Standards of Performance for New and Existing Stationary Sources: Electric Utility Steam Generating Units, 28606-28700 [05-8447]

Agencies

• ENVIRONMENTAL PROTECTION AGENCY

[Federal Register Volume 70, Number 95 (Wednesday, May 18, 2005)]
[Rules and Regulations]
[Pages 28606-28700]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 05-8447]



[[Page 28605]]

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Part II





Environmental Protection Agency





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40 CFR Parts 60, 72, and 75



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Standards of Performance for New and Existing Stationary Sources: 
Electric Utility Steam Generating Units; Final Rule

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules 
and Regulations

[[Page 28606]]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 60, 72, and 75

[OAR-2002-0056; FRL-7888-1]
RIN 2060-AJ65


Standards of Performance for New and Existing Stationary Sources: 
Electric Utility Steam Generating Units

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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SUMMARY: In this document, EPA is finalizing the Clean Air Mercury Rule 
(CAMR) and establishing standards of performance for mercury (Hg) for 
new and existing coal-fired electric utility steam generating units 
(Utility Units), as defined in Clean Air Act (CAA) section 111. The 
amendments to CAA section 111 rules would establish a mechanism by 
which Hg emissions from new and existing coal-fired Utility Units are 
capped at specified, nation-wide levels. A first phase cap of 38 tons 
per year (tpy) becomes effective in 2010, and a second phase cap of 15 
tpy becomes effective in 2018. Facilities must demonstrate compliance 
with the standard by holding one ``allowance'' for each ounce of Hg 
emitted in any given year. Allowances are readily transferrable among 
all regulated facilities. Such a ``cap-and-trade'' approach to limiting 
Hg emissions is the most cost-effective way to achieve the reductions 
in Hg emissions from the power sector.
    The added benefit of the cap-and-trade approach is that it 
dovetails well with the sulfur dioxide (SO2) and nitrogen 
oxides (NOX) emission caps under the final Clean Air 
Interstate Rule (CAIR) that was signed on March 10, 2005. CAIR 
establishes a broadly-applicable cap-and-trade program that 
significantly limit SO2 and NOX emissions from 
the power sector. The advantage of regulating Hg at the same time and 
using the same regulatory mechanism as for SO2 and 
NOX is that significant Hg emissions reductions, especially 
reductions of oxidized Hg, can and will be achieved by the air 
pollution controls designed and installed to reduce SO2 and 
NOX. Significant Hg emissions reductions can be obtained as 
a ``co-benefit'' of controlling emissions of SO2 and 
NOX; thus, the coordinated regulation of Hg, SO2, 
and NOX allows Hg reductions to be achieved in a cost-
effective manner.
    The final rule also finalizes a performance specification (PS) 
(Performance Specification 12A, ``Specification and Test Methods for 
Total Vapor Phase Mercury Continuous Emission Monitoring Systems in 
Stationary Sources'') and a test method (``Quality Assurance and 
Operating Procedures for Sorbent Trap Monitoring Systems'').
    The EPA is also taking final action to amend the definition of 
``designated pollutant.'' The existing definition predates the Clean 
Air Act Amendments of 1990 (the CAAA) and, as a result, refers to 
section 112(b)(1)(A) which no longer exists. The EPA is also amending 
the definition of ``designated pollutant'' so that it conforms to EPA's 
interpretation of the provisions of CAA section 111(d)(1)(A), as 
amended by the CAAA. That interpretation is explained in detail in a 
separate Federal Register notice (70 FR 15994; March 29, 2005) 
announcing EPA's revision of its December 2000 regulatory determination 
and removing Utility Units from the 112(c) list of categories. For 
these reasons, EPA has determined that it is appropriate to promulgate 
the revised definition of ``designated pollutant'' without prior notice 
and opportunity for comment.

DATES: The final rule is effective on July 18, 2005. The Incorporation 
by Reference of certain publications listed in the final rule are 
approved by the Director of the Office of the Federal Register as of 
July 18, 2005.

ADDRESSES: Docket. EPA has established a docket for this action under 
Docket ID No. OAR-2002-0056 and legacy Docket ID No. A-92-55. All 
documents in the legacy docket are listed in the legacy docket index 
available through the Air and Radiation Docket; all documents in the 
EDOCKET are listed in the EDOCKET index at https://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: 
maxwell.bill@epa.gov.

SUPPLEMENTARY INFORMATION: Regulated Entities. Categories and entities 
potentially regulated by the final rule include the following:

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                                   NAICS  code   Examples of potentially
             Category                  \1\         regulated entities
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Industry.........................       221112  Fossil fuel-fired
                                                 electric utility steam
                                                 generating units.
Federal government...............   \2\ 221122  Fossil fuel-fired
                                                 electric utility steam
                                                 generating units owned
                                                 by the Federal
                                                 government.
State/local/Tribal government....   \2\ 221122  Fossil fuel-fired
                                        921150   electric utility steam
                                                 generating units owned
                                                 by municipalities.
                                                Fossil fuel-fired
                                                 electric utility steam
                                                 generating units in
                                                 Indian country.
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\1\ North American Industry Classification System.
\2\ Federal, State, or local government-owned and operated
  establishments are classified according to the activity in which they
  are engaged.

    This table is not intended to be exhaustive, but rather provides a 
guide for readers regarding entities likely to be regulated by the 
final rule. This table lists examples of the types of entities EPA is 
now aware could potentially be regulated by the final rule. Other types 
of entities not listed could also be affected. To determine whether 
your facility, company, business, organization, etc., is regulated by 
the final rule, you should examine the applicability criteria in 40 CFR 
60.45a of the final new source performance standards (NSPS) amendments. 
If you have questions regarding the applicability of the final rule to 
a particular entity, consult your State or

[[Page 28607]]

local agency (or EPA Regional Office) described in the preceding FOR 
FURTHER INFORMATION CONTACT section.
    Worldwide Web (WWW). In addition to being available in the docket, 
an electronic copy of today's document will also be available on the 
WWW through EPA's Technology Transfer Network (TTN). Following 
signature by the Acting Administrator, a copy of the final rule will be 
posted on the TTN's policy and guidance page for newly proposed or 
promulgated rules at https://www.epa.gov/ttn/oarpg. The TTN provides 
information and technology exchange in various areas of air pollution 
control.
    Judicial Review. Under CAA section 307(b), judicial review of the 
final NSPS is available only by filing a petition for review in the 
U.S. Court of Appeals for the District of Columbia Circuit on or before 
July 18, 2005. Under CAA section 307(D)(7)(B), only those objections to 
the final rule which were raised with reasonable specificity during the 
period for public comment may be raised during judicial review. 
Moreover, under CAA section 307(b)(2), the requirements established by 
the final rule may not be challenged separately in any civil or 
criminal proceedings brought by EPA to enforce these requirements.
    Outline. The information presented in this preamble is organized as 
follows:

I. Background
    A. What is the source of authority for development of the final 
rule?
    B. What is the regulatory background for the final rule?
    C. What is the relationship between the final rule and the 
section 112 delisting action?
    D. What is the relationship between the final rule and other 
combustion rules?
II. Revision of Regulatory Finding on the Emissions of Hazardous Air 
Pollutants from Utility Units
III. Summary of the Final Rule Amendments
    A. Who is subject to the final rule?
    B. What are the primary sources of emissions, and what are the 
emissions?
    C. What is the affected source?
    D. What are the emission limitations and work practice 
standards?
    E. What are the performance testing, initial compliance, and 
continuous compliance requirements?
    F. What are the notification, recordkeeping, and reporting 
requirements?
IV. Significant Comments and Changes Since Proposal
    A. Why is EPA not taking final action to regulate Ni emissions 
from oil-fired units?
    B. How did EPA select the regulatory approach for coal-fired 
units for the final rule?
    C. How did EPA determine the NSPS under CAA section 111(b) for 
the final rule?
    D. How did EPA determine the Hg cap-and-trade program under CAA 
section 111(d) for the final rule?
    E. CAMR Model Cap-and-trade Program
    F. Standard of Performance Requirements
    G. What are the performance testing and other compliance 
provisions?
V. Summary of the Environmental, Energy, Cost, and Economic Impacts
    A. What are the air quality impacts?
    B. What are the non-air health, environmental, and energy 
impacts?
    C. What are the cost and economic impacts?
VI. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review
    B. Paperwork Reduction Act
    C. Regulatory Flexibility Act
    D. Unfunded Mandates Reform Act
    E. Executive Order 13132: Federalism
    F. Executive Order 13175: Consultation and Coordination with 
Indian Tribal Governments
    G. Executive Order 13045: Protection of Children from 
Environmental Health and Safety Risks
    H. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use
    I. National Technology Transfer and Advancement Act
    J. Executive Order 12898: Federal Actions to Address 
Environmental Justice in Minority Populations and Low-Income 
Populations
    K. Congressional Review Act

I. Background

A. What is the source of authority for development of the final rule?

    CAA section 111 creates a program for the establishment of 
``standards of performance.'' A ``standard of performance'' is ``a 
standard for emissions of air pollutants which reflects the degree of 
emission limitation achievable through the application of the best 
system of emission reduction, which (taking into account the cost of 
achieving such reduction, any non-air quality health and environmental 
impacts and energy requirements), the Administrator determines has been 
adequately demonstrated.'' (See CAA section 111(a)(1).)
    For new sources, EPA must first establish a list of stationary 
source categories, which, the Administrator has determined ``causes, or 
contributes significantly to, air pollution which may reasonably be 
anticipated to endanger public health or welfare.'' (See CAA section 
110(b)(1)(A).) EPA must then set Federal standards of performance for 
new sources within each listed source category. (See CAA section 
111(b)(1)(B).) Like section 112(d) standards, the standards for new 
sources under section 111(b) apply nationally and are effective upon 
promulgation. (See CAA section 111(b)(1)(B).)
    Existing sources are addressed under CAA section 111(d). EPA can 
issue standards of performance for existing sources in a source 
category only if it has established standards of performance for new 
sources in that same category under section 111(b), and only for 
certain pollutants. (See CAA section 111(d)(1).) Section 111(d) 
authorizes EPA to promulgate standards of performance that States must 
adopt through a State Implementation Plans (SIP)-like process, which 
requires State rulemaking action followed by review and approval of 
State plans by EPA. If a State fails to submit a satisfactory plan, EPA 
has the authority to prescribe a plan for the State. (See CAA section 
111(d)(2)(A).) Below in this document, we discuss in more detail (i) 
the applicable standards of performance for the regulatory 
requirements, (ii) the legal authority under CAA section 111(d) to 
regulate Hg from coal-fired Utility Units, and (iii) the legal 
authority to implement a cap-and-trade program for existing Utility 
Units.

B. What is the regulatory background for the final rule?

1. What are the relevant Federal Register actions?
    On December 20, 2000, EPA issued a finding pursuant to CAA section 
112(n)(1)(A) that it was appropriate and necessary to regulate coal- 
and oil-fired Utility Units under section 112. In making this finding, 
EPA considered the Utility Study, which was completed and submitted to 
Congress in February 1998.
    In December 2000, EPA concluded that the positive appropriate and 
necessary determination under section 112(n)(1)(A) constituted a 
decision to list coal- and oil-fired Utility Units on the section 
112(c) source category list. Relying on CAA section 112(e)(4), EPA 
explained in its December 2000 finding that neither the appropriate and 
necessary finding under section 112(n)(1)(A), nor the associated 
listing were subject to judicial review at that time. EPA did not add 
natural-gas fired units to the section 112(c) list in December 2000 
because it did not make a positive appropriate and necessary finding 
for such units.
    On January 30, 2004, EPA published in the Federal Register a notice 
of proposed rulemaking (NPR) entitled ``Proposed National Emissions 
Standards for Hazardous Air Pollutants; and, in the Alternative, 
Proposed Standards of Performance for New and Existing Stationary 
Sources: Electric Utility Steam Generating Units.'' In that

[[Page 28608]]

rule, EPA proposed three alternative regulatory approaches. First, EPA 
proposed to retain the December 2000 Finding and associated listing of 
coal- and oil-fired Utility Units and to issue maximum achievable 
control technology-based (MACT) national emission standards for 
hazardous air pollutants (NESHAP) for such units. Second, EPA 
alternatively proposed revising the Agency's December 2000 Finding, 
removing coal- and oil-fired Utility Units from the section 112(c) 
list,\1\ and issuing final standards of performance under CAA section 
111 for new and existing coal-fired units that emit Hg and new and 
existing oil-fired units that emit nickel (Ni). Finally, as a third 
alternative, EPA proposed retaining the December 2000 finding and 
regulating Hg emissions from Utility Units under CAA section 
112(n)(1)(A).
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    \1\ We did not propose revising the December 2000 finding for 
gas-fired Utility Units because EPA continues to believe that 
regualtion of such units under section 112 is not appropriate and 
necessary. We therefore take no action today with regard to gas-
fired Utility Units.
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    Shortly thereafter, on March 16, 2004, EPA published in the Federal 
Register a supplemental notice of proposed rulemaking (SNPR) entitled 
``Supplemental Notice of Proposed National Emission Standards for 
Hazardous Air Pollutants; and, in the Alternative, Proposed Standards 
of Performance for New and Existing Stationary Sources: Electric 
Utility Steam Generating Units.'' In that notice, EPA proposed certain 
additional regulatory text, which largely governed the proposed section 
111 standards of performance for Hg, which included a cap-and-trade 
program. The supplemental notice also proposed State plan approvability 
criteria and a model cap-and-trade rule for Hg emissions from coal-
fired Utility Units. The Agency received thousands of comments on the 
proposed rule and supplemental notice. Some of the more significant 
comments relating to today's action are addressed in this preamble. We 
respond to the other significant comments in the response to comments 
document entitled Response to ``Significant Public Comments on the 
Proposed Clean Air Mercury Rule,'' which is in the docket.
    On December 1, 2004, EPA published in the Federal Register a notice 
of data availability (NODA) entitled ``Proposed National Emission 
Standards for Hazardous Air Pollutants; and, in the Alternative, 
Proposed Standards of Performance for New and Existing Stationary 
Sources, Electric Utility Steam Generating Units: Notice of Data 
Availability.'' EPA issued this notice: (1) To seek additional input on 
certain new data and information concerning Hg that the Agency received 
in response to the January 30, 2004 NPR and March 16, 2004 SNPR; and 
(2) to seek input on a revised proposed benefits methodology for 
assessing the benefits of Hg regulation. EPA conducts benefits analysis 
for rulemakings consistent with the provisions of Executive Order (EO) 
12866.
2. How did the public participate in developing the final rule?
    Upon signature on December 15, 2003, the proposed rule was posted 
on the Agency's Internet Web site for public review. Following 
publication of the NPR in the Federal Register (69 FR 4652; January 30, 
2004), a 60-day public comment period ensued. Concurrent public 
hearings were held in Research Triangle Park, NC, Philadelphia, PA, and 
Chicago, IL, on February 25 and 26, 2004, at which time any member of 
the public could provide oral comment on the NPR. On March 16, 2004, a 
SNPR was published in the Federal Register (69 FR 12398). On March 17, 
2004, EPA announced that the public comment period on the NPR and SNPR 
had been extended to April 30, 2004. A public hearing on the SNPR was 
held in Denver, CO, on March 31, 2004, during which time members of the 
public could provide oral comment on any aspect of the NPR or SNPR. On 
May 5, 2004, EPA announced (69 FR 25052) that the public comment period 
for the NPR and SNPR had been reopened and extended until June 29, 
2004. On December 1, 2004, EPA published a NODA with a public comment 
period until January 3, 2005 (69 FR 69864). In addition to the public 
comment process, EPA met with a number of stakeholder groups and has 
placed in the docket records of these meetings. Comments received after 
the close of the public comment period on the NODA (January 3, 2005), 
were not considered in the analyses. Approximately 500,000 public 
comments were received during this period, indicating wide public 
interest and access.

C. What is the relationship between the final rule and the section 112 
delisting action?

    In a separate Federal Register notice (70 FR 15994; March 29, 
2005), EPA published a final Agency action which delists Utility Units 
under section 112(n)(1)(A). In that action, EPA revised the regulatory 
finding that it issued in December 2000 pursuant to CAA section 
112(n)(1)(A), and based on that revision, removed coal- and oil-fired 
electric utility steam generating units (coal- and oil-fired Utility 
Units) from the CAA section 112(c) list. Section 112(n)(1)(A) of the 
CAA is the threshold statutory provision underlying this action. 
Congress enacted this special provision for Utility Units which gives 
EPA considerable discretion in determining whether Utility Units should 
be regulated under section 112. The provision requires EPA to conduct a 
study to examine the hazards to public health that are reasonably 
anticipated to occur as the result of hazardous air pollutant (HAP) 
emissions from Utility Units after imposition of the requirements of 
the CAA. The provision also provides that EPA shall regulate Utility 
Units under section 112, but only if the Administrator determines that 
such regulation is both ``appropriate'' and ``necessary'' considering, 
among other things, the results of the study. EPA completed the study 
in 1998 (Utility Study), and in December 2000 found that it was 
``appropriate and necessary'' to regulate coal- and oil-fired Utility 
Units under CAA section 112. That December 2000 finding focused 
primarily on Hg emissions from coal-fired Utility Units. In January 
2004, EPA proposed revising the December 2000 appropriate and necessary 
finding and, based on that revision, removing coal- and oil-fired 
Utility Units from the section 112(c) list.
    In a separate Federal Register notice (70 FR 15994; March 29, 
2005), we revised the December 2000 appropriate and necessary finding 
and concluding that it is not appropriate and necessary to regulate 
coal- and oil-fired Utility Units under section 112. We took this 
action because we now believe that the December 2000 finding lacked 
foundation and because recent information demonstrates that it is not 
appropriate or necessary to regulate coal- and oil-fired Utility Units 
under section 112. Based solely on the revised finding, we are removing 
coal- and oil-fired Utility Units from the section 112(c) list and 
instead establishing standards of performance for Hg for new and 
existing coal-fired Utility Units, as defined in CAA section 111.
    The reasons supporting today's action are described in detail in a 
separate final Agency action published in the Federal Register (70 FR 
15994; March 29, 2005).

D. What is the relationship between the final rule and other combustion 
rules?

    Revised NSPS for SO2, NOX, and particulate 
matter (PM) were proposed under CAA section 111 for Utility Units (40 
CFR part 60, subpart Da) and industrial boilers (IB) (40 CFR part 60, 
subpart Db) on February 28, 2005 (70 FR

[[Page 28609]]

9706). EPA earlier promulgated NSPS for Utility Units (1979) and for IB 
(1987). In addition, the EPA promulgated another combustion-related 
standard under CAA section 112: Industrial, commercial, and 
institutional boilers and process heaters (40 CFR part 63, subpart 
DDDDD) on September 13, 2004 (69 FR 55218).
    All of the rules pertain to sources that combust fossil fuels for 
electrical power, process operations, or heating. The applicability of 
these rules differ with respect to the size of the unit (megawatts 
electric (MWe) or British thermal unit per hour (Btu/hr)) they 
regulate, the boiler/furnace technology they employ, or the portion of 
their electrical output (if any) for sale to any utility power 
distribution systems.
    Any combustion unit that produces steam to serve a generator that 
produces electricity exclusively for industrial, commercial, or 
institutional purposes is considered an IB unit. A fossil fuel-fired 
combustion unit that serves a generator that produces electricity for 
sale is not considered to be a Utility Unit under the final rule if its 
size is less than or equal to 25 MWe. Also, a cogeneration facility 
that sells electricity to any utility power distribution system equal 
to more than one-third of their potential electric output capacity and 
more than 25 MWe during any portion of a year is considered to be an 
electric utility steam generating unit.
    Because of the similarities in the design and operational 
characteristics of the units that would be regulated by the different 
combustion rules, there are situations where coal-fired units 
potentially could be subject to multiple rules. An example of this 
situation would be cogeneration units that are covered under the 
proposed IB rule, potentially meeting the definition of a Utility Unit, 
and vice versa. This might occur where a decision is made to increase/
decrease the proportion of production output being supplied to the 
electric utility grid, thus causing the unit to exceed the IB/electric 
utility cogeneration criteria (i.e. greater than one-third of its 
potential output capacity and greater than 25 MWe). As discussed below, 
EPA has clarified the definitions and applicability provisions to 
lessen any confusion as to which rule a unit may be subject to.

II. Revision of Regulatory Finding on the Emissions of Hazardous Air 
Pollutants from Utility Units

    In a separately published Federal Register action (70 FR 15994; 
March 29, 2005), EPA revised the regulatory finding that it issued in 
December 2000 pursuant to CAA section 112(n)(1)(A), and based on that 
revision, removed coal- and oil-fired electric utility steam generating 
units (coal- and oil-fired Utility Units) from the CAA section 112(c) 
source category list. Section 112(n)(1)(A) of the CAA is the threshold 
statutory provision underlying the action. That provision requires EPA 
to conduct a study to examine the hazards to public health that are 
reasonably anticipated to occur as the result of HAP emissions from 
Utility Units after imposition of the requirements of the CAA. The 
provision also provides that EPA shall regulate Utility Units under CAA 
section 112, but only if the Administrator determines that such 
regulation is both appropriate and necessary considering, among other 
things, the results of the study. EPA completed the Utility Study in 
1998, and in December 2000 found that it was appropriate and necessary 
to regulate coal- and oil-fired Utility Units under CAA section 112. 
That December 2000 finding focused primarily on Hg emissions from coal-
fired Utility Units. In light of the finding, EPA in December 2000 
announced its decision to list coal- and oil-fired Utility Units on the 
CAA section 112(c) list of regulated source categories. In January 
2004, EPA proposed revising the December 2000 appropriate and necessary 
finding and, based on that revision, removing coal- and oil-fired 
Utility Units from the CAA section 112(c) list.
    By a separately published Federal Register action (70 FR 15994; 
March 29, 2005), we revised the December 2000 appropriate and necessary 
finding and concluded that it is neither appropriate nor necessary to 
regulate coal- and oil-fired Utility Units under CAA section 112. We 
took this action because we now believe that the December 2000 finding 
lacked foundation and because recent information demonstrates that it 
is not appropriate or necessary to regulate coal- and oil-fired Utility 
Units under CAA section 112. Based solely on the revised finding, we 
are removing coal- and oil-fired Utility Units from the CAA section 
112(c) list. The reasons supporting today's action are described in 
detail in the separately published Federal Register notice (70 FR 
15994; March 29, 2005).
    EPA revised its December 2000 determination and removed coal- and 
oil-fired Utility Units from the CAA section 112(c) source category 
list because we have concluded that utility HAP emissions remaining 
after implementation of other requirements of the CAA, including in 
particular the CAIR, do not cause hazards to public health that would 
warrant regulation under CAA section 112.
    The HAP of greatest concern from coal-fired utilities is Hg. 
Although we believe that after implementation of CAIR, remaining 
utility emissions will not pose hazards to public health, we do believe 
that it is appropriate to establish national, uniform Hg emission 
standards for new and modified coal-fired utilities, as defined 
elsewhere in this preamble. Effective controls have been adequately 
demonstrated to reduce utility emissions; such reductions will further 
the goal of reducing the domestic and global Hg pool.
    Under the structure of the CAA, once we establish NSPS for new 
sources under section 111(b), we must, with respect to designated 
pollutants, establish 111(d) standards for existing sources. 
Specifically, section 111(d) provides that the Administrator ``shall 
prescribe regulations which establish a procedure under which each 
State shall submit * * * a plan which establishes standards of 
performance for any existing source for any air pollutant * * * to 
which a standard of performance under this section would apply if such 
existing source were a new source.'' Thus, because we deem it 
appropriate to establish NSPS for Hg emissions from new sources, we are 
obligated to establish NSPS Hg standards for existing sources as well.

III. Summary of the Final Rule Amendments

A. Who is subject to the final rule?

    EPA is finalizing applicability provisions for 40 CFR part 60, 
subparts Da and HHHH that are consistent with historical applicability 
and definition determinations under the CAA section 111 and Acid Rain 
programs. EPA realizes that these definitions are somewhat different 
because of differences in the underlying statutory authority. EPA 
believes that it is appropriate to finalize the applicability and 
definitions of the revised subpart Da NSPS consistent with the 
historical interpretations. Similarly, EPA believes that it is 
appropriate to finalize the applicability and definitions of subpart 
HHHH consistent with those of the Acid Rain and CAIR programs because 
of the similarities in their trading regimes.
    The 40 CFR part 60, subpart Da NSPS apply to Utility Units capable 
of firing more than 73 megawatts (MW) (250 million Btu/hr; MMBtu/hr) 
heat input of fossil fuel. The current NSPS also apply to industrial 
cogeneration facilities that sell more than 25 MW of electrical output 
and more than one-third of their potential output capacity to any 
utility power distribution system. Utility Units subject to revised 
subpart Da are also

[[Page 28610]]

subject to 40 CFR part 60, subpart HHHH.
    The following units in a State shall be Hg Budget units (i.e., 
units that are subject to the Hg Budget Trading Program), and any 
source that includes one or more such units shall be a Hg Budget 
source, subject to the requirements of subpart HHHH:
    (a) Except as provided in paragraph (b), a stationary, fossil fuel-
fired boiler or stationary, fossil fuel-fired combustion turbine 
serving at any time, since the start-up of a unit's combustion chamber, 
a generator with nameplate capacity of more than 25 MWe producing 
electricity for sale.
    (b) For a unit that qualifies as a cogeneration unit starting on 
the date the unit first produces electricity, a cogeneration unit 
serving at any time a generator with nameplate capacity of more than 25 
MWe and supplying in any calendar year more than one-third of the 
unit's potential electric output capacity or 219,000 MWh, whichever is 
greater, to any utility power distribution system for sale. If a unit 
qualifies as a cogeneration unit starting on the date the unit first 
produces electricity but subsequently no longer qualifies as a 
cogeneration unit, the unit shall be subject to paragraph (a) of this 
section starting on the day on which the unit first no longer qualifies 
as a cogeneration unit.
    The Hg provisions of 40 CFR part 60, subparts Da and HHHH apply 
only to coal-fired Utility Units (i.e., units where any amount of coal 
or coal-derived fuel is used at any time). This is similar to the 
definition that is used in the Acid Rain Program to identify coal-fired 
units.

B. What are the primary sources of emissions, and what are the 
emissions?

    The final rule amendments add Hg to the list of pollutants covered 
under 40 CFR part 60, subpart Da, by establishing emission limits for 
new sources and guidelines for existing sources. New sources (and 
existing subpart Da facilities), however, remain subject to the 
applicable existing subpart Da emission limits for NOX, 
SO2, and PM.

C. What is the affected source?

    Only those coal-fired Utility Units for which construction, 
modification, or reconstruction is commenced after January 30, 2004, 
will be affected by the new-source provisions of the final rule 
amendments under CAA section 111(b). Coal-fired Utility Units existing 
on January 30, 2004, will be affected facilities for purposes of the 
CAA section 111(d) guidelines finalized in the final rule.

D. What are the emission limitations and work practice standards?

    The following standards of performance for Hg are being finalized 
in the final rule for new coal-fired 40 CFR part 60, subpart Da units:

Bituminous units: 0.0026 nanograms per joule (ng/J) (21 x 
10-6 pounds per megawatt-hour (lb/MWh));
Subbituminous units:
    Wet FGD--0.0053 ng/J (42 x 10-6 lb/MWh);
    Dry FGD--0.0098 ng/J (78 x 10-6 lb/MWh);
Lignite units: 0.0183 ng/J (145 x 10-6 lb/MWh);
Coal refuse units: 0.00018 ng/J (1.4 x 10-6 lb/MWh);
Integrated gasification combined cycle (IGCC) units: 0.0025 ng/J (20 x 
10-6 lb/MWh).
    All of these standards are based on gross energy output.

    In addition, to complying with these standards, new units, along 
with existing coal-fired Utility Units will be subject to the cap-and-
trade provisions being finalized in the final rule. The specifics of 
the cap are described below.
    Compliance with the final standards of performance for Hg will be 
on a 12-month rolling average basis, as explained below. This 
compliance period is appropriate given the nature of the health hazard 
presented by Hg.

E. What are the performance testing, initial compliance, and continuous 
compliance requirements?

    Under 40 CFR part 60, subpart Da, new or reconstructed units must 
commence their initial performance test by the applicable date in 40 
CFR 60.8(a). Because compliance with the Hg emission limits in 40 CFR 
60.45a is on a 12-month rolling average basis, the initial performance 
test consists of 12 months of data collection with certified continuous 
monitoring systems, to determine the average Hg emission rate. New and 
existing units under 40 CFR part 60, subpart HHHH must certify the 
required continuous monitoring systems and begin reporting Hg mass 
emissions data by the applicable compliance date in 40 CFR 60.4170(b).
    Under 40 CFR 60.49a(s), the owner/operator is required to prepare a 
unit-specific monitoring plan and submit the plan to the Administrator 
for approval, no less than 45 days before commencing the certification 
tests of the continuous monitoring systems. The final rule amendments 
require that the plan address certain aspects with regard to the 
monitoring system; installation, performance and equipment 
specifications; performance evaluations; operation and maintenance 
procedures; quality assurance (QA) techniques; and recordkeeping and 
reporting procedures. The final amendments require all continuous 
monitoring systems to be certified prior to the commencement of the 
initial performance test.
    Mercury Emission Limits. Compliance with the final standard of 
performance for Hg will be determined based on a rolling 12-month 
average calculation. The rolling average is weighted according to the 
number of hours of valid Hg emissions data collected each month, unless 
insufficient valid data are collected in the month, as explained below. 
The Hg emissions are determined by continuously collecting Hg emission 
data from each affected unit by installing and operating a continuous 
emission monitoring system (CEMS) or an appropriate long-term method 
(e.g., sorbent trap) that can collect an uninterrupted, continuous 
sample of the Hg in the flue gases emitted from the unit. The final 
rule amendments will allow the owner/operator to use any CEMS that 
meets the requirements in Performance Specification 12A (PS-12A), 
``Specifications and Test Procedures for Total Vapor-phase Mercury 
Continuous Monitoring Systems in Stationary Sources.'' Alternatively, a 
Hg concentration CEMS that meets the requirements of 40 CFR part 75, or 
a sorbent trap monitoring system that meets the requirements of 40 CFR 
75.15 and 40 CFR part 75, appendix K, may be used. Note that EPA has 
revised and renamed proposed Method 324, ``Determination of Vapor Phase 
Flue Gas Mercury Emissions from Stationary Sources Using Dry Sorbent 
Trap Sampling'' as 40 CFR part 75, appendix K).
    For on-going quality control (QC) of the Hg CEMS, the final rule 
requires the calibration drift and quarterly accuracy assessment 
procedures in 40 CFR part 60, appendix F, to be implemented. The 
quarterly accuracy tests consist of a relative accuracy test audit 
(RATA) and three measurement error tests (as described in PS 12A), 
using mercuric chloride (HgCl2) standards. In lieu of 
implementing the 40 CFR part 60, appendix F procedures, the owner or 
operator may QA the data from the Hg CEMS according to 40 CFR part 75, 
appendix B. For sorbent trap monitoring systems, and annual RATA is 
required, and the on-going QA procedures of 40 CFR part 75, appendix K, 
must be met.
    The final rule requires valid Hg mass emissions data to be obtained 
for a minimum of 75 percent of the unit operating hours in each month. 
If this

[[Page 28611]]

requirement is not met, the Hg data for the month are discarded. In 
each 12-month cycle, if there are any months in which the data capture 
requirement is not met, data substitution is required. For the first 
such occurrence, the mean Hg emission rate for the last 12 months is 
reported, and for any subsequent occurrences, the maximum emission rate 
from the past 12 months is reported. For any month in which a 
substitute Hg emission rate is reported, the substitute emission rate 
is weighted according to the number of unit operating hours in that 
month when the 12-month rolling average is calculated.
    For new cogeneration units, steam is also generated for process 
use. The energy content of this process steam must also be considered 
in determining compliance with the output-based standard. Therefore, 
the owner/operator of a new cogeneration unit will be required to 
calculate emission rates based on electrical output to the grid plus 
half the equivalent electrical output energy in the unit's process 
steam. The procedure for determining these Hg emission rates is 
described in 40 CFR 60.50a(g), and is consistent with those currently 
used in 40 CFR part 60, subpart Da.
    The owner/operator of a new coal-fired unit that burns a blend of 
fuels will develop a unit-specific Hg emission limitation; the unit-
specific Hg emission rate will be used for the portion of the 
compliance period in which the unit burned the blend of fuels. The 
procedure for determining the emission limitations is outlined in 40 
CFR 60.45a(a)(5)(i). The owner/operator of an existing coal-fired unit 
that burns a blend of fuels will have to meet the limitations 
applicable under its unit-specific Hg allocation as outlined elsewhere 
in the final rule.

F. What are the notification, recordkeeping, and reporting 
requirements?

    The final rule requires the owner or operator to maintain records 
of all information needed to demonstrate compliance with the applicable 
Hg emission limit, including the results of performance tests, data 
from the continuous monitoring systems, fuel analyses, calculations 
used to assess compliance, and any other information specified in 40 
CFR 60.7 (General Provisions).
    Mercury compliance reports are required semiannually, under 40 CFR 
60.51. Each compliance report must include the following information 
for each month of the reporting period: (1) The number of unit 
operating hours; (2) the number of unit operating hours with valid Hg 
emissions data; (3) the calculated monthly Hg emission rate; (4) the 
number of hours (if any) excluded from the emission calculations due to 
startup, shutdown and malfunction; (5) the 12-month rolling average Hg 
emission rate; and (6) the 40 CFR part 60, appendix F data assessment 
report (DAR), or equivalent summary of QA test results if 40 CFR part 
75 QA procedures are implemented.

IV. Significant Comments and Changes Since Proposal

A. Why is EPA not taking final action to regulate Ni emissions from 
oil-fired units?

    In the January 30, 2004 NPR, EPA proposed to regulate Ni emissions 
from oil-fired units based on information collected and reported in the 
Utility Study. During the ensuing public comment period on the January 
30, 2004 NPR, the March 2004 SNPR, and the December 2004 NODA, EPA 
received new information indicating that there were fewer oil-fired 
units in operation and that Ni emissions had diminished since the 
Utility Study. Accordingly, in the final rule, EPA is not taking final 
action on the proposal to regulate Ni emissions from oil-fired units.

B. How did EPA select the regulatory approach for coal-fired units for 
the final rule?

1. Applicability
    EPA is maintaining the discrete applicability definitions of 
``electric utility steam generating unit'' that have historically been 
used under the CAA section 111 NSPS and the CAA section 401 Acid Rain 
programs.
    As defined in 40 CFR 60.41a, an ``electric utility steam generating 
unit'' means

any steam electric generating unit that is constructed for the 
purpose of supplying more than one-third of its potential electric 
output capacity and more than 25 MW electrical output to any utility 
power distribution system for sale. Any steam supplied to a steam 
distribution system for the purpose of providing steam to a steam-
electric generator that would produce electrical energy for sale is 
also considered in determining the electrical energy output capacity 
of the affected facility.

    In the NPR, EPA proposed to modify the definition of an ``electric 
utility steam generating unit'' to mean

any fossil fuel-fired combustion unit of more than 25 megawatts 
electric (MWe) that serves a generator that produces electricity for 
sale. A unit that cogenerates steam and electricity and supplies 
more than one-third of its potential electric output capacity and 
more than 25 MWe output to any utility power distribution system for 
sale is also considered an electric utility steam generating unit.

    This proposed change in the definition was made as a part of the 
proposed CAA section 112 rulemaking alternative; however, it was EPA's 
intent that this change also apply to the CAA section 111 rulemaking 
alternative and, therefore, EPA is finalizing it as part of the section 
111 rule today.
    Only Utility Units that are fired by coal in any amount, or 
combinations of fuels that include coal, are subject to the final rule. 
Integrated gasification combined cycle units are also subject to the 
final rule.
    An affected source under NSPS is the equipment or collection of 
equipment to which the NSPS rule limitations or control technology is 
applicable. For the final rule, the affected source will be the group 
of coal-fired units at a facility (a contiguous plant site where one or 
more Utility Units are located). Each unit will consist of the 
combination of a furnace firing a boiler used to produce steam, which 
is in turn used for a steam-electric generator that produces electrical 
energy for sale. This definition of affected source will include a wide 
range of regulated units with varying process configurations and 
emission profile characteristics.
    EPA received comment requesting clarification of the applicability 
definition relating to whether a unit would be classified as a Utility 
Unit or an IB. For the purposes of 40 CFR part 60, subpart Da, EPA 
believes that the definition being finalized today in 40 CFR part 60, 
subpart Da clearly defines two categories of new sources--Utility Units 
and non-Utility Units (which could include IB units, etc.). That is, 
all three conditions must be met in order for a unit to be classified 
as a Utility Unit: (1) Must sell more than 25 MWe to any utility power 
distribution system; (2) any individual boiler must be capable of 
combusting more than 73 MW (250 MMBtu/hr) heat input (which equates to 
25 MWe on an output basis); and (3) if the unit is a cogeneration unit, 
it must sell more than one-third of its potential electric output 
capacity. The Agency's historical interpretation of the 40 CFR part 60, 
subpart Da definition has been that a boiler meeting the capacity 
definition (i.e., greater than 250 MMBtu/hr) but connected to an 
electrical generator with a generation capacity of 25 MWe or less would 
still be classified as an ``electric utility steam generating unit'' 
under 40 CFR part 60, subpart Da. However, one or more new boilers with 
heat input capacities less than 250 MMBtu/hr each but connected to an 
electrical generator with a

[[Page 28612]]

generation capacity of greater than 25 MWe would not be considered 
Utility Units under 40 CFR part 60, subpart Da because they 
individually do not meet the definition (they would be considered IB).
    Under the final 40 CFR part 60, subpart HHHH rule, EPA is 
continuing the definition of an Utility Unit used in the Acid Rain and 
CAIR trading programs. A coal-fired Utility Unit is a unit serving at 
any time, since the start-up of a unit's combustion chamber, a 
generator with nameplate capacity of more than 25 MWe producing 
electricity for sale. For a unit that qualifies as a cogeneration unit 
during the 12-month period starting on the date the unit first produces 
electricity and continues to qualify as a cogeneration unit, a 
cogeneration unit serving at any time a generator with nameplate 
capacity of more than 25 MWe and supplying in any calendar year more 
than one-third of the unit's potential electric output capacity or 
219,000 MWh, whichever is greater, to any utility power distribution 
system for sale. If a unit qualifies as a cogeneration unit during the 
12-month period starting on the date the unit first produces 
electricity but subsequently no longer qualifies as a cogeneration 
unit, the unit shall be subject to paragraph (a) of this definition 
starting on the day on which the unit first no longer qualifies as a 
cogeneration unit. These criteria are similar to the definition in the 
NPR and SNPR with the clarification that the criteria be determined on 
an annual basis. These criteria are the same used in the CAIR and are 
similar to those used in the Acid Rain Program to determine whether a 
cogeneration unit is a Utility Unit and the NOX SIP Call to 
determine whether a cogeneration unit is an Utility Unit or a non-
Utility Unit.
2. Subcategorization
    Under CAA section 111(b)(2), the Administrator has the discretion 
to ``* * * distinguish among classes, types, and sizes within 
categories of new sources * * *'' in establishing standards when 
differences between given types of sources within a category lead to 
corresponding differences in the nature of emissions and the technical 
feasibility of applying emission control techniques. At proposal, EPA 
examined a number of options for subcategorizing coal-fired Utility 
Units, including by coal rank and by process type. Based on the 
information available, EPA proposed to use five subcategories for 
establishing Hg limits based on a combination of coal rank and process 
type in the final rule (bituminous coal, subbituminous coal, lignite 
coal, coal refuse, and IGCC). EPA is today finalizing these five 
subcategories.
    EPA received numerous comments both in support of and in opposition 
to the proposed subcategorization approach for both new and existing 
Utility Units. Those commenters opposed to the proposed approach 
suggested several alternative approaches, including no 
subcategorization, combining bituminous and subbituminous coal ranks in 
one subcategory, a separate subcategory for Gulf Coast lignite, and a 
separate subcategory for fluidized bed combustion (FBC) units, among 
others. Other commenters indicated that any subcategorization approach 
should be ``fuel neutral,'' i.e., not disadvantage any rank of coal or 
lead to fuel switching, and/or should not result in the loss of 
viability of any coal rank.
    Those commenters opposed to subcategorization generally argued that 
subcategorization can only be done on three criteria: Class, type, and 
size of sources and contended that the fact that coal rank is one of 
the characteristics of a coal-fired boiler does not mean it can be used 
for subcategorization. The commenters stated that EPA's reliance on 
coal rank is misplaced because many coal-fired units blend or fire two 
or more ranks of coal in the same boiler, and EPA itself states that 
coal blending is possible and not uncommon. The commenters stated that 
EPA had also provided unsupported claims that fuel switching would 
require significant modification or retooling of a unit. The commenters 
cited case law to support their contention that EPA's proposed 
subcategorization is not permitted and stated that EPA's justification 
for rejecting a no subcategorization option is factually and legally 
indefensible.
    A similar argument was presented by those commenters suggesting a 
single subcategory for bituminous and subbituminous coals. That is, 
given the extent of coal blending, particularly with respect to these 
two coal ranks, a single subcategory was appropriate. Further, the 
commenters argued that the proposed emission limits for the two 
subcategories disadvantaged bituminous coal.
    Commenters representing producers and users of Gulf Coast lignite 
suggested that a separate subcategory should be established for this 
coal because of its significantly higher Hg content, even when compared 
to Fort Union lignite. Gulf Coast lignite, therefore, is more difficult 
to control.
    Several commenters suggested that the American Society of Testing 
and Materials (ASTM) classification methodology for ranking coals is an 
inappropriate basis upon which to base subcategorization. This claim 
was made primarily because of the overlaps in the ASTM classification 
methodology and the fact that some Western coal seams are alleged to 
provide both bituminous and subbituminous coal ranks. Reliance on the 
ASTM methodology would create problems for the users of this coal in 
determining which subcategory they were in.
    Several commenters indicated that a separate subcategory for FBC 
units, is appropriate because FBC units use a fundamentally different 
combustion process than pulverized-coal (PC) units, making them a 
different type of source.
    Commenters concerned that the nation's fuel supply not be 
jeopardized stated that the final rule must be consistent with the need 
for reliable and affordable electric power, including affordable use of 
all coal ranks and options for efficient on-site power generation such 
as combined heat and power (CHP). The commenters stated that the final 
rule must facilitate--not discourage--the availability of an adequate 
and diverse fuel supply for the future, including all coal ranks, 
natural gas, nuclear energy, hydroelectric, and renewable sources. 
According to several commenters, the final rule must not aggravate the 
already precarious natural gas supply which is currently inadequate.
    EPA continues to believe that it has the statutory authority to 
subcategorize based on coal rank and process type, as appropriate for a 
given standard. As initially structured, 40 CFR part 60, subpart Da 
subcategorized based on the sulfur content of the coal (essentially 
based on coal rank) for SO2 emission limits and based on 
coal rank for NOX emission limits. This approach was 
selected because of the differences in the relative ability of the 
respective control technologies to effect emissions reductions on the 
various coal ranks. Although EPA has recently proposed (February 28, 
2005; 70 FR 9706) to change the format of the NOX emission 
limits and to establish common SO2 emission limits 
regardless of coal rank, we believe that the conditions existing when 
we proposed 40 CFR 60, subpart Da in 1978 (e.g., the inability of the 
technologies to control SO2 and NOX equally from 
all coal ranks) still exist for Hg and justify the use of 
subcategorization by coal rank for the Hg emission limits. At some 
point in the future, the performance of control technologies on Hg 
emissions could advance to the point that the rank of coal being fired 
is irrelevant to the level of Hg control that can be achieved (similar 
to the point reached by controls

[[Page 28613]]

for SO2 and NOX emissions). If that occurs, EPA 
may consider adjusting the approach to Hg controls appropriately.
    EPA believes that there are sufficient differences in the design 
and operation of utility boilers utilizing the different coal ranks to 
justify subcategorization by major coal rank. As documented in the 
record, utility boilers vary in size depending on the rank of coal 
burned (i.e., boilers designed to fire lignite coal are larger than 
those designed to fire subbituminous coal which, in turn, are larger 
than those designed to fire bituminous coal). Boilers designed to burn 
one fuel (e.g., lignite) cannot randomly or arbitrarily change fuels 
without extensive testing and tuning of both the boiler and the control 
device. Further, if a different rank of coal is burned in a boiler 
designed for another rank, either in total or through blending, the 
practice is only done with ranks that have similar characteristics to 
those for which the boiler was originally designed. To do otherwise 
entails a loss of efficiency and/or significant increases in 
maintenance costs. That is, the ASTM classification system is 
structured on a continuum based on a number of characteristics (e.g., 
heat content or Btu value, fixed carbon, volatile matter, agglomerating 
vs. non-agglomerating) and provides basic information regarding 
combustion characteristics. Because more than one characteristic is 
used, the possibility exists for numerous situations where a coal could 
be ``classified'' in one rank based on one characteristic but in 
another rank based on another characteristic. Ranking is based on an 
evaluation of all characteristics. Therefore, it is possible that (for 
example) a non-agglomerating subbituminous coal with a heating value of 
8,300 Btu/lb (ASTM classification III.3--``Subbituminous C coal'') 
could be co-fired with, or substituted for, a non-agglomerating lignite 
coal with heating value of 8,300 Btu/lb (ASTM classification IV.1--
``Lignite A coal''). This does not, however, mean that it is possible 
for a boiler designed to burn the Lignite A coal to burn an 
agglomerating coal with a heating value of 13,000 Btu/lb (e.g., ASTM 
classification II.5--``High volatile C bituminous coal''). Further, it 
does not mean that the substituted coal would exhibit the same 
``controllability'' with respect to emissions reductions as the 
original coal, regardless of its compatibility with the boiler. The 
fact that a number of Utility Units co-fire different ranks of coal 
does not negate the overall differences in the ranks that preclude 
universal coal rank switching, particularly when the design coal ranks 
are not adjacent on the ASTM classification continuum.
    Although other classification approaches have been suggested, the 
ASTM classification system remains the one most recognized and utilized 
by the industry and the one which the EPA believes is most suitable for 
use as a basis for subcategorization. Further, EPA is perplexed by the 
comments indicating that Utility Units do not know the coal rank that 
they are firing and would incur additional costs to determine this for 
the purpose of establishing their subcategory. Electric utilities are 
currently required by law to report to the U.S. Department of Energy, 
Energy Information Administration (DOE/EIA) on one or more of six 
different forms, the rank of coal burned in each Utility Unit. EPA is 
not suggesting that these utilities do anything different in 
establishing their subcategory and respective emission limit. Utility 
Units that blend coals from different ranks would need to follow the 
specified procedures for establishing the appropriate emission limit 
for blended coals. EPA, therefore, believes that, at this time, coal 
rank is an appropriate and justifiable basis on which to subcategorize 
for the purposes of the final rule.
    EPA continues to believe that there is insufficient evidence 
available to justify separate subcategories for Gulf Coast and Fort 
Union lignites. The reanalysis of the data in support of the revised 
NSPS Hg emission limits, discussed later in this preamble, incorporated 
data from units firing both types of lignite, further lessening the 
necessity of additional subcategorization. EPA will continue to 
evaluate the Hg emission data that become available, including that 
generated through the studies on emerging Hg control technologies by 
the DOE, and reassess issues of further subcategorizing lignites during 
the normal 8-year NSPS review cycle.
    With regard to FBC units, EPA agrees that such units operate and 
are designed differently than conventional PC boilers. However, with 
the exception of FBC units firing coal refuse, there was no clear 
indication from the available data that such units influenced the 
ultimate Hg control. That is, in some cases, FBC units were better than 
most with respect to their Hg emissions; in other cases, FBC units were 
worse than most. Therefore, EPA concluded that it was the coal rank, 
rather than the process type (e.g., FBC, PC) that should govern in any 
determination relating to subcategorization.
    EPA's modeling has shown minimal coal switching as a result of the 
final CAMR and CAIR actions. We believe that this rebuts the 
commenters' suggestions that the final rule will cause one or another 
coal rank to be ``advantaged'' or ``disadvantaged'' with respect to 
other coal ranks. Further, we do not believe that the final rule will 
have a negative impact on the nation's energy security, employment 
rates, or energy reliability.
    New units designed to burn bituminous coals will still not be able 
to burn lignite coals (for example) and, thus, EPA believes that the 
need for subcategorization remains, even for new units.

C. How did EPA determine the NSPS under CAA section 111(b) for the 
final rule?

1. Criteria Under CAA Section 111
    CAA section 111 creates a program for the establishment of 
``standards of performance.'' A ``standard of performance'' is ``a 
standard for emissions of air pollutants which reflects the degree of 
emission limitation achievable through the application of the best 
system of emission reduction, which (taking into the cost of achieving 
such reduction, any non-air quality health and environmental impacts 
and energy requirements), the Administrator determines has been 
adequately demonstrated.'' (See CAA section 111(a)(1).)
    For new sources, EPA must first establish a list of stationary 
source categories which the Administrator has determined ``causes, or 
contributes significantly to, air pollution which may reasonably be 
anticipated to endanger public health or welfare.'' (See CAA section 
111(b)(1)(A).) EPA must then set Federal standards of performance for 
new sources within each listed source category. (See CAA section 
111(b)(1)(B).) Like CAA section 112(d) standards, the standards for new 
sources under section 111(b) apply nationally and are effective upon 
promulgation. (See CAA section 111(b)(1)(B).)
    Section 111(b) covers any category of sources that causes or 
contributes to air pollution that may reasonably be anticipated to 
endanger public health or welfare and provides EPA authority to 
regulate new sources of such air pollution. EPA included Utility Units 
on the section 111(b) list of stationary sources in 1979 and has issued 
final standards of performance for new Utility Units for pollutants, 
such as NOX, PM, and SO2. (See 44 FR 33580; June 
11, 1979; 40 CFR part 60, subpart Da.) Nothing in the language of 
section 111(b) precludes EPA from issuing additional standards of 
performance for

[[Page 28614]]

other pollutants, including HAP, emitted from new Utility Units. 
Moreover, nothing in CAA section 112(n)(1)(A) suggests that Congress 
sought to preclude EPA from regulating Utility Units under CAA section 
111(b). Indeed, section 112(n)(1)(A) provides to the contrary, in that 
it calls for an analysis of utility HAP emissions ``after imposition of 
the requirements'' of the CAA, which we have reasonably interpreted to 
mean those authorities that EPA reasonably anticipates will be 
implemented and will reduce utility HAP emissions.
2. Mercury Control Technologies
    At proposal, EPA stated that available information indicates that 
Hg emissions from coal-fired Utility Units are minimized in some cases 
through the use of PM controls (e.g., fabric filter or electrostatic 
precipitator (ESP)) coupled with a flue gas desulfurization (FGD) 
system. For bituminous-fired units, use of a selective catalytic 
reduction (SCR) or selective non-catalytic reduction (SNCR) system in 
conjunction with one of these systems may further enhance Hg removal. 
This SCR-induced enhanced Hg removal appears to be absent for 
subbituminous- and lignite-fired units.
    The EPA believes the best potential way of reducing Hg emissions 
from IGCC units, on the other hand, is to remove Hg from the synthetic 
gas (syngas) before combustion. An existing industrial IGCC unit has 
demonstrated a process, using sulfur-impregnated activated carbon (AC) 
beds, that has proven to yield 90 to 95 percent Hg removal from the 
coal syngas. Available information indicates that this technology could 
be adapted to the electric utility IGCC units, and EPA believes this to 
be a viable option for new IGCC units.
    In selecting a regulatory approach for formulating emission 
standards to limit Hg emissions from new coal-fired Utility Units, the 
performance of the control technologies discussed on Hg above were 
considered. After considering the available information, EPA has 
determined that the technical basis (i.e., the best system of emission 
reduction which the Administrator determines has been adequately 
demonstrated, or best demonstrated technology, BDT) selected for 
establishing Hg emission limits for new sources is the use of effective 
PM controls (e.g., fabric filter or ESP) and wet or dry FGD systems on 
subbituminous-, lignite-, and coal refuse-fired units; effective PM 
controls, wet or dry FGD systems, and SCR or SNCR on bituminous-fired 
units; and AC beds for IGCC units.
    EPA received several public comments that disagreed with the EPA's 
conclusion at proposal that Hg-specific controls for Utility Units, 
including activated carbon injection (ACI), will not be commercially 
available on a wide scale until 2010 or later. Arguments stated by 
these commenters included the following assertions: (a) Mercury control 
technologies are available now and EPA disregarded studies on emerging 
Hg control technologies by the DOE, the industry, and others. (b) The 
EPA's own numbers and other studies indicate that coal-fired plants can 
achieve 90 percent reduction regardless of the type of plant or coal. 
(c) Field testing o