[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]]

-----------------------------------------------------------------------

Part II





Environmental Protection Agency





-----------------------------------------------------------------------



40 CFR Parts 60, 72, and 75



-----------------------------------------------------------------------



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]]


-----------------------------------------------------------------------

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.

-----------------------------------------------------------------------

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:

------------------------------------------------------------------------
                                   NAICS  code   Examples of potentially
             Category                  \1\         regulated entities
------------------------------------------------------------------------
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.
------------------------------------------------------------------------
\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).
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.

---------------------------------------------------------------------------

[[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.
---------------------------------------------------------------------------

    \6\ Auctions could provide States with a less distortionary 
source of revenue.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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)
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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]
BILLING CODE 6560-50-P