sources established under section 111(b) and standards for existing
sources established by a state plan under section 111(d) are both
``standards of performance,'' it is the EPA's responsibility to
determine the BSER for designated facilities for standards developed
under both CAA section 111(b) for new sources and section 111(d) for
existing sources.\150\ In making this determination, the EPA identifies
all ``adequately demonstrated'' ``system[s] of emission reduction'' for
a particular source category and then evaluates those systems to
determine which is the ``best,'' \151\ while ``taking into account''
the factors of ``cost . . . non-air quality health and environmental
impact and energy requirements.'' \152\ Because CAA section 111 does
not set forth the weight that should be assigned to each of these
factors, courts have granted the Agency a great degree of discretion in
balancing them.\153\
---------------------------------------------------------------------------

    \149\ CAA section 110 governs state implementation plans, or
SIPs, which states develop and submit for EPA approval and which are
used to ensure attainment and maintenance of the National Ambient
Air Quality Standards (NAAQS) for criteria pollutants.
    \150\ See also 40 CFR 60.22a. However, while the BSER underlying
both new- and existing-source performance standards is determined by
the EPA, the performance standards for new sources are directly
established by the EPA under section 111(b), whereas states
establish performance standards (applying the BSER) for existing
sources in their jurisdiction in their state plans under section
111(d), and Congress has expressly required that EPA permit states,
in establishing performance standards for existing sources, to take
into account the remaining useful life of the source and other
source-specific factors. See 42 U.S.C. 7411(d)(1).
    \151\ The D.C. Circuit recognizes that the EPA's evaluation of
the ``best'' system must also include ``the amount of air pollution
as a relevant factor to be weighed . . . .'' Sierra Club v. Costle,
657 F.2d 298, 326 (D.C. Cir. 1981). Additionally, a system cannot be
``best'' if it does more harm than good due to cross-media
environmental impacts. See Portland Cement, 486 F. 2d at 384; Sierra
Club, 657 F.2d at 331; see also Essex Chemical Corp., 486 F.2d 427,
439 (D.C. Cir. 1973) (remanding standard to consider solid waste
disposal implications of the BSER determination). Nevertheless, CAA
section 111 does not require the ``greatest degree of emission
control'' or ``mandate that the EPA set standards at the maximum
degree of pollution control technologically achievable.'' Sierra
Club, 657 F.2d at 330.
    \152\ The EPA may consider energy requirements on both a source-
specific basis and a sector-wide, region-wide or nationwide basis.
Considered on a source-specific basis, ``energy requirements''
entail, for example, the impact, if any, of the system of emission
reduction on the source's own energy needs. As discussed in this
document, a consideration of ``energy requirements'' informs the
EPA's judgment that repowering and refueling coal-fired facilities
to be fueled by natural gas is not appropriate for consideration as
BSER here.
    \153\ Lignite Energy, 198 F.3d 930, 933 (D.C. Cir. 1999).
---------------------------------------------------------------------------

    The CAA limits ``standards of performance'' to systems that can be
applied at and to a stationary source (i.e., as opposed to off-site
measures that are implemented by an owner or operator, such as
subsidizing lower-emitting sources) and that lead to continuous
emission reductions (i.e., are not intermittent control techniques).
Such systems include add-on controls and lower-emitting processes/
practices/designs that can be applied to a designated facility, i.e., a
building, structure, facility, or installation regulated under CAA
section 111.\154\ As discussed in section II of this preamble, this is
the only permissible interpretation of the scope of the EPA's authority
under CAA section 111. But this clear outer bound on the EPA's
authority leaves the Agency considerable room for interpretation and
policy choice within that scope in determining the BSER that has been
adequately demonstrated to address a particular source category's
emission of a given pollutant. Case law under CAA section 111(b)
explains that ``[a]n adequately demonstrated system is one which has
been shown to be reasonably reliable, reasonably efficient, and which
can reasonably be expected to serve the interests of pollution control
without becoming exorbitantly costly in an economic or environmental
way.'' \155\ While some of these cases suggest that ``[t]he
Administrator may make a projection based on existing technology,''
\156\ the D.C. Circuit has also

noted that ``there is inherent tension'' between considering a
particular control technique as both ``an emerging technology and an
adequately demonstrated technology.'' \157\ Nevertheless, the EPA
appears to ``have authority to hold the industry to a standard of
improved design and operational advances, so long as there is
substantial evidence that such improvements are feasible.'' \158\ The
essential question, therefore, is whether the BSER is ``available.''
\159\
---------------------------------------------------------------------------

    \154\ See section 111(a)(3) for definition of ``stationary
source.''
    \155\ Essex Chemical Corp., 486 F.2d 375, 433-34 (D.C. Cir.
1973).
    \156\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 391
(D.C. Cir. 1973).
    \157\ Sierra Club v. Costle, 657 F.2d 298, 341 n.157 (D.C.
Cir.1981); see also NRDC v. Thomas, 805 F.2d 410, n.30 (D.C. Cir.
1986) (suggesting that ``a standard cannot both require adequately
demonstrated technology and also be technology-forcing'').
    \158\ Sierra Club, 657 F.2d at 364. It is not clear whether
these cases would have applied the same technology-forcing
philosophy to the regulation of existing sources, as at least one
case noted that section 111 ``looks toward what may fairly be
projected for the regulated future, rather than the state of the art
at present, since it is addressed to standards for new plants--old
stationary source pollution being controlled through other
regulatory authority.'' Portland Cement, 486 F.2d at 391 (emphasis
added).
    \159\ See Portland Cement v. Ruckelshaus, 486 F.2d at 391.
---------------------------------------------------------------------------

    In considering the availability of different systems of emission
reduction, the ``EPA must examine the effects of technology on the
grand scale,'' because CAA section 111 standards are, after all, ``a
national standard with long-term effects.'' \160\ To that end, the
Agency must ``consider the representativeness for the industry as a
whole of the tested plants on which it relies. . . .'' \161\ A CAA
section 111 standard, therefore, ``cannot be based on a `crystal ball'
inquiry.'' \162\
---------------------------------------------------------------------------

    \160\ Id. at 330.
    \161\ Nat'l Lime Ass'n v. EPA, 627 F.2d 416, 432-33 (D.C. Cir.
1980).
    \162\ Essex Chemical Corp., 486 F.2d at 391.
---------------------------------------------------------------------------

    Whereas the EPA establishes performance standards for new sources
under CAA section 111(b), section 111(d) provides that states are
primarily responsible for regulating existing sources. This bifurcated
approach dovetails with testimony offered during development of the CAA
Amendments of 1970 (which established the section 111 program)--
specifically, Secretary Finch explained that ``existing stationary
sources of air pollution are so numerous and diverse that the problems
they pose can most efficiently be attacked by state and local
agencies.'' \163\ Indeed, Congress eventually made explicit the
requirement that the EPA allow states to take into account the
``remaining useful life'' of an existing source, ``among other
factors,'' when applying a standard of performance to any particular
source.\164\ Accordingly, the Agency's identification of the BSER is
based on what is ``adequately demonstrated'' and broadly achievable for
a source category across the country, while each state--which will be
more familiar with the operational and design characteristics of
actually existing sources within their borders--is responsible for
developing source-specific standards reflecting application of the
BSER.\165\ Indeed, Congress has expressly provided that the EPA must
permit states to take into consideration a source's remaining useful
life, among other factors, when applying a standard of performance to a
particular source.\166\
---------------------------------------------------------------------------

    \163\ Testimony of Robert Finch, Secretary of Health, Education,
and Welfare (which regulated air pollution prior to the
establishment of the EPA) in support of S. 3466/H.R. 15848, before
the House Subcommittee on Public Health and Welfare, H. Hearing (May
16, 1970), 1970 CAA Legis. Hist. at 1369.
    \164\ 42 U.S.C. 7411(d)(1).
    \165\ This approach is analogous to the NAAQS program: Where
``[e]ven with air quality standards being set nationally . . . the
steps needed to deal with existing stationary sources would
necessarily vary from one State to another and, within States, from
one area to another . . . .'' Id.
    \166\ 42 U.S.C. 7411(d)(1).
---------------------------------------------------------------------------

    In the ACE proposal, the EPA provided a discussion of the
identified systems of emission reduction and explained why certain
systems were eliminated from consideration at a preliminary state or
were otherwise determined not to be the ``best system.'' The EPA
received public comments that challenged or refuted the Agency's
evaluation of these systems of emission reduction. A discussion of
those reduction measures and a summary of significant public comments
are provided below.
    The EPA proposed that ``heat rate improvement'' (HRI, which may
also be referred to as ``efficiency improvement'') is the BSER for
existing coal-fired EGUs. In this action, after consideration of public
comments, the EPA is finalizing its proposed determination that HRI is
the BSER. The basis for the final determination and a summary of
significant public comments received on the proposed determination are
discussed below.
2. Heat Rate Improvement Is the BSER for Existing Coal-Fired EGUs
a. Background and BSER Determination
    Heat rate is a measure of efficiency that is commonly used in the
power sector. The heat rate is the amount of energy or fuel heat input
(typically measured in British thermal units, Btu) required to generate
a unit of electricity (typically measured in kilowatt-hours, kWh). The
lower an EGU's heat rate, the more efficiently it converts heat input
to electrical output. As a result, an EGU with a lower heat rate
consumes less fuel per kWh of electricity generated and, as a result,
emits lower amounts of CO2--and other air pollutants--per
kWh generated (as compared to a less efficient unit with a higher heat
rate). Heat rate data from existing coal-fired EGUs indicate that there
is potential for improvement across the source category.
    Heat rate improvement measures can be applied--and some measures
have already been applied--to all existing EGUs (supporting the
Agency's determination that HRI measures are the BSER). However, the
U.S. fleet of existing coal-fired EGUs is a diverse group of units with
unique individual characteristics that are spread across the
country.\167\ As a result, heat rates of existing coal-fired EGUs in
the U.S. vary substantially. Thus, even though the variation in heat
rates among EGUs with similar design characteristics, as well as year-
to-year variation in heat rate at individual EGUs, indicate that there
is potential for HRI that can improve CO2 emission
performance across the existing coal-fired EGU fleet, this potential
may vary considerably at the unit level--including because particular
units may not be able to employ certain HRI measures, or may have
already done so. Accordingly, the EPA identified several available
technologies and equipment upgrades, as well as best operating and
maintenance practices, that EGU owners or operators may apply to
improve an individual EGU's heat rate. The EPA referred to these HRI
technologies and techniques as ``candidate technologies'' and solicited
comment on their technical feasibility, applicability, performance, and
cost.
---------------------------------------------------------------------------

    \167\ For example, the current fleet of existing fossil fuel-
fired EGUs is quite diverse in terms of size, age, fuel type,
operation (e.g., baseload, cycling), boiler type, etc. Moreover,
geography and elevation, unit size, coal type, pollution controls,
cooling system, firing method, and utilization rate are just a few
of the parameters that can impact the overall efficiency and
performance of individual units.
---------------------------------------------------------------------------

    The EPA received numerous public comments, both supporting and
opposing, the proposed determination that HRI is the BSER. Many
commenters supported the proposed concept of a unit-specific, state-led
evaluation of HRI potential as a means of establishing a unit-specific
standard of performance. The commenters argued that it is not possible
to adopt uniform, nationally applicable standards of performance based
on implementation of particular HRI technologies because each
individual unit is subject to a unique combination of factors that can
affect the unit's heat rate and HRI potential, many of which are
geographically driven and outside the control of a

source. The EPA agrees with these commenters. As previously mentioned,
the U.S. fleet of existing coal-fired EGUs is diverse in terms of size,
vintage, fuel usage, design, geographic location, etc. The HRI
potential for each unit will be influenced by source-specific factors
such as the EGU's past and projected utilization rate, maintenance
history, and remaining useful life (among other factors). Therefore,
standards of performance must be established from a unit-level
evaluation of the application of the BSER and consideration of other
factors at the unit level. States are in the best position to make
those evaluations and to consider of other unit-specific factors, and
indeed CAA section 111(d)(1) directs EPA to permit states to take such
factors into consideration as they develop plans to establish
performance standards for existing sources within their jurisdiction.
    Other commenters opposed the proposed use of unit-specific HRI
plans because the commenters believe that this interpretation is
inconsistent with the legislative history and that this approach does
not enable significant emissions reductions. Some commenters said that
defining BSER in terms of operational efficiency (heat rate) is not
consistent with the understanding reflected in the EPA's historic
practice in all previous CAA section 111(d) rules, where the BSER was
determined based on a specific emission reduction technology. The EPA
disagrees with the contention. The EPA proposed that HRI through the
application of a specific set of emission reduction technologies
(discussed in more detail below) and operational practices is the BSER.
That approach is consistent with the direction given in the statute. It
is also an approach that recognizes the challenges of applying a single
specific emission reduction technology within such a diverse population
of designated facilities.
    After consideration of public comment, the EPA affirms its
determination that, as proposed, HRI is the BSER for existing coal-
fired EGUs.
b. The List of Candidate Technologies
    While a large number of HRI measures have been identified in a
variety of studies conducted by government agencies and outside
groups,\168\ some of those identified technologies have limited
applicability and many provide only negligible HRI. The EPA stated in
the proposal that it believed that requiring a state in developing its
plan to evaluate the applicability to each of its sources of the entire
list of potential HRI options--including those with limited
applicability and with negligible benefits--would be overly burdensome
to the states. Therefore, the EPA identified and proposed a list of the
``most impactful'' HRI technologies, equipment upgrades, and best
operating and maintenance practices that form the list of ``candidate
technologies'' constituting the BSER. The candidate technologies of the
BSER are listed in Table 1 below. Those technologies, equipment
upgrades, and best operating and maintenance practices were deemed to
be ``most impactful'' because they can be applied broadly and are
expected to provide significant HRI without limitations due to
geography, fuel type, etc. The EPA solicited comment on each of the
proposed candidate technologies and on whether any additional
technologies should be added to the list, and on whether there is
additional information that the EPA should be aware of and consider in
determining the BSER and establishing the candidate technologies for
HRI measures.
---------------------------------------------------------------------------

    \168\ See Table 3 in ANPRM, 82 FR 61515.
---------------------------------------------------------------------------

    The EPA received numerous public comments on the list of candidate
technologies. Some commenters stated that there are additional
available HRI technologies that should be added to the list of
candidate technologies, while many other commenters agreed that the
proposed list of ``candidate technologies'' is reasonable and should be
considered the core group for states to evaluate in establishing
standards of performance. Commenters agreed that the proposed list of
``candidate technologies'' focuses the states' standard-setting process
on those HRI measures with the greatest ability to impact
CO2 emissions. Commenters further stated that the EPA's
proposed candidate technology list will limit the burden on states by
eliminating the need to consider measures that would almost certainly
be rejected due to negligible emission reduction benefits,
disproportionate costs, or availability. However, commenters also noted
that there may be additional HRI opportunities available to a
significant number of designated facilities and that states should not
be required to limit their evaluations to just the ``candidate
technologies'' in establishing unit-specific standards of performance.
Some commenters suggested that the EPA establish a process whereby HRI
solutions can be added to the list of ``candidate technologies.''
    Commenters also stated that some of the equipment upgrades and
operating practices proposed as candidate technologies have the
potential to improve an EGU's net heat rate by reducing auxiliary load
but would have no impact on the unit's gross heat rate.\169\ Comments
regarding gross versus net heat rate, and gross- versus net-based
standards of performance, are discussed in more detail below in section
III.F.1.c of this preamble.
---------------------------------------------------------------------------

    \169\ The gross heat rate is the fuel heat input required to
generate a unit of electricity (typically presented in Btu/kWh-
gross). The net heat rate is the fuel heat input required to
generate a unit of electricity minus the electricity that is used to
power facility auxiliary equipment (typically presented in Btu/kWh-
net).
---------------------------------------------------------------------------

    The EPA considered the public comments on the BSER technologies and
believes that the proposed list still represents the most broadly
applicable and impactful collection of HRI measures. Therefore, the EPA
is, in this action, finalizing the proposed technologies, equipment
upgrades, and best operating and maintenance practices provided in
Table 1 of the proposal \170\ as the final list of ``candidate
technologies'' whose applicability to each designated facility within
their boundaries states must evaluate in establishing a standard of
performance for that source in their state plans under CAA section
111(d).
---------------------------------------------------------------------------

    \170\ See 83 FR 44757.
---------------------------------------------------------------------------

    The technologies and operating and maintenance practices listed and
described below are generally available and appropriate for all types
of EGUs. However, some existing EGUs will have already implemented some
of the listed HRI technologies, equipment upgrades, and operating and
maintenances practices. There will also be unit-specific physical or
cost considerations that will limit or prevent full implementation of
the listed HRI technologies and equipment upgrades. States will
consider these and other factors when establishing unit-level standards
of performance. The final list of ``candidate technologies''--with the
range of expected percent HRI--is provided below in Table 1.

                            Table 1--Summary of Most Impactful HRI Measures and Range of Their HRI Potential (%) by EGU Size
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                      <200 MW                       200-500 MW                        >500 MW
                       HRI Measure                       -----------------------------------------------------------------------------------------------
                                                                Min             Max             Min             Max             Min             Max
--------------------------------------------------------------------------------------------------------------------------------------------------------
Neural Network/Intelligent Sootblowers..................             0.5             1.4             0.3             1.0             0.3             0.9
Boiler Feed Pumps.......................................             0.2             0.5             0.2             0.5             0.2             0.5
Air Heater & Duct Leakage Control.......................             0.1             0.4             0.1             0.4             0.1             0.4
Variable Frequency Drives...............................             0.2             0.9             0.2             1.0             0.2             1.0
Blade Path Upgrade (Steam Turbine)......................             0.9             2.7             1.0             2.9             1.0             2.9
Redesign/Replace Economizer.............................             0.5             0.9             0.5             1.0             0.5             1.0
                                                         -----------------------------------------------------------------------------------------------
Improved Operating and Maintenance (O&M) Practices......            Can range from 0 to >2.0% depending on the unit's historical O&M practices.
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Two of the technologies shown in Table 1--``Blade Path Upgrade
(Steam Turbine)'' and ``Redesign/Replace Economizer''--are candidate
technologies that are expected to offer some of the largest
improvements in unit-level heat rate. However, based on public comments
from the ANPRM and the ACE proposal, those also are HRI technologies
that have the most potential to trigger NSR requirements. Industrial
stakeholders and commenters have indicated, if such HRI trigger NSR,
the resulting requirements for analysis, permitting, and capital
investments will greatly increase the cost of implementing those HRI
technologies and, in the absence of NSR reforms, states will be more
likely to determine that those technologies are not cost-effective when
analyzing ``other factors'' in determining a standard of performance
for an individual facility.
    For the ACE proposal, the EPA reflected this in assumptions made in
the power sector modeling, using the Integrated Planning Model (IPM),
to assess potential costs and benefits of the proposed rule. In that
modeling, the EPA assumed two different levels of potential HRI (in
percentage terms)--a lower expected HRI without NSR reform and a higher
expected HRI with NSR reform.\171\
---------------------------------------------------------------------------

    \171\ See 80 FR 44783.
---------------------------------------------------------------------------

    As mentioned earlier in this preamble, the EPA is not taking final
action on the proposed NSR reforms in this final rulemaking action; the
EPA intends to take final action on that proposal in a separate final
action at a later date. Without finalization of NSR reforms, the EPA
anticipates that states in some instances may determine, when
considering other factors, that the candidate technologies, ``Blade
Path Upgrade (Steam Turbine)'' and ``Redesign/Replace Economizer,'' are
less appropriate for application to a particular source or sources than
the EPA anticipated would be when it proposed the ACE Rule.
Nevertheless, the EPA is retaining these two candidate technologies as
part of the final BSER, because it still expects these technologies to
be generally applicable across the fleet of existing EGUs, and because
the costs of the technologies themselves are generally economical and
reasonable.
c. Level of Stringency Associated With the BSER
    As discussed in section III.B above, the EPA has the authority and
responsibility to determine the BSER. CAA section 111(d)(1), meanwhile,
clearly assigns states the role of developing a plan that establishes
standards of performance for designated facilities (with EPA's
authority to promulgate a federal plan serving as a backstop in the
event that a state fails to develop a satisfactory plan \172\). Based
on these statutory divisions of roles and responsibilities, the EPA
proposed to determine the BSER as HRI achievable through implementation
of certain technologies, equipment upgrades, and improved O&M
practices. The EPA also declined to propose a standard of performance
that presumptively reflects application of the BSER because the
establishment of standards of performance for existing sources is the
states' role.\173\ While declining to provide a presumptive standard,
the EPA also proposed to provide information on the degree of emission
limitation achievable through application of the BSER by providing a
range of reductions and costs associated with each of the candidate
technologies identified as part of the BSER.\174\
---------------------------------------------------------------------------

    \172\ See section 111(d)(2).
    \173\ See 83 FR 44764.
    \174\ See 83 FR 44757, Table 1.
---------------------------------------------------------------------------

    The EPA received numerous comments from states and industry
requesting that the EPA provide a presumptive standard, or at minimum,
additional guidance and clarity on how states could derive a standard
of performance that meets the requirements of this regulation.
Additionally, several commenters contended that under CAA section
111(a)(1), the EPA is legally obligated to identify ``the degree of
emission limitation achievable through the application of the [BSER]''
(i.e., a level of stringency) because such degree of emission
limitation is inextricably linked with the determination of the BSER,
which is the EPA's statutory role and responsibility. Upon
consideration of these comments, especially the widespread request for
more guidance from the EPA on developing appropriate standards of
performance, the EPA agrees that it has a responsibility under the CAA
to identify the degree of emission reduction that it determines to be
achievable through the application of the BSER.
    While the CAA provides that the responsibility to establish
standards of performance is a state's responsibility, the EPA is
identifying the degree of emission limitation achievable through the
application of the BSER (i.e., the level of stringency) associated with
the candidate technologies. By providing the level of emissions
reductions achievable using the candidate technologies the EPA is
fulfilling its responsibility as part of the BSER determination. In
this instance, the EPA has identified the degree of emission limitation
achievable through application of the BSER by providing ranges of
expected reductions associated with each of the technologies. These
ranges are provided in Table 1, clearly presenting the percentage
improvement ranges that can be expected when each candidate technology
comprising the BSER is applied to a designated facility. Defining the
ranges of HRI as the degree of emission limitation achievable through
application of the BSER is consistent with the EPA's position at
proposal, where EPA noted that ``while the HRI potential range is
provided as guidance for the states, the actual HRI performance for
each of the candidate technologies will be unit-specific and

will depend upon a range of unit-specific factors. The states will use
the information provided by the EPA as guidance but will be expected to
conduct unit-specific evaluations of HRI potential, technical
feasibility, and applicability for each of the BSER candidate
technologies.'' \175\ For purposes of the final ACE rule, states will
utilize the ranges of HRI the EPA has provided in developing standards
of performance but may ultimately establish standards of performance
for one or more existing sources within their jurisdiction that reflect
a value of HRI that falls outside of these ranges. See section
III.F.1.a of this preamble.
---------------------------------------------------------------------------

    \175\ See 83 FR 44763.
---------------------------------------------------------------------------

    It is reasonable for the EPA to express the ``degree of emission
limitation achievable through application of the BSER'' as a set of
ranges of values, rather than a single number, that reflects
application of the candidate technologies as a whole. This approach is
reasonable in light of the nature of what the EPA has identified as the
adequately demonstrated BSER (as well as of the structure of section
111 in general and the interplay between section 111(a)(1) and section
111(d) in particular): A suite of candidate technologies that the EPA
anticipates will be generally applicable to EGUs at the fleet-wide
level but not all of which may be applicable or warranted at the level
of a particular facility due to source-specific factors such as the
site-specific operational and maintenance history, the design and
configuration, the expected operating plans, etc. Because of the
importance for applicability of the BSER of these source-specific
factors, and because the application and installation of the candidate
technologies will result in varying degrees of reductions based on
application of each of the BSER technologies into the existing
infrastructure of the EGU, the EPA has provided ranges of HRI
associated with each technology. This accounts for some of the
variation that is expected among the designated facilities (see section
III.F.1.a.(1) of this preamble for discussion of variable emission
performance at and between designated facilities). While these ranges
represent the degree of emission reduction achievable through
application of the BSER, a particular designated facility may have the
potential for more or less HRI as a result of the application of the
candidate technology based on source-specific characteristics. As
further discussed in section III.F. of this preamble, the level of
stringency associated with each candidate technology is to be used by
states in the process of establishing a standard of performance, and in
this process, states may also consider source-specific factors such as
variability that may result in a different level of stringency.\176\
---------------------------------------------------------------------------

    \176\ As described later in the preamble in section III.F., the
EPA envisions states will develop standards of performance for
designated facilities in a two -step process where states first
apply the BSER and then consider source-specific factors such as
remaining useful life.
---------------------------------------------------------------------------

d. Detail on the HRI Technologies & Techniques
(1) Neural Network/Intelligent Sootblower
    Neural networks. Computer models, known as neural networks, can be
used to simulate the performance of the power plant at various
operating loads. Typically, the neural network system ties into the
plant's distributed control system for data input (process monitoring)
and process control. The system uses plant specific modeling and
control modules to optimize the unit's operation and minimize the
emissions. This model predictive control can be particularly effective
at improving the plant's performance and minimizing emissions during
periods of rapid load changes--conditions that commenters claimed to be
more prevalent now than was the case 5 to 10 years ago. The neural
network can be used to optimize combustion conditions, steam
temperatures, and air pollution control equipment.
    Intelligent Sootblowers. During operations at a coal-fired power
plant, particulate matter (PM) (ash or soot) builds up on heat transfer
surfaces. This build-up degrades the performance of the heat transfer
equipment and negatively affects the efficiency of the plant. Power
plant operators use steam injection ``sootblowers'' to clean the heat
transfer surfaces by removing the ash build-up. This is often done on a
routine basis or as needed based on monitored operating
characteristics. Intelligent sootblowers (ISB) are automated systems
that use process measurements to monitor the heat transfer performance
and strategically allocate steam to specific areas to remove ash
buildup.
    The cost to implement an ISB system is relatively inexpensive if
the necessary hardware is already installed. The ISB software/control
system is often incorporated into the neural network software package
mentioned above. As such, the HRIs obtained via installation of neural
network and ISB systems are not necessarily cumulative.
    The efficiency improvements from installation of ISB are often
greatest for EGUs firing subbituminous coal and lignite due to more
significant and rapid fouling at those units as compared to EGUs firing
bituminous coal.
    Commenters recommended that the EPA disaggregate its analysis of
neural networks and ISB because these technologies do not have to be
deployed together and implementing one without the other may be
appropriate in many cases. The EPA agrees that the technologies do not
have to be implemented together and states must evaluate the
applicability and effectiveness of both technologies. The technologies
were listed together to emphasize that they are often implemented
together and that the resulting HRIs from each are not necessarily
additive.
(2) Boiler Feed Pumps
    A boiler feed pump (or boiler feedwater pump) is a device used to
pump feedwater into a boiler. The water may be either freshly supplied
or returning condensate produced from condensing steam produced by the
boiler. The boiler feed pumps consume a large fraction of the auxiliary
power used internally within a power plant. For example, boiler feed
pumps can require power in excess of 10 MW on a 500-MW power plant.
Therefore, the maintenance on these pumps should be rigorous to ensure
both reliability and high-efficiency operation. Boiler feed pumps wear
over time and subsequently operate below the original design
efficiency. The most pragmatic remedy is to rebuild a boiler feed pump
in an overhaul or upgrade.
    Commenters stated that because upgrading an electric boiler feed
pump impacts only net heat rate (and not gross heat rate), it should be
excluded from the candidate technologies list. The EPA disagrees that
candidate technologies affecting only the net heat rate should be
removed from the candidate technologies list. These technologies
improve the efficiency and reduce emissions from the plant by reducing
the auxiliary power load, allowing for more of the produced power to be
placed on the grid. As is discussed below in section III.F.1.c., the
state will determine whether to establish standards of performance as
gross output-based standards or as net output-based standards. If
states establish gross output-based standards, it will be up to the
states to determine how to account for emission reductions that are
attributable to technologies affecting only the net output.

(3) Air Heater and Duct Leakage Control
    The air pre-heater is a device that recovers heat from the flue gas
for use in pre-heating the incoming combustion air (and potentially for
other uses such as coal drying). Properly operating air pre-heaters
play a significant role in the overall efficiency of a coal-fired EGU.
The air pre-heater may be regenerative (rotary) or recuperative
(tubular or plate). A major difficulty associated with the use of
regenerative air pre-heaters is air in-leakage from the combustion air
side to the flue gas side. Air in-leakage affects boiler efficiency due
to lost heat recovery and affects the axillary load since any in-
leakage requires additional fan capacity. The amount of air leaking
past the seals tends to increase as the unit ages. Improvements to
seals on regenerative air pre-heaters have enabled the reduction of air
in-leakage.
    The EPA received comments that claimed the applicability of air
pre-heater seals is limited, and that low-leakage seals are not
feasible on certain units while other commenters agreed that the HRI
estimates for leakage reduction are reasonable, and HRI improvement
from 0.25 to 1.0 percent is achievable. The EPA agrees that the HRI
estimates for air heater and duct in-leakage are reasonable. The EPA
agrees that low-leakage seals are not feasible for certain units (e.g.,
those using recuperative air heaters). However, the EPA is finalizing a
determination that this candidate technology is an element of the BSER
because limiting air in-leakage in the air heater and associated duct
work can be evaluated on all units and limiting the amount of air in-
leakage will improve the efficiency of the unit.
(4) Variable Frequency Drives (VFDs)
    VFD on induced draft (ID) fans. The increased pressure required to
maintain proper flue gas flow through downstream air pollutant control
equipment may require additional fan power, which can be achieved by an
ID fan upgrade/replacement or an added booster fan. Generally, older
power plant facilities were designed and built with centrifugal fans.
    The most precise and energy-efficient method of flue gas flow
control is the use of VFD. The VFD controls fan speed electrically by
using a static controllable rectifier (thyristor) to control frequency
and voltage and, thereby, the fan speed. The VFD enables very precise
and accurate speed control with an almost instantaneous response to
control signals. The VFD controller enables highly efficient fan
performance at almost all percentages of flow turndown.
    Due to current electricity market conditions, many units no longer
operate at base-load capacity and, therefore, VFDs, also known as
variable-speed drives on fans can greatly enhance plant performance at
off-peak loads. Additionally, units with oversized fans can benefit
from VFD controls. Under these scenarios, VFDs can significantly
improve the unit heat rate. VFDs as motor controllers offer many
substantial improvements to electric motor power requirements. The
drives provide benefits such as soft starts, which reduce initial
electrical load, excessive torque, and subsequent equipment wear during
startups; provide precise speed control; and enable high-efficiency
operation of motors at less than the maximum efficiency point. During
load turndown, plant auxiliary power could be reduced by 30-60 percent
if all large motors in a plant were efficiently controlled by VFD. With
unit loads varying throughout the year, the benefits of using VFDs on
large-size equipment, such as FD or ID fans, boiler feedwater and
condenser circulation water pumps, can have significant impacts. There
are circumstances in which the HRI has been estimated to be much higher
than that shown in Table 1, depending on the operation of the unit.
Cycling units realize the greatest gains representative of the upper
range of HRI, whereas units which were designed with excess fan
capacity will exhibit the lower range.
    VFD on boiler feed pumps. VFDs can also be used on boiler feed
water pumps as mentioned previously. Generally, if a unit with an older
steam turbine is rated below 350 MW, the use of motor-driven boiler
feedwater pumps as the main drivers may be considered practical from an
efficiency standpoint. If a unit cycles frequently then operation of
the pumps with VFDs will offer the best results on heat rate
reductions, followed by fluid couplings. The use of VFDs for boiler
feed pumps is becoming more common in the industry for larger units.
And with the advancements in low pressure steam turbines, a motor-
driven feed pump can improve the thermal performance of a system up to
the 600-MW range, as compared to the performance associated with the
use of turbine drive pumps.
    Some commenters stated that VFDs should be excluded from the
candidate technologies list because the efficiency improvements are
likely near zero when the EGU operates as a baseload unit. Commenters
further stated that VFD installation may not be reasonable because of
their high cost, large physical size, and significant cooling
requirements. The EPA agrees that VFD HRIs will be less effective for
units that operate consistently at high capacity factors at base load
conditions. However, due to the changing nature of the power sector
(increased use of natural gas-fired generating sources, more
intermittent renewable generating sources, etc.), many coal-fired EGUs
are cycling more often and the heat rate of such units will benefit
from installation of VFD technology. In evaluating the applicability of
the BSER technologies, states will consider ``other factors'' that will
include expected utilization rate, remaining useful life, physical/
space limitations, etc. That evaluation of ``other factors'' will
identify whether implementation of a BSER candidate technology is
reasonable. The EPA is finalizing a determination that this candidate
technology is an element of the BSER because it contributes to emission
reductions and it is broadly applicable at reasonable cost.
    Commenters also stated that VFDs only impact net heat rate, so
efficiency improvements may not be cost-effective. As stated earlier,
if the states choose to establish gross output-based standards of
performance, it will be up to the states to determine how to account
for emission reductions attributable to improvement to net heat rate.
(5) Blade Path Upgrade (Steam Turbine)
    Upgrades or overhauls of steam turbines offer the greatest
opportunity for HRI on many units. Significant increases in performance
can be gained from turbine upgrades when plants experience problems
such as steam leakages or blade erosion. The typical turbine upgrade
depends on the history of the turbine itself and its overall
performance. The upgrade can entail myriad improvements, all of which
affect the performance and associated costs. The availability of
advanced design tools, such as computational fluid dynamics (CFD),
coupled with improved materials of construction and machining and
fabrication capabilities have significantly enhanced the efficiency of
modern turbines. These improvements in new turbines can also be
utilized to improve the efficiency of older steam turbines whose
efficiency has degraded over time.
    Commenters stated that steam turbine blade path upgrades may not be
achievable for every turbine because of the potentially significant
variability in an individual turbine's parameters when considering
costs. Commenters further noted that these are large investments that
can require lengthly outages and long lead times.

    Other commenters noted that these steam turbine blade path upgrades
have been commercially available for over 10 years and that the HRI
estimates in Table 1 appear reasonable.
    The EPA agrees that steam turbine blade path upgrades are
commercially available and that the HRI estimates in Table 1 appear to
be consistent with other estimates of HRI achievable from this type of
upgrade. As mentioned earlier, based on public comments responding to
the ANPRM and the ACE proposal, this HRI measure has the potential to
trigger NSR requirements (in the absence of NSR program reforms), and
the EPA anticipates that, among the candidate technologies identified
as comprising the BSER, states may be relatively more likely to
determine in light of the resulting requirements for analysis,
permitting, and capital investments that this candidate technology is
not economically feasible when evaluating it in the process of
establishing standards of performance for particular existing sources
within their jurisdiction. Nevertheless, the EPA is finalizing a
determination that steam turbine blade bath upgrades are part of the
BSER because the EPA anticipates they will still be generally available
and feasible at a sufficient scale among the nationwide fleet.
(6) Redesign/Replace Economizer
    In steam power plants, economizers are heat exchange devices used
to capture waste heat from boiler flue gas which is then used to heat
the boiler feedwater. This use of waste heat reduces the need to use
extracted energy from the system and, therefore, improves the overall
efficiency or heat rate of the unit. As with most other heat transfer
devices, the performance of the economizer will degrade with time and
use, and power plant representatives contend that economizer
replacements are often delayed or avoided due to concerns about
triggering NSR requirements. In some cases, economizer replacement
projects have been undertaken concurrently with retrofit installation
of selective catalytic reduction (SCR) systems because the entrance
temperature for the SCR unit must be controlled to a specific range.
    Commenters stated that redesigning or replacing an economizer may
be limited for some units by the need to maintain appropriate
temperatures at a downstream SCR system for nitrous oxides (NOx)
control. Commenters also stated that applicability of this measure will
be site-specific because boiler layout and construction varies widely
between units. Commenters stated that the values in Table 1 appear to
reflect a major economizer redesign which may not be possible for many
units. The EPA agrees that there will likely be site-specific factors
that must be considered to determine whether economizer redesign/
replacement is a feasible HRI option (as is the case for all the BSER
candidate technologies). Nevertheless, the EPA is finalizing a
determination that economizer upgrades (or replacement) are part of the
BSER because the EPA anticipates they will still be generally available
and feasible at a sufficient scale among the nationwide fleet. As
mentioned earlier, states may take into consideration site-specific
characteristics (``other factors'') when establishing a standard of
performance for each unit.
(7) HRI Techniques--Best Operating and Maintenance Practices
    Many unit operators can achieve additional HRI by adopting best O&M
practices. The amount of achievable HRI will vary significantly from
unit to unit, ranging from no improvement to potentially more than 2.0
percent depending on the unit's historical O&M practices. In setting a
standard of performance for a specific unit or subcategory of units,
states will evaluate the opportunities for HRI from the following
actions.
(a) Adopt HRI Training for O&M Staff
    EGU operators can obtain HRI by adopting ``awareness training'' to
ensure that all O&M staff are aware of best practices and how those
practices affect the unit's heat rate.
    Some commenters agreed that HRI training can improve staff
awareness of plant efficiency measures, which should result in improved
plant performance. Other commenters stated that the benefits of HRI
training are highly variable and depend on existing equipment and
staff. Some commenters stated that the operating staff already
routinely undergo HRI training and that states should not be required
to consider these measures in developing their plans. The EPA agrees
that the benefits will be variable from unit to unit depending upon the
unit's historical O&M practices. If operating staff at a source already
undergo routine HRI training, then the state will note that in the
standard-setting process. Just as an EGU that has recently installed
new or reconstructed boiler feed pumps would not be expected to replace
those pumps, a source that already has an effective HRI training
program in place would not be expected to implement a new HRI training
program. The EPA is finalizing a determination that this practice is an
element of the BSER because it can result in emission reductions and
can be broadly implemented at reasonable cost.
(b) Perform On-Site Appraisals To Identify Areas for Improved Heat Rate
Performance
    Some large utilities have internal groups that can perform on-site
evaluations of heat rate performance improvement opportunities. Outside
(i.e., third-party) groups can also provide site-specific/unit-specific
evaluations to identify opportunities for HRI.
    Commenters stated that the benefits of on-site appraisals are
variable, speculative, and site-specific. Commenters stated that no
state should determine what opportunities a coal-fired EGU might find
during an on-site appraisal, and, therefore, that states should not be
required to evaluate the applicability of on-site appraisals when
developing their plans and establishing standards of performance for
existing sources within their jurisdiction. The EPA agrees that the
benefits of on-site appraisals will be variable and site-specific. As
with other BSER measures, it will be up to each state to determine the
extent of this requirement. States may require that the owner/operator
perform an on-site appraisal to identify areas for HRI or the state may
choose to have a third party conduct an on-site HRI appraisal.
(c) Improved Steam Surface Condenser--Cleaning
    Effective operation of the steam surface condenser in a power plant
can significantly improve a unit's heat rate. In fact, in many cases
ineffective operation can pose the most significant hindrance to a
plant trying to maintain its original design heat rate. Since the
primary function of the condenser is to condense steam flowing from the
last stage of the steam turbine to liquid form, it is most desirable
from a thermodynamic standpoint that this occurs at the lowest
temperature reasonably feasible. By lowering the condensing
temperature, the backpressure on the turbine is lowered, which improves
turbine performance.
    Condenser cleaning. A condenser degrades primarily due to fouling
of the tubes and air in-leakage. Tube fouling leads to reduced heat
transfer rates, while air in-leakage directly increases the
backpressure of the condenser and degrades the quality of the water.
Condenser tube cleaning can be performed using either on-line methods
or more rigorous off-line methods.

    Commenters stated that improved steam surface condenser cleaning is
a viable O&M option. Commenters stated that the need for such cleaning
can be determined by enhanced monitoring of condenser performance. The
EPA agrees with this assessment and notes that many owner/operators may
already have steam surface condenser cleaning as part of routine O&M
for their units. The EPA is finalizing a determination that this O&M
practice is an element of the BSER because it provides opportunity for
heat rate improvement and is broadly applicable.
e. Cost of HRI
    The EPA finds that the costs of the HRI technologies and practices
that the EPA has identified as the BSER and provided in Table 1 are
reasonable because they improve the efficiency of the units to which
they are applied. This results in lower operating costs (especially
lower fuel costs). In fact, these HRI technologies and practices are
the types of efficiency improvement measures that some owners and
operators have reasonably implemented at times over the course of the
operating life of their EGUs. In specific circumstances the cost to
implement one or more of the technologies may be determined to be
unreasonable--after consideration of source-specific factors. This will
be determined when states establish standards by applying the BSER and
taking other factors, including remaining useful life, into
consideration.
(1) Reasonableness of Cost
    As mentioned earlier, under CAA section 111(a)(1), the EPA
determines ``the best system of emission reduction which (taking into
account the cost of achieving such reduction . . .) . . . has been
adequately demonstrated.'' 42 U.S.C. 7411(a)(1) (emphasis added). In
several cases, the D.C. Circuit has elaborated on this cost factor in
various ways, stating that the EPA may not adopt a standard for which
costs would be ``exorbitant,'' \177\ ``greater than the industry could
bear and survive,'' \178\ ``excessive,'' \179\ or ``unreasonable.''
\180\ These formulations appear to be synonymous and suggest a cost-
reasonableness standard. Therefore, in this action, the EPA has
evaluated whether the costs of HRI are considered to be reasonable as a
general matter across the fleet of existing sources.
---------------------------------------------------------------------------

    \177\ Lignite Energy, 198 F.3d at 933.
    \178\ Portland Cement, 513 F.2d at 508.
    \179\ Sierra Club, 657 F.2d at 343.
    \180\ Id.
---------------------------------------------------------------------------

    Any efficiency improvement made by an EGU will also reduce the
amount of fuel consumed per unit of electricity output; fuel costs can
account for a large percentage of the overall costs of power
production. The cost attributable to CO2 emission
reductions, therefore, is the net cost of achieving HRIs after any
savings from reduced fuel expenses. So, over some time period
(depending upon, among other factors, the extent of HRIs, the cost to
implement such improvements, and the unit utilization rate), the
savings in fuel cost associated with HRIs may be sufficient to cover
the costs of implementing the HRI measures. Thus, the net costs of HRIs
associated with reducing CO2 emissions from designated
facilities can be relatively low depending upon each EGU's individual
circumstances. It should be noted that this cost evaluation is not an
attempt to determine the affordability of the HRI in a business or
economic sense (i.e., the reasonableness of the imposed cost is not
determined by whether there is an economic payback within a predefined
time period). However, the ability of EGUs to recoup some of the costs
of HRIs through fuel savings supports a finding that costs are
reasonable. While some EGUs may not realize the full potential of cost
recuperation from fuel savings, the EPA finds that the net costs of
implementing HRIs as an approach to reducing CO2 emissions
from fossil fuel-fired EGUs are reasonable because they are not
exorbitant or excessive. In fact, these HRIs are the types of
efficiency improvement measures that some owners and operators have
reasonably implemented at times over the course of the operating life
of their EGUs.
    It will be up to the states to, either directly or indirectly, take
cost into consideration in establishing unit-specific standards of
performance. CAA section 111(d) explicitly allows the states to take
into consideration, among other factors, the remaining useful life of
the existing source in applying the standard of performance. For
example, a state may find that an HRI technology is applicable for an
affected coal-fired EGU but find that the costs are not reasonable when
consideration is given to the timeframe for the planned retirement of
the source (i.e., the source's remaining useful life). A state may find
that an HRI technology is applicable for an affected coal-fired EGU but
find that the costs are not reasonable because the source is already
implementing that HRI technology and it would not be reasonable to
expect the source to replace that HRI technology with a newer version
of the same technology.
    There are several ways that cost can be considered. For example,
when evaluating costs for criteria pollutants in a BACT analysis or for
a ``beyond-the-floor'' analysis for HAP under CAA section 112, the
emphasis is focused on the cost of control relative to the amount of
pollutant removed--a metric typically referred to as the ``cost-
effectiveness.'' There have been relatively few BACT analyses
evaluating GHG reduction technologies for coal-fired EGUs. Therefore,
there are not a large number of GHG cost-effectiveness determinations
to compare against as a measure of the cost reasonableness.
Nevertheless, in PSD and title V permitting guidance for GHG emissions,
the EPA noted that ``it is important in BACT reviews for permitting
authorities to consider options that improve the overall energy
efficiency of the source or modification--through technologies,
processes and practices at the emitting unit. In general, a more energy
efficient technology burns less fuel than a less energy efficient
technology on a per unit of output basis.'' \181\ The EPA has also
noted that a ``number of energy efficiency technologies are available
for application to both existing and new coal-fired EGU projects that
can provide incremental step improvements to the overall thermal
efficiency.'' \182\
---------------------------------------------------------------------------

    \181\ See page 21, ``PSD and Title V Permitting Guidance for
Greenhouse Gases,'' EPA-457/B-11-001, March 2011; https://www.epa.gov/sites/production/files/2015-12/documents/ghgpermittingguidance.pdf.
    \182\ See page 25, ``Available and Emerging Technologies for
Reducing Greenhouse Gas Emissions from Coal-fired Electric
Generating Units,'' October 2010; https://www.epa.gov/sites/production/files/2015-12/documents/electricgeneration.pdf.
---------------------------------------------------------------------------

(2) Cost of the HRI Candidate Technologies Measures
    The estimated costs for the BSER candidate technologies are
presented below in Table 2. These are cost ranges from the 2009 Sargent
& Lundy Study \183\ updated to $2016.\184\ These costs correspond to
ranges of HRI (percent) presented earlier in Table 1.
---------------------------------------------------------------------------

    \183\ ``Coal-Fired Power Plant Heat Rate Reductions'' Sargent &
Lundy report SL-009597 (2009) Available in the rulemaking docket at
EPA-HQ-OAR-2017-0355-21171.
    \184\ The conversion factor comes from Federal Reserve Economic
Data (FRED). See https://fred.stlouisfed.org.

                                                   Table 2--Summary of Cost ($2016/kW) of HRI Measures
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                      <200 MW                       200-500 MW                        >500 MW
                       HRI Measure                       -----------------------------------------------------------------------------------------------
                                                                Min             Max             Min             Max             Min             Max
--------------------------------------------------------------------------------------------------------------------------------------------------------
Neural Network/Intelligent Sootblowers..................             4.7             4.7             2.5             2.5             1.4             1.4
Boiler Feed Pumps.......................................             1.4             2.0             1.1             1.3             0.9             1.0
Air Heater & Duct Leakage Control.......................             3.6             4.7             2.5             2.7             2.1             2.4
Variable Frequency Drives...............................             9.1            11.9             7.2             9.4             6.6             7.9
Blade Path Upgrade (Steam Turbine)......................            11.2            66.9             8.9            44.6             6.2            31.0
Redesign/Replace Economizer.............................            13.1            18.7            10.5            12.7            10.0            11.2
                                                         -----------------------------------------------------------------------------------------------
Improved O&M Practices..................................                                       Minimal capital cost
--------------------------------------------------------------------------------------------------------------------------------------------------------

    These costs presented in Table 2 represent both capital and O&M
costs. Investments in HRI measures at EGUs should also result in fuel
savings which can offset some or all of the cost of the HRI. However,
the EPA does not suggest that HRI measures should meet any particular
economic criterion (e.g., pay for themselves through reduced fuel
costs) in order to be applied in state plans for the establishment of
source-specific standards of performance.
    The technical applicability and efficacy of HRI measures and the
cost of implementing them are dependent upon site specific factors and
can vary widely from site to site. Because there is inherent
flexibility provided to the states in applying the standards of
performance, there is a wide range of potential outcomes that are
highly dependent upon how the standards are applied (and to what degree
states take into consideration other factors, including remaining
useful life).
    Because the heat rate improvement technologies result in fuel
savings and other potential cost savings and the listed candidate
technologies are the types of improvements and equipment upgrades that
have been previously undertaken, the EPA finds that the costs of the
HRI technologies and practices that have been identified as the BSER
and provided in Table 1 are reasonable.
f. Non-Air Quality Health and Environmental Impacts, Energy
Requirements, and Other Considerations
    As directed by CAA section 111(a)(1), the EPA has taken into
account non-air quality health and environment requirements for each of
the candidate BSER technologies listed in Tables 1 and 2. None of the
candidate technologies, if implemented at a coal-fired EGU, would be
expected to result in any deleterious effects on any of the liquid
effluents (e.g., scrubber liquor) or solid by-products (e.g., ash,
scrubber solids). The EPA has also taken into account energy
requirements. All of these candidate technologies, when implemented,
would have the effect of improving the efficiency of the coal-fired
EGUs to which they are applied. As such, the EGU would be expected to
use less fuel to produce the same amount of electricity as it did prior
to the efficiency (heat rate) improvement. None of the candidate
technologies is expected to impose any significant additional auxiliary
energy demand.
    Implementation of heat rate improvement measures also would achieve
reasonable reductions in CO2 emissions from designated
facilities in light of the limited cost-effective and technically
feasible emissions control opportunities. In the same vein, because
existing sources face inherent constraints that new sources do not,
existing sources present different, and in some ways more limited,
opportunities for technological innovation or development.
Nevertheless, the final emissions guidelines encourage technological
development by promoting further development and market penetration of
equipment upgrades and process changes that improve plant efficiency
leading to reasonable reductions in CO2 emissions.
3. Discussion of ``Rebound Effect''
    At proposal, the EPA solicited comment on potential CO2
emissions and generation changes that might occur as a result of
efficiency improvements at designated facilities, including potential
increased generation to the point of a net increase in emissions from a
particular facility, also referred to as the ``rebound effect.'' In
some instances, it is possible that certain sources increase in
generation (relative to some baseline) as a result of lower operating
costs from adoption of candidate technologies to improve their
efficiency. The EPA conducted analysis and modeling for the ACE
proposal, and found that while there were instances (in some scenarios)
where a limited number of designated facilities that adopted HRI
increased generation to the point of increasing mass emissions
notwithstanding the lower emissions rate resulting from HRI adoption,
due to their improved efficiency and marginally improved economic
competitiveness relative to other electric generators, the designated
facilities as a group reduce emissions because they can generate higher
levels of electricity with a lower overall emission rate.
    Some commenters on the proposed rule highlighted environmental and
legal concerns with the rebound effect as undermining the BSER, while
others commented that the concern was de minimis, not rooted in any
legal basis, and not germane to establishing standards of performance.
On one side, some commenters asserted that the determined BSER is not
properly designed because it would not achieve emission reductions if
it results in higher utilization and, therefore, emission increases.
Some doubted the EPA claims of lower systemwide emissions and said the
EPA had not adequately analyzed the concern. Some asserted that the
assumptions used in the analysis do not reflect real world
considerations that efficiency of all fossil fuel plants degrades over
time, rather than being static. Also, some asserted that the EPA had
understated the amount of coal capacity that will likely retire in its
analysis, and, thus, the remaining coal fleet will consist of more
efficient and competitive units that may end up emitting more than the
EPA's analysis shows. In addition, some asserted that the EPA's
proposed NSR reforms allow sources to extend lifetimes without
requiring controls, exacerbating rebound issues.
    Other commenters asserted that CAA section 111 does not require the
Agency to obtain absolute reductions in emissions at a sector-wide
level, and the EPA's obligation is to determine the BSER through
evaluation of emissions performance per output at the unit-level. Some
commenters stated that any rebound effect from more efficient units is
most likely to come at expense of lower-efficiency coal units, negating
the effect. Also, commenters contended that rebound is unlikely to
change the

dispatch order and/or utilization of units based upon the levels of HRI
that are reasonable and part of ACE, and, thus, any rebound effect
would be de minimis.
    The EPA agrees with the commenters who do not see the rebound
effect as undermining the BSER determination in this rule, because this
rule is aimed at improving a source's emissions rate performance at the
unit-level. Indeed, in repealing the ``percent reduction'' requirement
from the 1977 CAA Amendments, Congress expressly acknowledged that
standards of performance were to be expressed as an emissions
rate.\185\ In addition, as noted above, this rule results in overall
reductions of emissions of CO2. Because the BSER in this
rule improves the emissions rate of designated facilities and results
in overall reductions, the limited rebound effect that may occur does
not undermine the BSER.
---------------------------------------------------------------------------

    \185\ See 1990 CAA Amendments, section 403, 104 Stat. at 2631
(``the Administrator shall promulgate revised regulations for
standards of performance . . . that, at a minimum, require any
source subject to such revised standards to emit sulfur dioxide at a
rate not greater than would have resulted from compliance by such
source with the applicable standards of performance under this
section prior to such revision'') (emphasis added).
---------------------------------------------------------------------------

    Nonetheless, to the extent commenters have asserted that ACE would
cause an increase in aggregate CO2 emissions due to some
sources operating more, this concern is not supported by our analysis.
The EPA conducted updated modeling and analysis for the final ACE rule
(see Chapter 3 of the RIA for more details) and confirmed that
aggregate CO2 emissions from the group of designated
facilities are anticipated to decrease (outweighing any potential
CO2 increases related to increased generation by certain
units).
    The final ACE rule establishes the BSER, and a framework for states
to determine rate-based standards of performance for designated
facilities. The BSER for ACE is expressed as a rate-based approach,
which should necessarily result in rate-based emission reductions. The
modeling and analysis show individual units and the entire coal fleet
reducing emission rates, as well as an aggregate decrease in mass
emissions. As such, any potential ``rebound effect'' is determined to
be small and manageable (if necessary) and does not require any
specific remedy in the final rule. However, if a state determines that
the source-specific factors of a designated facility dictate that the
rebound effect is an issue that should be considered in setting the
standard of performance, that is within the state's discretion to
consider in the process of establishing a standard of performance for
that particular existing source. As noted above and as a result of
modeling, the EPA does not expect these considerations to be necessary
in the state plan development process.
4. Systems That Were Evaluated But Are Not Part of the Final BSER
    The EPA identified several systems of GHG emission reduction that
may be applied at or to designated facilities but did not propose that
they should be part of the BSER. The Agency solicited comment on the
rationale for eliminating or not identifying those alternative systems
as part of the BSER. After consideration of public comments, the EPA is
not revising its proposed determination and is not including any
additional or different systems of emission reduction in the final BSER
determination. A description of the considered systems of emission
reduction that are not part of the final BSER along with a summary of
significant public comments is provided below.
    The EPA previously considered co-firing (including 100 percent
conversion) with natural gas and implementation of carbon capture and
storage (CCS) as potential BSER options. See 80 FR 64727. In that
analysis, the EPA found some natural gas co-firing and CCS measures to
be technically feasible but determined that switching from coal to gas
is ``a relatively costly approach to CO2 reductions at
existing coal steam boilers when compared to other measures such as
heat rate improvements. . .'' \186\ and that the cost to implement CCS
for existing source standards is not reasonable and that ``CCS is not
an appropriate component of the [BSER].'' \187\ A more detailed
description of the current consideration of these technologies is
provided below.
---------------------------------------------------------------------------

    \186\ Technical Support Document (TSD) for Carbon Pollution
Guidelines for Existing Power Plants: Emission Guidelines for
Greenhouse Gas Emissions from Existing Stationary Sources: Electric
Utility Generating Units; Chapter 6, June 10, 2014, Available at
Docket Item No. EPA-HQ-OAR-2013-0602-36852.
    \187\ Id. Chapter 7
---------------------------------------------------------------------------

a. Natural Gas Repowering
    Coal-fired utility boilers can reduce their emissions by firing
natural gas instead of--or in combination with--coal. This can be done
in three different ways: (1) By repowering, (2) by co-firing, or (3) by
refueling. Repowering is when an existing coal-fired boiler is replaced
with one or more natural gas-fired stationary combustion turbines,
while still utilizing the existing steam turbines. Co-firing and
refueling involve the burning of natural gas at an existing
boiler.\188\
---------------------------------------------------------------------------

    \188\ Co-firing and refueling are discussed in section III.E.4.b
of this preamble.
---------------------------------------------------------------------------

    In the ACE proposal, the EPA did not consider natural gas
repowering as a potential system of emission reduction (i.e., as a
candidate for the BSER) based on the reasoning that this option would
fundamentally redefine the existing sources subject to the rule.\189\
Some commenters argued, however, that coal-fired utility boilers can
reduce emissions through natural gas repowering and it should be the
BSER. Other commenters argued that the `redefining the source' concept
from PSD was inappropriate for application to NSPS. After considering
public comments on this issue, the EPA concludes that repowering should
not be considered for purposes of CAA section 111(d). As described in
more detail below, repowering is not a ``system'' of emission reduction
for a source at all because it cannot be applied to the existing
sources subject to this rule (steam generating units). Rather,
repowering these existing units would replace them entirely with a
different type of source (stationary combustion turbines) that would be
subject to the NSPS in 40 CFR part 60, subpart TTTT.\190\ Even if
repowering were to be evaluated to determine if it was part of the
BSER, the EPA has found non-air quality health and environmental
impacts and energy requirements that demonstrate that repowering is not
part of the BSER.\191\
---------------------------------------------------------------------------

    \189\ See 83 FR 44753.
    \190\ The EPA is not concluding whether or not the `redefining
the source' concept can or should be applied in the context of the
NSPS program.
    \191\ These non-air quality health and environmental impacts and
energy requirements are discussed in more detail below in the
discussion of refueling and co-firing. Except to the extent that
discussion involves the inefficient combustion of natural gas, the
non-air quality health and environmental impacts and energy
requirements found for these technologies are similar, if not
identical, to those the EPA has found for repowering.
---------------------------------------------------------------------------

    As described above, a ``standard of performance'' under CAA section
111(d) must be ``establishe[d]'' for an ``existing source.'' However,
repowering a coal-fired boiler--that is, the replacement of a boiler
with a stationary combustion turbine--creates a ``new source,'' which
is regulated directly by the EPA under 40 CFR part 60, subpart TTTT
(establishing standards for the control of GHG emissions from new,
modified, or reconstructed steam generating units, IGCCs, or stationary
combustion turbines). The ``best system of emission reduction'' for an
existing source,

therefore, simply cannot be the creation of a new source that is
regulated under separate authority. Otherwise, the EPA could subvert
the provisions of CAA section 111(d) (which authorizes states to
regulate existing sources in the first instance) and require all
existing sources to transform into ``new sources,'' which the Agency
can directly regulate under CAA section 111(b). Therefore, repowering a
coal-fired boiler is not a ``system'' within the scope of the BSER.
b. Natural Gas Co-Firing and Refueling
    Some coal-fired utility boilers use natural gas or other fuels
(such as distillate fuel oil) for startup operations, for maintaining
the unit in ``warm standby,'' or for NOX control (either
directly as a combustion fuel or in configuration referred to as
natural gas reburn). During such periods of natural gas co-firing, an
EGU's CO2 emission rate is reduced as natural gas is a less
carbon intensive fuel than coal. For example, at 10 percent natural gas
co-firing, the net emissions rate (lb/MWh-net) of a typical unit could
decrease by approximately 4 percent.
    Commenters stated that the EPA should determine that natural gas
co-firing is the BSER because it is technically feasible, readily
available, achieves significant emission reductions, and may be the
most cost-effective option for some facilities. Some commenters also
provided data (from EIA) to assert that co-firing is widely used and
adequately demonstrated at coal-fired EGUs. The commenters contended
that a significant number of coal-fired EGUs have the capacity to burn
both natural gas and coal. One commenter asserted that 35 percent of
coal-fired utility boilers across 33 states co-fired with natural gas.
Another commenter provided a table listing coal-fired EGUs that have
recently converted to natural gas or are co-firing with natural gas.
One commenter cited data from the EIA and claimed that 48 percent of
steam generating EGUs are already co-firing some amount of natural gas.
    While the EPA agrees with the assertion that there are existing
coal plants that have some access to a supply of natural gas, the EPA
disagrees that the data demonstrate that co-firing is a system of
emission reduction that has been or that could be implemented on a
nationwide scale at reasonable cost. The EPA believes that commenters
have conflated operational co-firing (i.e., co-firing coal and natural
gas to generate electricity) with startup co-firing (i.e., only using
natural gas to heat up a utility boiler or to maintain temperature
during standby periods). Coal-fired boilers always use a secondary fuel
(most often natural gas or distillate fuel oil), utilizing burners
specifically configured to bring the boiler from a cold, non-operating
status to a temperature where coal, the primary fuel, can be safely
introduced for normal operations.
    The EPA conducted its own analysis using EIA fuel use data from
2017.\192\ The EPA's analysis supports the assertion that nearly 35
percent of coal-fired units co-fired (in either sense of co-firing as
described above) with natural gas in 2017. However, very few--less than
four percent of coal-fired units--co-fired with natural gas in an
amount greater than five percent of the total annual heat input. This
strongly suggests that most of the natural gas that was utilized at
these sites was used as a secondary fuel for unit startup or to
maintain the unit in ``warm standby'' rather than as a primary fuel for
generation of electricity. Further, the small number of units that co-
fired with greater than five percent natural gas during 2017 operated
at an average capacity factor of only 24 percent--indicating that they
are not the most economical units and are not dispatched as frequently
as those units that used less than five percent natural gas. For
comparison, in 2017, 62 percent of coal-fired utility boilers co-fired
with some amount of distillate fuel oil and, as with natural gas, the
vast majority of those units used less than 5 percent distillate fuel
oil (again, strongly suggesting that it is primarily used as a
secondary fuel for startup and warm standby).
---------------------------------------------------------------------------

    \192\ See the memorandum ``2017 Fuel Usage at Affected Coal-
fired EGUs,'' available in the rulemaking docket (Docket ID No. EPA-
HQ-OAR-2017-0355).
---------------------------------------------------------------------------

    The EPA also disagrees that the data demonstrate that co-firing can
be considered at the national level as an adequately demonstrated
system of emission reduction and that there are easy paths to expand it
at a reasonable cost. The EIA 923 fuel use data indicated that about 65
percent of coal-fired utility boilers use something other than natural
gas as the secondary fuel for periods of startup and standby
operations. Distillate fuel oil is by far the most commonly used
secondary fuel. While the use of distillate fuel oil does not
necessarily mean that the unit lacks access to natural gas, it suggests
that for many of those units, there is an inadequate supply to serve
even as a secondary fuel for startup and standby operations. The 2018
average price \193\ of distillate fuel oil was more than four times
higher than that of natural gas; so, if there was an adequate supply of
natural gas, then it would be much more economically favorable to
utilize that natural gas rather than the much more expensive distillate
fuel oil. As explained earlier, for plants that require additional or
new pipeline capacity, the capital cost of constructing new pipeline
laterals is approximately $1 million per mile of pipeline built.
Therefore, a 50-mile gas pipeline would add $50 million--$100/kW for a
typical 500 MW unit--to the capital costs of adding co-firing
capability.
---------------------------------------------------------------------------

    \193\ The 2018 average U.S. power generation fuel costs for
natural gas was $3.52 per million Btu while the cost for distillate
fuel oil for power generation was $16.13 per million Btu. U.S. EIA
Short Term Energy Outlook, https://www.eia.gov/outlooks/steo/tables/pdf/2tab.pdf.
---------------------------------------------------------------------------

    As mentioned earlier, the EPA has previously evaluated the costs
associated with using natural gas refueling or co-firing as a GHG
mitigation option. See 79 FR 34875. For a typical base-load coal-fired
EGU, the average cost of CO2 reductions achieved through co-
firing with 10 percent natural gas would be approximately $136 per ton
of CO2. While a utility boiler that is converted to 100
percent natural gas-fired can offset some of the capital costs by
reducing its fixed operating and maintenance costs (though, as
discussed below, the costs would still be considerably higher than the
HRI technologies that the EPA identified as the BSER), a unit that is
co-firing natural gas with coal would continue to bear the fixed costs
associated with equipment needed for coal combustion, raising the cost
per ton of CO2 reduced.
    In determining the BSER, CAA section 111(a)(1) also directs the EPA
to take into account non-air quality health and environmental impacts
and energy requirements. The EPA is unaware of any significant non-air
quality health or environmental impacts associated with natural gas co-
firing. However, in taking energy requirements into account, the EPA
notes that co-firing natural gas in coal-fired utility boilers is not
the best or most efficient use of natural gas and, as noted above, can
lead to less efficient operation of utility boilers. NGCC stationary
combustion turbine units are much more efficient at using natural gas
as a fuel for generating electricity and it would not be an
environmentally positive outcome for utilities and owner/operators to
redirect natural gas from the more efficient NGCC EGUs to the less
efficient utility boilers to satisfy an emission standard at the
utility boiler. Some commenters disagreed with the EPA's claim that
increased use of natural gas in a utility boiler would

come at the expense of its use in more efficient NGCC units. The EPA
did not intend to imply that there is now (or that there will be) a
restricted supply of natural gas. Instead, the EPA suggested that, if
there were to be an increase in the use of natural gas, the more
efficient use for that increased natural gas would be as fuel for
under-utilized NGCC units rather than in less efficient utility
boilers. The EPA does not believe that establishing a BSER that, for
all practical purposes, would mandate increased use of natural gas in
utility boilers is good policy.
    Given that a natural gas co-firing-based BSER would result in
standards that are more costly than standards based on application of
the candidate technologies for heat rate improvements, that such a BSER
would encourage inefficient use of natural gas, that implementation
would be even more expensive and challenging for those units that
currently have limited or no access to natural gas, the EPA concludes
that co-firing natural gas in coal-fired boilers is not the BSER.
    Some commenters requested that co-firing be added to the list of
HRI candidate technologies (discussed in more detail below), the
combination of which would represent the BSER. However, whereas all
coal-fired utility boilers can apply (or have already applied) HRI
measures, natural gas co-firing does not satisfy the same CAA section
111(a)(1) criteria (see above). Moreover, co-firing can negatively
impact a unit's heat rate (efficiency) due to the high hydrogen content
of natural gas and the resulting production of water as a combustion
by-product.\194\ And depending on the design of the boiler and extent
of modifications, some boilers may be forced to de-rate (a reduction in
generating capacity) to maintain steam temperatures at or within design
limits, or for other technical reasons. Accordingly, natural gas co-
firing cannot be applied in combination with the HRI measures
identified as the BSER. However, natural gas co-firing might be
appropriate for certain sources as a compliance option. For a
discussion of compliance options, see below section III.F.2.
---------------------------------------------------------------------------

    \194\ Natural gas firing or co-firing degrades the boiler's
efficiency (relative to the use of coal) primarily due to the
increased production of water. Some of the heat that is produced in
the combustion process will be used to heat that flue gas moisture
(which will exit with the stack gases) rather than to converting
water in the boiler tubes to steam. The efficiency declines because
there is less heat available to produce useful steam.
---------------------------------------------------------------------------

    Some commenters also suggested that the EPA's concerns about using
gas inefficiently were not persuasive because the United States has
such an abundant supply of natural gas. The EPA disagrees for many of
the same reasons that the Agency relied upon to reject the
consideration of natural gas as the BSER. First, it is on the higher
end of the cost of the measures the EPA considered even for units with
ready natural gas availability; second, many designated facilities do
not have natural gas availability, so it is not broadly applicable.
    The same factors discussed above lead the Agency to conclude that
refueling also cannot be BSER. Refueling is when an existing coal-fired
boiler is converted to a natural gas-fired boiler (i.e., firing 100%
natural gas). In the ACE proposal, the EPA did not consider natural gas
refueling as a potential system of emission reduction (i.e., as a
candidate for the BSER) based on the reasoning that this option would
fundamentally redefine the existing sources subject to the rule.\195\
Some commenters argued, however, that coal-fired utility boilers can
reduce emissions through natural gas refueling and should be the BSER.
Other commenters argued that the `redefining the source' concept from
PSD was inappropriate for application to NSPS.\196\ After considering
public comments on this issue, the EPA concludes that natural gas
refueling, like natural gas co-firing, is not the BSER.
---------------------------------------------------------------------------

    \195\ See 83 FR 44753.
    \196\ As with repowering, the EPA is not concluding whether or
not the ``redefining the source'' concept can or should be applied
in the context of the NSPS program.
---------------------------------------------------------------------------

    The EPA has previously evaluated the costs associated with using
natural gas refueling or co-firing as a GHG mitigation option.\197\ The
capital costs of plant modifications required to switch a coal-fired
EGU completely to natural gas are roughly $100-300/kW, not including
any costs associated with constructing additional pipeline capacity.
Many coal-fired plants do not have immediate and ready access to any
supply of natural gas. Others that do have access to a supply of
natural gas have only a limited supply (i.e., enough for startup and
warm standby firing, but not enough for full load firing). For plants
that require additional pipeline capacity, the capital cost of
constructing new pipeline laterals is approximately $1 million per mile
of pipeline built. A 50-mile gas pipeline would add $50 million--$100/
kW for a typical 500 MW unit--to the capital costs of the conversion.
---------------------------------------------------------------------------

    \197\ See 79 FR 34875.
---------------------------------------------------------------------------

    While a coal-fired utility boiler that is converted to a 100
percent natural gas-fired boiler could offset some of the capital costs
by reducing its fixed operating and maintenance costs, in most cases,
the most significant cost change associated with switching from coal to
gas is likely to be the difference in fuel cost. Using the EIA's
projections of future coal and natural gas prices, switching a utility
boiler from coal-fired to natural gas-fired could more than double the
unit's fuel cost per MWh of generation. For a typical base-load coal-
fired EGU, the average cost of CO2 reductions achieved
through gas conversion would be approximately $75 per ton of
CO2. This cost could also be much higher as there would very
likely be an increase in natural gas prices corresponding to the
increased demand from widespread coal-to-gas conversion.
    The EPA also found that consideration of energy requirements (as
required by CAA section 111(a)(1)) provides additional reasons why
refueling natural gas in a utility boiler should not be considered
BSER.\198\ Burning natural gas in a utility boiler is not the best use
of such fuel as it is much less efficient than burning it in a
combustion turbine. New natural gas combined cycle (NGCC) units can
convert the heat input from natural gas to electricity with an
efficiency of more than 50 percent.\199\ A coal-fired utility boiler
that is repurposed to burn 100 percent natural gas will see a reduction
in efficiency of up to five percent (to less than 40 percent
efficiency) as the higher hydrogen content in the natural gas fuel will
lead to higher moisture losses that will negatively impact the boiler
efficiency.\200\ Widespread refueling is not a practice that the EPA
should be promoting as it is not the most efficient use of natural gas.
Utilities choosing to increase use of natural gas in a combined cycle
or simple cycle combustion turbine is a more efficient way to utilize
natural gas for electricity generation. In reaching this determination,
the EPA is mindful of Congress's direction to ``tak[e] into account . .
. energy requirements'' in determining the best system of emission
reduction in CAA section 111(a)(1). Consideration of ``energy
requirements'' is one of the factors informing the EPA's judgment that
it would be inappropriate to base performance standards on an

inherently energy-inefficient practice such as refueling.
---------------------------------------------------------------------------

    \198\ See 83 FR 44762.
    \199\ ``Cost and Performance Baseline for Fossil Energy Plants
Volume 1a: Bituminous Coal (PC) and Natural Gas to Electricity''
Rev. 3, DOE/NETL-2015/1723 (July 2015).
    \200\ ``Leveraging Natural Gas: Technical Considerations for the
Conversion of Existing Coal-Fired Boilers'', Babcock Power Services,
Presented at 2014 ASME Power Conference (July 2014), Baltimore, MD.
Available in the rulemaking docket.
---------------------------------------------------------------------------

    NGCC units have become the preferred option for intermediate and
baseload natural gas power generation. Other technologies (such as
simple cycle aeroderivative turbines) offer significant advantages for
peaking purposes in that they can start up quickly and require fewer
staff to operate. Some combination of aeroderivative turbines and
flexible combined cycle units offer advantages in both efficiency and
the flexibility to change loads when compared to utility boilers. For
these reasons, the power sector has moved away from the use of gas-
fired boilers. There have been no new natural gas-fired utility boilers
built since the 1980s.
    There have been some cases where coal-fired utility boilers have
chosen to refuel (i.e., have chosen to convert to natural gas-firing).
In those cases, the motivation was largely to preserve reserve capacity
without investing in the air pollution controls needed to meet air
emission standards--especially MATS.\201\ The EPA examined fuel use
data submitted by plant owner/operators to the U.S. Energy Information
Administration (EIA) on Form 923.\202\ According to that data, there
were 131 natural gas-fired utility boilers \203\ in 2012 and 170 such
units in 2017. The average capacity factor for those units was only 11
percent in 2012 and 2017. Between 2012 (before the MATS compliance
date) and 2017 (after MATS was fully in effect), 39 utility boilers
converted from coal-fired units to become natural gas-fired utility
boilers. Those natural gas-fired utility boilers operated at an average
capacity factor of less than 10 percent, indicating that they were
likely utilized only during periods of high demand.
---------------------------------------------------------------------------

    \201\ See 40 CFR part 63, subpart UUUUU.
    \202\ Monthly fuel use data is submitted to the EIA on Form 923.
Available at https://www.eia.gov/electricity/data/eia923/. For
details of the EPA data analysis, see the memorandum ``2017 Fuel
Usage at Affected Coal-fired EGUs'' available in the rulemaking
Docket ID No. EPA-HQ-OAR-2017-0355.
    \203\ Natural gas-fired utility boilers are those with capacity
of more than 25 MW that use more than 90 percent natural gas on a
heat input basis.
---------------------------------------------------------------------------

    These non-air quality health and environmental impacts and energy
requirements demonstrate that refueling is not the BSER.
c. Biomass Co-Firing
    The EPA previously proposed that co-firing of biomass in coal-fired
utility boilers is not the BSER for existing fossil fuel-fired sources
due to cost and achievability considerations.\204\ Although biomass co-
firing methods are technically feasible and can be cost-effective for
some designated facilities, these factors and others (namely, that any
potential net reductions in emissions from biomass use occur outside of
the regulated source and are outside of the control of the designated
facility, which is incompatible with the interpretation of the EPA's
authority and the permissible scope of BSER as set forth in section II
above) are the considerations that prevent its adoption as the BSER for
the source category.
---------------------------------------------------------------------------

    \204\ See ACE proposal and 80 FR 64756.
---------------------------------------------------------------------------

    In the ACE proposal, the EPA sought comment on the inclusion of
forest-derived and non-forest biomass as non-BSER compliance options
for affected units to meet state plan standards.\205\ In response, the
EPA received comments both supporting and opposing the use of biomass
for compliance (as discussed in section III.F.2.b); however, commenters
also spoke to the appropriateness of including biomass firing as part
of the BSER. Some commenters noted that co-firing with biomass cannot
be a ``system of emission reduction'' as it increases CO2
emissions at the source. Commenters further asserted that the EPA has
failed to demonstrate how firing biomass meets the CAA section 111
requirements and the criteria for qualifying as a system of emission
reduction described in the Proposed Repeal and the ACE proposal.
---------------------------------------------------------------------------

    \205\ See 83 FR 44766.
---------------------------------------------------------------------------

    Upon consideration of comments and in accordance with the plain
language of CAA section 111 (discussed above in section II.B), the EPA
is now clarifying that biomass does not qualify as a system of emission
reduction that can be incorporated as part of, or in its entirety, as
the BSER. As described in section III.F.2 of this preamble. the BSER
determination must include systems of emission reduction that are
achievable at the source. While the firing of biomass occurs at a
designated facility, biomass firing in and of itself does not reduce
emissions of CO2 emitted from that source. Specifically,
when measuring stack emissions, combustion of biomass emits more mass
of emissions per Btu than that from combustion of fossil fuels, thereby
increasing CO2 emissions at the source. Recognition of any
potential CO2 emissions reductions associated with biomass
utilization at a designated facility relies on accounting for
activities not applied at and largely not under the control of that
source, including consideration of offsite terrestrial carbon effects
during biomass fuel growth, which are not a measure of emissions
performance at the level of the individual designated facility. Use of
biomass in affected units is therefore not consistent with the plain
meaning of ``standard of performance'' and cannot be considered as part
of the BSER.\206\
---------------------------------------------------------------------------

    \206\ Notwithstanding this conclusion in the context of CAA
section 111(d), the EPA believes that a PSD permitting authority may
still reach the conclusion that use of some type(s) of biomass is
BACT for greenhouse gases in the context of a PSD permit application
where the applicant proposes to use biomass, as discussed in the
EPA's Guidance for Determining Best Available Control Technology for
Reducing Carbon Dioxide Emissions from Bioenergy Production (March
2011). While biomass combustion may result in more greenhouse gas
emissions (in particular CO2) per unit of production than
combustion of fossil fuels, a comparative analysis of biomass and
other fuels may not be required in the BACT context. As EPA has
observed, ``where a proposed bioenergy facility can demonstrate that
utilizing a particular type of biogenic fuel is fundamental to the
primary purpose of the project, then at the first step of the top-
down process, permitting authorities can rely on that to determine
that use of another fuel would redefine the proposed source.''
Bioenergy BACT Guidance at 15. Moreover, even if biomass is compared
to fossil fuels and ranked lower at Step 3 of a top-down BACT
analysis, broader offsite environmental, economic, and energy
considerations related to biomass use (e.g., any potential offsite
net carbon sequestration associated with growth of the biomass
feedstock) may be considered in Step 4 of a top-down BACT analysis.
See Bioenergy BACT Guidance at 20-21. It is therefore consistent to
determine that the firing of biomass does not qualify as a
``standard of performance'' for setting or complying with the BSER
because it does not reduce the GHG emissions of a fossil fuel-fired
source, while also allowing the consideration of any potential
offsite environmental, economic, or energy attributes when
considering an application that treats biomass as BACT for a
proposed biomass facility in the PSD permitting context.
---------------------------------------------------------------------------

    Additionally, many commenters agreed with the ACE proposal that
biomass co-firing should not be part of the BSER because it is not
sufficiently cost-effective, there is not a reliable supply of biomass
fuel accessible nationally, co-firing with biomass has a negative
impact on unit heat rate, and co-firing requirements would ``redefine
the source.'' Many commenters supported inclusion of fuel co-firing as
a component of the BSER but focused primarily on argument for natural
gas co-firing (as discussed earlier). Some of these commenters
specifically asserted that biomass use is a widely available and proven
GHG reduction technology.
    As discussed by the EPA previously in the ACE proposal and other
instances,\207\ biomass fuel use opportunities are dependent upon many
regional considerations and limitations--namely fuel supply proximity,
reliability and cost--that prevent its adoption as BSER on a national
level (whereas nearly all sources can or have implemented some form of
HRI measures). The infrastructure, proximity, and cost aspects of co-
firing biomass at existing

coal EGUs are similar in nature and concept to those of natural gas.
While there are a few existing coal-fired EGUs that currently co-fire
with biomass fuel, those are in relatively close proximity to cost-
effective biomass supplies. Therefore, even if biomass firing could be
considered a ``system of emission reduction,'' the EPA is not able to
include the use of biomass fuels as part of the BSER in this action due
to the current cost and achievability considerations and limitations
discussed above. Additional discussion on biomass is provided in
section III.F.2.b. below.
---------------------------------------------------------------------------

    \207\ See 80 FR 64756.
---------------------------------------------------------------------------

d. Carbon Capture and Storage (CCS) \208\
---------------------------------------------------------------------------

    \208\ CCS is sometimes referred to as Carbon Capture and
Sequestration. It is also sometimes referred to as CCUS or Carbon
Capture Utilization and Storage (or Sequestration), where the
captured CO2 is utilized in some useful way and/or
permanently stored (for example, in conjunction with enhanced oil
recovery). In this document, the EPA considers these terms to be
interchangeable and for convenience will exclusively use the term
CCS.
---------------------------------------------------------------------------

    In the ACE proposal, the EPA noted that while CCS is an advanced
emission reduction technology that is currently under development, the
Agency must balance the promotion of innovative technologies against
their economic, energy, and non-air quality health and environmental
impacts. The EPA proposed that neither CCS nor partial CCS are
technologies that can be considered the BSER for existing fossil fuel-
fired EGUs and explicitly solicited comment on any new information
regarding the availability, applicability, costs, or technical
feasibility of CCS technologies.
    Many commenters agreed with EPA's proposed finding that CCS
(including partial CCS) should not be part of the BSER. The commenters
stated that it is not adequately demonstrated, sufficiently cost-
effective, or nationally available. Other commenters disagreed and
claimed that CCS is technically feasible and adequately demonstrated
and should be part of BSER, asserting that the EPA has previously
provided evidence in the record during the 2016 denial of petitions for
reconsideration of the CPP that CCS had been successfully implemented
at power plants. Commenters also asserted that there are many vendors
that offer carbon capture technologies for power plants, which
demonstrates that the technology is commercially available and
adequately demonstrated.
    CCS is a difficult and complicated process, requiring numerous
pieces of process equipment to capture CO2 from the exhaust
gas, compress it for transport, transport it in a CO2
pipeline, inject it, and then monitor the injection space to ensure the
CO2 remains stored. Currently there are only two large-scale
commercial applications of post-combustion CCS at a coal-fired power
plant--the Boundary Dam project in Saskatchewan, Canada and the Petra
Nova project at the W.A. Parish plant near Houston, Texas.\209\
Commenters noted that both of the demonstration projects were heavily
subsidized by government support and were able to generate additional
income from the sale of captured CO2 for enhanced oil
recovery (EOR) and, without these subsidies, neither project would have
been economically viable.
---------------------------------------------------------------------------

    \209\ Several commenters noted that the Petra Nova project
received funding from the U.S. Department of Energy (DOE) through
the Clean Coal Power Initiative and stated that the project is,
pursuant to section 402(i) of the Energy Policy Act of 2005
(EPAct05), therefore, precluded from being used to demonstrate that
the technology is ``adequately demonstrated'' under section 111 of
the CAA. Some commenters noted that the DOE funding was only for the
initial 60 MW slip-stream demonstration project, but the CCS project
at Petro Nova was later expanded to a 240 MW slip-stream and no
federal funding was received for this expansion.
---------------------------------------------------------------------------

    Commenters addressed the cost of installing CCS on an existing
coal-fired EGU and noted that it can be much costlier and more
technically challenging to retrofit the technology to an existing EGU
as compared to installation on a newly constructed unit (where the
system can be incorporated into the design and space allocation of the
new plant). Other commenters claimed that CCS can achieve significant
emission reductions (up to 90 percent), that there is opportunity for
some sources to generate income from the sale of captured
CO2, and that there are additional financial incentives from
the recently approved 2018 Internal Revenue Code (IRC) section 45Q tax
credits for stored CO2, so now CCS may be more cost-
effective than HRI options for some facilities. One commenter performed
modeling runs that included the section 45Q tax credit and found that,
for some sources, CCS would provide much greater emission reductions
than HRI options at a reasonable cost and concluded that the EPA should
include CCS as part of the BSER. Other commenters minimized the impact
of the section 45Q tax credit for a variety of reasons.
    Several commenters claimed that access to appropriate
CO2 storage locations is critical to the feasibility and
cost of CCS. They described the geographic limitations of both deep
saline aquifers and depleted oil fields (EOR fields) noting that 15
states have little or no demonstrated storage capacity or have very
limited storage capacity and that EOR sites are similarly
geographically limited, with 19 states having little or no demonstrated
EOR opportunity. However, other commenters claimed that a technology
need not be feasible at every site to be a component of BSER especially
since the EPA is relying on site-specific analyses. The commenters
noted that not all HRI options are applicable to every source, so the
EPA cannot disregard CCS from the BSER options based on ``national
availability.''
    Commenters noted that 60 GW (or about 20 percent) of the coal-fired
power plant capacity might be amenable to CCS based on locality and
that North America has widespread and abundant geologic storage options
with the capacity to sequester over 500 years of the U.S.'s current
energy-related CO2 emissions. Commenters claimed that 90
percent of existing coal-fired power plants are within 100 miles from
the center of a basin with adequate storage capacity and more than half
of the existing plants are less than 10 miles from the center of a
basin.
    The EPA has considered all these public comments and has concluded
that, as proposed, CCS is not the BSER for emissions of CO2
from existing coal-fired EGUs--nor does it constitute a component of
the BSER, as some commenters have suggested. As discussed in section
III.E.1, above, concerning the ``guiding principles'' for identifying
the BSER under CAA section 111(d), the BSER is based on what is
adequately demonstrated and broadly achievable across the country.
Under CAA section 111(b)(1), the EPA determines ``standards of
performance'' for new sources and under section 111(d)(1), the states
determine ``standards of performance'' for existing sources within
their jurisdiction. Importantly, the term ``standard of performance''
is given a uniform definition under section 111(a)(1) for purposes of
both new and existing sources, and, in accordance with that definition,
the Administrator is required to determine the BSER as a predicate for
the standards of performance for both new and existing sources. In this
manner, the text and structure of section 111 indicate that the EPA
must make the BSER determination at the national, source-category
level. Thus, the EPA disagrees with the commenters who argue that
because the EPA is emphasizing that standard setting will be done on a
unit-by-unit (rather than fleetwide) basis, all viable emission
reduction options should be evaluated at the unit level.
    Whereas HRI measures are broadly applicable to the entire existing
coal-

fired power plant fleet, the EPA determines that CCS or partial CCS is
not. The EPA agrees that there may be some existing coal-fired EGUs
that find the application of CCS to be technically feasible and an
economically viable control option, albeit only under very specific
circumstances. However, the high cost of CCS, including the high
capital costs of purchasing and installing CCS technology and the high
costs of operating it, including high parasitic load requirements,
prevent CCS or partial CCS from qualifying as BSER on a nationwide
basis.
    According to the DOE National Energy Technology Laboratory (NETL),
the incremental cost from capital expenditures alone of installing
partial or full capture CCS \210\ on a new coal-fired EGU ranged from
$626 (for 16% capture) to $2,098 (for full capture) per kW (2011
dollars).\211\ These costs are for new CCS equipment installed on a new
facility, but they fairly represent the costs of new CCS equipment
installed on an existing facility; indeed, these costs are probably
lower than the actual costs of installing new CCS equipment on an
existing facility, because the costs of retrofitting pollution controls
on an existing facility generally are greater than the costs of
installing pollution controls on a new facility. In contrast, as noted
elsewhere, the cost of the HRI that constitute the BSER for this rule
range from $25-$47 per kW (2016 dollars). Thus, the costs of partial
CCS, considering only the capital costs and not the operating costs,
are far higher than--more than 13 times--the cost of what the EPA has
identified as the BSER.
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    \210\ Full capture is considered to occur when 100 percent of
the flue gas is treated, resulting in a 90 percent reduction in
emissions of CO2 relative to a power plant without carbon capture.
    \211\ ``Cost and Performance Baseline for Fossil Energy Plants
Supplement: Sensitivity to CO2 Capture Rate in Coal-Fired Power
Plants,'' une 22, 2015; DOE/NETL-2015/1720 https://www.netl.doe.gov/projects/files/[FR Doc.SupplementSensitivitytoCO2CaptureRatein[FR
Doc.CoalFiredPowerPlants_062215.pdf.
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    Viewing the costs of CCS through other prisms yields the same
determination. According to NETL, the capital costs of a CCS system
with 90 percent capture increases the cost of a new coal-fired power
plant approximately 75 percent relative to the cost of constructing a
new coal-fired power plant without post-combustion control technology.
Furthermore, the additional auxiliary load required to support the CCS
system consumes approximately 20 percent of the power plant's potential
generation.\212\ The NETL Pulverized Coal Carbon Capture Retrofit
Database tool (April 2019) \213\ estimates that the operating costs of
existing coal-fired EGUs range from 22 to 44 $/MWh.\214\ The
incremental increase in generating costs, including the recovery of
capital costs over a 30-year period, due to CCS range from 56 to 77 $/
MWh.\215\ For reference, according to the EIA, the average electricity
price for all sectors in March of 2019 was 103.8 $/MWh.\216\ About 60
percent of these latter costs (60 $/MWh) are associated with generation
and 40 percent with transmission and distribution of the
electricity.\217\ Thus, the incremental increase in generating costs
due to CCS by itself would equal or exceed the average generation cost
of electricity for all sectors. The costs of partial CCS are less than
full CCS, but due to economies of scale, costs do not reduce as quickly
as reductions in the capture rate. For example, the capital costs of
treating only 18 percent of the flue gas (a 16 percent reduction in
emissions of CO2) are about 30 percent of the capital costs
of treating all of the flue gas (full capture or a 90 percent reduction
in emissions of CO2). Similarly, at full capture, treating
only 18 percent of the flue gas (a 16 percent reduction in emissions of
CO2) still increases the cost of electricity by about 28
percent of the increase that results from treating all of the flue
gas.\218\ Again, these costs are probably lower than the actual costs
of installing new CCS equipment on an existing facility. Not only are
these costs far higher than what the EPA has identified as the BSER,
they would almost certainly force the closure of the coal-fired power
plants that would be required to install them. Many of those plants
have a marginal profit margin, as demonstrated by the high rate of
plant closure and the relatively low amounts of operation (i.e.,
capacity factors) in recent years. Thus, these costs must be considered
exorbitant. See section III.E.1. for a discussion of the guiding
principles in determining the BSER.
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    \212\ A CCS system requires both auxiliary steam and electricity
to operate. According to NETL, a full capture system consumes 53 MW
of direct electrical load and steam that could have otherwise been
used to generate approximately 86 MW of electricity.
    \213\ https://www.netl.doe.gov/energy-analysis/details?id=2949.
    \214\ Existing coal-fired power plants have generally already
paid off the initial construction (i.e., capital) expenses.
    \215\ Variable operating costs represent approximately $15/MWh
and the remaining costs are recovered capital over a 30-year period.
The capital costs assume the power plant can recover the costs over
30 years. If the actual remaining useful life of the power plant
itself is less, the costs would be higher because the capital would
have to be recovered over a shorter time period. The average age of
the remaining coal fleet is approximately 42 years, and the average
age of retirement for coal-fired power plants is currently 54 years
(http://www.americaspower.org/wp-content/uploads/2018/03/Coal-Facts-August-31-2018.pdf). Therefore, a significant portion of the
existing coal-fired will likely retire in less than 30 years.
    \216\ https://www.eia.gov/electricity/monthly/epm_table_grapher.php?t=epmt_5_6_a.
    \217\ https://www.eia.gov/outlooks/aeo/data/browser/#/?id=8-AEO2019&cases=ref2019&sourcekey=0.
    \218\ ``Cost and Performance Baseline for Fossil Energy Plants
Supplement: Sensitivity to CO2 Capture Rate in Coal-Fired
Power Plants,'' June 22, 2015; DOE/NETL-2015/1720.
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    As noted above, the Boundary Dam project in Saskatchewan, Canada
and the Petra Nova project at the W.A. Parish plant near Houston, Texas
are the only large-scale commercial applications of post-combustion CCS
at a coal-fired power plant. They both have retrofit CCS or partial
CCS, and they both received significant governmental subsidies--
including, for the Petra Nova project, both direct federal grants from
the DOE through the Clean Coal Power Initiative and the IRC section 45Q
tax credits--and relied on nearby EOR opportunities. Due to the high
costs of CCS, all of these subsidies and EOR opportunities were
essential to the commercial viability of each project.\219\
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    \219\ The EPA discussed the government funding and the EOR
revenue from the transport of captured CO2 to the
Hilcorp's West Ranch Oil Field in ``Standards of Performance for
Greenhouse Gas Emissions from New, Modified, and Reconstructed
Stationary Sources: Electric Generating Units,'' 80 FR 64510, 64551
(October 23, 2015).
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    Some commenters have asserted that the costs of CCS are reasonable
and explain, as a central part of their assertion, that the
availability of tax credits under section 45Q, as revised by the
Bipartisan Budget Act of 2018, significantly lowers the costs of CCS.
In fact, they have asserted, that the tax credits, which have an
initial value of $35 per tonne (i.e., metric ton) for CO2
stored through EOR, offset about 70% of the cost of CCS, with EOR
offsetting the rest.\220\ However, the section 45Q tax credits are
limited in time: The credit for equipment placed in service after the
date of enactment of the Bipartisan Budget Act of 2018 is available, in
general, only for facilities and equipment for which construction
begins before January 1, 2024. IRC section 45Q(d)(1). Under the present
rule, state plans are not required to be submitted until mid-2022 and
the states have the authority to determine their sources' compliance
schedule; compliance schedules are generally expected to last 24 months
(i.e., until mid-2024), but could in some instances be longer, as noted
in preamble section

III.F.1.a.(2).\221\ In order for sources to implement CCS and be able
to rely on the 45Q tax credit, they would have to complete all
planning, including arranging all financing, preconstruction
permitting, and commence construction within about 18 months (by
December 31, 2023) of the state plan submittal. The EPA considers that
timetable to be impracticably short for most sources, considering the
complexity of implementation of CCS. In addition, the tax credit is, in
general, available only for the 12-year period beginning on the date
the equipment is originally placed in service. IRC section 45Q(a)(3)-
(4). Thus, it would not be available to offset much of the capital
costs of the CCS systems that are recovered over a 30-year period.\222\
Further, like any federal income tax credit, the 45Q tax credits do not
provide a benefit to a company that does not owe federal income tax,
and thus it may not benefit some coal-fired power plant owners.
Accordingly, the 45Q tax credits cannot be considered to offset the
high costs of CCS for the industry as a whole. While nearby EOR
opportunities are available for some EGUs, they alone cannot offset the
high costs of CCS, as is evident from the comments discussed above.
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    \220\ EPA-HQ-OAR-2017-0355-24266 at 18.
    \221\ By comparison, the implementation period for the CPP began
three years after the state plan submittal. See 80 FR at 64669.
    \222\ The NETL Pulverized Coal Carbon Capture Retrofit Database
tool (April 2019) defaults to a capital recovery factor based on 30
years. Capital recovery factors based on 10 and 20 years are also
selectable. If shorter periods are selected, the $/MWh for capital
recovery would be higher. Table 10-12 of The Integrated Planning
Model (version 6) uses a 15-year capital recovery factor for
environmental retrofits, https://www.epa.gov/sites/production/files/2019-03/documents/chapter_10.pdf. Recovering costs over a 12-year
period, as opposed to a 30-year period, increased the capital
recovery factor by 40 percent.
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    In addition, nearby EOR opportunities are not available for many
EGUs, which, as a result, would incur higher costs for constructing and
operating pipelines to transport CO2 long distances.
Throughout the country, 29 states are identified as having oil
reservoirs amenable to EOR, of which only 12 states have active EOR
operations.\223\ The vast majority of EOR is conducted in oil
reservoirs in the Permian Basin, which extends through southwest Texas
and southeast New Mexico. States where EOR is utilized include Alabama,
Arkansas, Colorado, Louisiana, Michigan, Mississippi, Montana, New
Mexico, Oklahoma, Texas, Utah, and Wyoming, whereas coal-fired
generation capacity is located across the country.\224\ For example,
Georgia, Minnesota, Missouri, Nevada, North Carolina, South Carolina,
and Wisconsin have coal-fired generation capacity but do not have oil
reservoirs that have been identified as amenable for EOR. In addition,
some of the states with the largest amounts of coal-fired generation
capacity have no active EOR operations, including Illinois, Indiana,
Kentucky, Ohio, Pennsylvania, Tennessee, Virginia, and West Virginia.
Even in states that are identified as having potential oil and gas
storage capacity, the amount of storage resource varies by state. In
some states, the total oil and gas storage resource is smaller than the
annual energy-related CO2 emissions from coal, including
Indiana and Virginia.\225\ The limited geographic availability of EOR,
and the consequent high costs of CCS for much of the coal fleet, by
itself means that CCS cannot be considered to be available across the
existing coal fleet.
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    \223\ The United States 2012 Carbon Utilization and Storage
Atlas, Fourth Edition, U.S. Department of Energy, Office of Fossil
Energy, National Energy Technology Laboratory (NETL) and EPA
Greenhouse Gas Reporting Program, see https://www.epa.gov/ghgreporting.
    \224\ U.S. Energy Information Administration, Electric Power
Annual 2017, see https://www.eia.gov/electricity/annual/pdf/epa.pdf.
    \225\ The United States 2012 Carbon Utilization and Storage
Atlas, Fourth Edition, U.S. Department of Energy, Office of Fossil
Energy, National Energy Technology Laboratory (NETL) and U.S. Energy
Information Administration, Energy-Related Carbon Dioxide Emissions
by State, 2005-2016, see https://www.eia.gov/environment/emissions/state/analysis/.
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    The high costs of CCS inform the Administrator's determination that
this technology is not BSER. Some commenters have suggested that CCS be
treated as BSER for some facilities on a unit-by-unit basis, but the
EPA believes that this would be inconsistent with its role under
section 111(a)(1) to determine as a general matter what is the BSER
that has been adequately demonstrated, taking into account, among other
factors, cost. To treat CCS as BSER for a handful of facilities would
result in those facilities becoming subject to high costs from CCS--
potentially much higher than those imposed on other facilities for whom
CCS is not treated as BSER. This potential disparate impact of costs is
inconsistent with the Administrator's role in determining BSER and is
another reason why the Administrator is finalizing a determination that
CCS is not BSER.
    Nevertheless, while many commenters argued that CCS should not be
considered part of the BSER, they supported its use as a potential
compliance option for meeting an individual unit's standard of
performance. The EPA agrees with this assessment. Evaluation of the
technical feasibility (e.g., space considerations, integration issues,
etc.) and the economic viability (e.g., the prospects and availability
of long-term contractual arrangements for sale of captured
CO2, the cost of constructing a CO2 pipeline, the
availability of tax credits, etc.) of a CCS project is heavily
dependent on source-specific characteristics. Accordingly, state plans
may authorize such projects for compliance with this rule.

F. State Plan Development

1. Establishing Standards of Performance
    CAA sections 111(d)(1) and 111(a)(1) collectively establish and
define certain roles and responsibilities for the EPA and the states.
As discussed in section III.B above, the EPA has the authority and
responsibility to determine the BSER. CAA section 111(d)(1) clearly
contemplates that states will submit plans that establish standards of
performance for designated facilities (i.e., existing sources).
    States have broad flexibility in setting standards of performance
for designated facilities. However, there is a fundamental obligation
under CAA section 111(d) that standards of performance reflect the
degree of emission limitation achievable through the application of the
BSER, which derives from the definition for purposes of section 111 of
``standard of performance'' in those terms, with no distinction made
between new-source and existing-source standards. In establishing such