spiking the standards onto the sorbent media
and then introducing into the analyzer after preparing the sorbent/
standard according to the particular analytical technique. For each
calibration curve, the value of the square of the linear correlation
coefficient, i.e., r2, must be >= 0.99, and the analyzer
response must be within 10 percent of reference value
at each upscale calibration point. Calibrations must be performed on
the day of the analysis, before analyzing any of the samples.
Following calibration, an independently prepared standard (not from
same calibration stock solution) shall be analyzed. The measured
value of the independently prepared standard must be within 10 percent of the expected value.
10.2 Sample Preparation.
Carefully separate the three sections of each sorbent trap.
Combine for analysis all materials associated with each section,
i.e., any supporting substrate that the sample gas passes through
prior to entering a media section (e.g., glass wool, polyurethane
foam, etc.) must be analyzed with that segment.
[[Page 28700]]
10.3 Spike Recovery Study.
Before analyzing any field samples, the laboratory must
demonstrate the ability to recover and quantify Hg from the sorbent
media by performing the following spike recovery study for sorbent
media traps spiked with elemental mercury.
Using the procedures described in sections 5.2 and 11.1 of this
appendix, spike the third section of nine sorbent traps with gaseous
Hg0, i.e., three traps at each of three different mass
loadings, representing the range of masses anticipated in the field
samples. This will yield a 3 x 3 sample matrix. Prepare and analyze
the third section of each spiked trap, using the techniques that
will be used to prepare and analyze the field samples. The average
recovery for each spike concentration must be between 85 and 115
percent. If multiple types of sorbent media are to be analyzed, a
separate spike recovery study is required for each sorbent material.
If multiple ranges are calibrated, a separate spike recovery study
is required for each range.
10.4 Field Sample Analyses.
Analyze the sorbent trap samples following the same procedures
that were used for conducting the spike recovery study. The three
sections of the sorbent trap must be analyzed separately (i.e.,
section 1, then section 2, then section 3). Quantify the mass of
total Hg for each section based on analytical system response and
the calibration curve from section 10.1 of this appendix. Determine
the spike recovery from sorbent trap section 3. Pre-sampling spike
recoveries must be between 75 and 125 percent. To report final Hg
mass, normalize the data for sections 1 and 2 based on the sample-
specific spike recovery, and add the normalized masses together.
11.0 Calculations and Data Analysis.
11.1 Calculation of Pre-Sampling Spiking Level.
Determine sorbent trap section 3 spiking level using estimates
of the stack Hg concentration, the target sample flow rate, and the
expected sample duration. First, calculate the expected Hg mass that
will be collected in section 1 of the trap. The pre-sampling spike
must be within 50 percent of this mass. Example
calculation: For an estimated stack Hg concentration of 5 [mu]g/
m\3\, a target sample rate of 0.30 L/min, and a sample duration of 5
days:
(0.30 L/min) (1440 min/day) (5 days) (10-3 m\3\/liter)
(5[mu]g/m\3\) = 10.8 [mu]g
A pre-sampling spike of 10.8 [mu]g 50 percent is,
therefore, appropriate.
11.2 Calculations for Flow-Proportional Sampling.
For the first hour of the data collection period, determine the
reference ratio of the stack gas volumetric flow rate to the sample
flow rate, as follows:
[GRAPHIC] [TIFF OMITTED] TR18MY05.012
Where:
Rref = Reference ratio of hourly stack gas flow rate to
hourly sample flow rate
Qref = Average stack gas volumetric flow rate for first
hour of collection period, adjusted for bias, if necessary,
according to section 7.6.5 of appendix A to this part, (scfh)
Fref = Average sample flow rate for first hour of the
collection period, in appropriate units (e.g., liters/min, cc/min,
dscm/min)
K = Power of ten multiplier, to keep the value of Rref
between 1 and 100. The appropriate K value will depend on the
selected units of measure for the sample flow rate.
Then, for each subsequent hour of the data collection period,
calculate ratio of the stack gas flow rate to the sample flow rate
using the equation K-2:
[GRAPHIC] [TIFF OMITTED] TR18MY05.013
Where:
Rh = Ratio of hourly stack gas flow rate to hourly sample
flow rate
Qh = Average stack gas volumetric flow rate for the hour,
adjusted for bias, if necessary, according to section 7.6.5 of
appendix A to this part, (scfh)
Fh = Average sample flow rate for the hour, in
appropriate units (e.g., liters/min, cc/min, dscm/min)
K = Power of ten multiplier, to keep the value of Rh
between 1 and 100. The appropriate K value will depend on the
selected units of measure for the sample flow rate and the range of
expected stack gas flow rates.
Maintain the value of Rh within 25 percent
of Rref throughout the data collection period.
11.3 Calculation of Spike Recovery.
Calculate the percent recovery of each section 3 spike, as
follows:
[GRAPHIC] [TIFF OMITTED] TR18MY05.014
Where:
%R = Percentage recovery of the pre-sampling spike
M3 = Mass of Hg recovered from section 3 of the sorbent
trap, ([mu]g)
Ms = Calculated Hg mass of the pre-sampling spike, from
section 7.1.2 of this appendix, ([mu]g)
11.4 Calculation of Breakthrough.
Calculate the percent breakthrough to the second section of the
sorbent trap, as follows:
[GRAPHIC] [TIFF OMITTED] TR18MY05.015
Where:
%B = Percent breakthrough
M2 = Mass of Hg recovered from section 2 of the sorbent
trap, ([mu]g)
M1 = Mass of Hg recovered from section 1 of the sorbent
trap, ([mu]g)
11.5 Normalizing Measured Hg Mass for Section 3 Spike Recoveries.
Based on the results of the spike recovery in section 12.3 of
this appendix, normalize the Hg mass collected in sections 1 and 2
of the sorbent trap, as follows:
[GRAPHIC] [TIFF OMITTED] TR18MY05.016
Where:
M* = Normalized total mass of Hg recovered from sections 1 and of
the sorbent trap, ([mu]g)
M1 = Mass of Hg recovered from section 1 of the sorbent
trap, unadjusted, ([mu]g)
M2 = Mass of Hg recovered from section 2 of the sorbent
trap, unadjusted, ([mu]g)
Ms = Calculated Hg mass of the pre-sampling spike, from
section 7.1.2 of this appendix, ([mu]g)
M3 = Mass of Hg recovered from section 3 of the sorbent
trap, ([mu]g)
11.6 Calculation of Hg Concentration.
Calculate the Hg concentration for each sorbent trap, using the
following equation:
[GRAPHIC] [TIFF OMITTED] TR18MY05.017
Where:
C = Concentration of Hg for the collection period, ([mu]g/dscm)
M* = Normalized total mass of Hg recovered from sections 1 and 2 of
the sorbent trap, ([mu]g)
Vt = Total volume of dry gas metered during the
collection period, (dscm). For the purposes of this appendix,
standard temperature and pressure are defined as 20[deg] C and 760
mm Hg, respectively.
11.7 Calculation of Paired Trap Agreement.
Calculate the relative deviation (RD) between the Hg
concentrations measured with the paired sorbent traps:
[GRAPHIC] [TIFF OMITTED] TR18MY05.018
Where:
RD = Relative deviation between the Hg concentrations from traps
``a'' and ``b'' (percent)
Ca = Concentration of Hg for the collection period, for
sorbent trap ``a'' ([mu]g/dscm)
Cb = Concentration of Hg for the collection period, for
sorbent trap ``b'' ([mu]g/dscm)
11.8 Calculation of Hg Mass Emissions.
To calculate Hg mass emissions, follow the procedures in section
9.1.2 of appendix F to this part. Use the average of the two Hg
concentrations from the paired traps in the calculations, except as
provided in Sec. 75.15(h).
12.0 Method Performance.
These monitoring criteria and procedures have been applied to
coal-fired utility boilers (including units with post-combustion
emission controls), having vapor-phase Hg concentrations ranging
from 0.03 [mu]g/dscm to 100 [mu]g/dscm.
[FR Doc. 05-8447 Filed 5-17-05; 8:45 am]
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