solicitation.
    Anti-Circumvention Provisions. EPA is proposing to add provisions
to the regulations that would prevent facilities from circumventing the
effluent limitations guidelines and standards. The proposed provisions
would do three things, as described below.
    First, the anti-circumvention provision would require that
compliance with the new effluent limits applicable to a particular
wastestream (e.g., FGD, gasification wastewater, leachate) be
demonstrated prior to use of the wastewater in another plant process
that results in surface water discharge or mixing the treated
wastestream with other wastestreams. Under 40 CFR 122.45(h), in
situations where an NPDES permit effluent limitations or standards
imposed at the point of discharge are impractical or infeasible,
effluent limitations or standards may be imposed on internal
wastestreams before mixing with other wastestreams or cooling water
streams. Limitations on internal wastestreams may be necessary, such as
in situations where the wastes at the point of discharge are so diluted
as to make monitoring impracticable, or the interferences among
pollutants would make detection or analysis impracticable. Many power
plants combine FGD wastewater and other power plant wastewaters with
ash transport water and/or cooling water prior to discharge, which can
dilute the wastewaters by several orders of magnitude prior to the
final outfall. In addition, surface impoundments typically contain a
variety of wastes (e.g., ash transport water, coal pile runoff,
landfill/impoundment leachate) that when mixed with the FGD wastewater
or gasification wastewater may make the analysis to measure compliance
with technology-based effluent limits impracticable. Because of the
high degree of dilution and the number of wastestream sources
containing similar pollutants, effluent

limits and monitoring requirements for certain internal wastestreams
(e.g., FGD wastewater, combustion residual leachate, gasification
wastewater) are necessary to ensure appropriate control of the
pollutants present in the wastewater. EPA requests comment on the
extent, if any, to which this provision may discourage water re-use.
    Second, the anti-circumvention provision would establish
requirements intended to prevent steam electric power plants from
circumventing the effluent limits and standards by moving effluent
produced by a process operation for which there is a zero discharge
effluent limit/standard to another process operation for discharge
under less stringent requirements than intended by the steam electric
ELGs. For example, several options (including Option 3a) considered in
this rulemaking would establish a zero discharge requirement for
pollutants in fly ash transport water and FGMC wastewater. If this
option were selected for the final rule, the anti-circumvention
provisions would allow power plants to recycle/reuse these wastestreams
in ash transport processes or other plant processes, but only to the
extent that the plants do not discharge any pollutants associated with
flue gas mercury controls or transporting fly ash. The presence of a
zero discharge wastestream in a process that ultimately discharges to
surface water (e.g., use of fly ash transport water as FGD absorber
make-up water in a scrubber that discharges FGD wastewater) would not
be in compliance with the effluent limit. EPA requests comment on the
extent to which this provision may discourage water re-use.
    Last, the anti-circumvention provisions would expressly require
permittees to use analytical EPA-approved methods that are sufficiently
sensitive to provide reliable quantified results at levels necessary to
demonstrate compliance with the effluent limits proposed by this
rulemaking when such methods are available. EPA's detailed study and
the field sampling for this rulemaking demonstrate that the use of
sufficiently sensitive analytical methods is critically important to
detecting, identifying, and measuring the concentrations of pollutants
present in power plant wastewaters. Where EPA has approved more than
one analytical method for a pollutant, the Agency expects that
permittees would select methods that are able to quantify the presence
of pollutants in a given discharge at concentrations that are low
enough to determine compliance with effluent limits, when such methods
are available. Facilities should not use a less sensitive or less
appropriate method, thus masking the presence of a pollutant in the
discharge, when an EPA-approved method is available that can quantify
the pollutant concentration at the lower levels needed for
demonstrating compliance. For purposes of the proposed anti-
circumvention provision, a method is ``sufficiently sensitive'' when
the sample-specific quantitation level \23\ for the wastewater being
analyzed is at or below the level of the effluent limitation. Allowing
plants to use insufficiently sensitive analytical methods for
compliance monitoring purposes when EPA-approved sufficiently sensitive
methods are available could result in an undetected exceedance of the
effluent limits.
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    \23\ For the purposes of this rulemaking, EPA is considering the
following terms related to analytical method sensitivity to be
synonymous: ``quantitation limit,'' ``reporting limit,'' ``level of
quantitation,'' and ``minimum level.''
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    BMPs for CCR Surface Impoundments. EPA is considering establishing
BMPs for plant operators to conduct periodic inspections of active and
inactive surface impoundments and to take corrective actions where
warranted. This requirement would apply to direct dischargers. For new
sources, EPA would be relying on CWA section 306, which authorizes the
promulgation of standards of performance for new sources. For existing
sources, EPA would be relying on CWA section 304(e), which authorizes
BMPs supplemental to ELGs for toxic or hazardous pollutants to control
plant site runoff, spillage or leaks, sludge or waste disposal, and
drainage from raw material storage which the Administrator determines
are associated with or ancillary to the industrial process and may
contribute significant amounts of pollutants to the nation's waters.
And CWA section 402(a) (2) authorizes the imposition of conditions,
which would include BMPs and monitoring requirements, necessary to
ensure compliance with all other applicable requirements. EPA's
regulation at 40 CFR 122.44(k) implements these authorities.
Specifically, 40 CFR 122.44(k) allow for NPDES permits to require the
use of BMPs to control and abate the discharge of toxic pollutants.
Existing regulations at 40 CFR 122.41(e) further require that NPDES
permittees properly operate and maintain all facilities and systems of
treatment and control used to achieve compliance with their permits.
This action provides notification that EPA is considering establishing
BMP requirements to address impoundment construction, operation, and
maintenance in the final ELG rule using CWA authority. Using CWA
authority, EPA could establish the BMPs as part of the ELGs (BAT and
NSPS) codified at 40 CFR part 423, and thus these BMPs would be
implemented through NPDES permits. Structural integrity requirements
that seek to reduce the potential for catastrophic releases from
surface impoundments could, alternatively, be established using RCRA
authority. The BMPs under consideration in this rulemaking are similar
to the structural integrity inspection and corrective active
requirements proposed in the CCR rulemaking, but do not include closure
requirements that were proposed as part of the CCR rulemaking.
    The Agency believes that the BMP requirements being considered by
the Agency in this rulemaking and in the CCR rulemaking are critical to
ensure that the owners and operators of surface impoundments become
aware of any problems that may arise with the structural stability of
the surface impoundment before they occur and, thus, prevent
catastrophic releases, such as those that occurred at Martins Creek,
Pennsylvania and TVA's Kingston, Tennessee facility.
    The BMPs being considered by EPA in this rulemaking would require,
first, that inspections be conducted every seven days by a person
qualified to recognize specific signs of structural instability and
other hazardous conditions by visual observation and, if applicable, to
monitor instrumentation such as piezometers. If a potentially hazardous
condition develops, the owner or operator shall immediately take action
to eliminate the potentially hazardous condition; notify the Regional
Administrator or the authorized State Director; and notify and prepare
to evacuate, if necessary, all personnel from the property that may be
affected by the potentially hazardous condition(s). Additionally, the
owner or operator must notify state and local emergency response
personnel if conditions warrant so that people living in the area down
gradient from the surface impoundment can evacuate. Reports of
inspections are to be maintained in the facility operating record.
    Second, to address the integrity of surface impoundments, EPA would
establish BMPs for CCR surface impoundments similar to those
promulgated for coal slurry impoundments regulated by the Mine Safety
and Health Administration (MSHA) at 30 CFR 77.216. Although the

MSHA regulations are applicable to coal slurry impoundments at coal
mines and not to the impoundments containing CCR at power plants, there
are sufficient similarities between coal slurry and CCR impoundments
for the MSHA regulations to be used as a model for the BMP requirements
being considered for the ELG rule. Facilities using CCR impoundments
would need to (1) submit to EPA or the authorized state plans for the
design, construction, and maintenance of existing impoundments, (2)
submit to EPA or the authorized state plans for closure, (3) conduct
periodic inspections by trained personnel who are knowledgeable in
impoundment design and safety, and (4) provide an annual certification
by an independent registered professional engineer that all
construction, operation, and maintenance of impoundments is in
accordance with the approved plan. When problematic stability and
safety issues are identified, owners and operators would be required to
address these issues in a timely manner.
    In developing these possible structural integrity BMP requirements,
EPA sought advice from the federal agencies charged with managing the
safety of dams in the United States. Many agencies in the federal
government are charged with dam safety, including the U.S. Department
of Agriculture (USDA), the Department of Defense (DOD), the Department
of Energy (DOE), the Nuclear Regulatory Commission (NRC), the
Department of Interior (DOI), and the Department of Labor (DOL), MSHA.
EPA looked particularly to MSHA, whose charge and jurisdiction appeared
to EPA to be the most similar to the Agency's in this context. MSHA's
jurisdiction extends to all dams used as part of an active mining
operation and their regulations cover ``water, sediment or slurry
impoundments'' so they include dams for waste disposal, freshwater
supply, water treatment, and sediment control. In fact, MSHA's current
impoundment regulations were created as a result of the dam failure at
Buffalo Creek, West Virginia on February 26, 1972. (This failure
released 138 million gallons of stormwater run-off and fine coal
refuse, and resulted in 125 persons killed, another 1,000 injured, over
500 homes completely destroyed, and nearly 1,000 others damaged.)
    MSHA has nearly 40 years of experience writing regulations and
inspecting dams associated with coal mining. MSHA's regulations are
comprehensive and directly applicable to the dams used in surface
impoundments at coal-fired utilities to manage CCRs. EPA believes that,
based on the record compiled by MSHA for its rulemaking, and on MSHA's
40 years of experience implementing these regulations, the requirements
being considered in this rulemaking would substantially reduce the
potential for catastrophic release of CCRs from surface impoundments,
as occurred at TVA's facility in Kingston, Tennessee, and would
generally meet RCRA's objective to ensure the protection of humans and
the environment.\24\ Thus, EPA is considering establishing BMPs that
would be modeled on MSHA regulations in 30 CFR part 77.
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    \24\ On December 22, 2008, the retention wall of a coal ash
impoundment at Tennessee Valley Authority's Kingston Plant
collapsed, which resulted in a massive release of CCRs directly into
the Emory River and its tributaries. The Emory River joins to the
Clinch River and then converges with the Tennessee River, a major
drinking water source for populations downstream. This failure
released over a billion gallons of fly ash and bottom ash, which
impacted over 100 properties, destroyed three homes, and ruptured a
gas line resulting in the evacuation of 22 residents.
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    MSHA's regulations for coal slurry impoundments apply to those
impoundments at coal mines, which impound water, sediment or slurry to
an elevation of more than five feet and have a storage volume of 20
acre-feet or more and those coal slurry impoundments that impound
water, sediment, or slurry to an elevation of 20 feet or more. The BMPs
being considered today for the ELG rule would apply to all CCR
impoundments at steam electric power generating facilities, regardless
of height and storage volume. EPA is also considering variations on
BMPs for the ELGs, including, but not limited to, different inspection
frequencies or limitations on the applicability of BMPs that more
closely mirror the applicability of the MSHA regulations. EPA requests
comment on possible BMPs for inclusion in a final ELG rule including
those described above and any other appropriate variations on them.
    Voluntary Incentive Program for Power Plants That Close CCR
Impoundments or Eliminate All Process Wastewater Discharges (Except
Cooling Water). EPA is considering establishing, as part of the BAT for
existing sources, a voluntary incentive program that provides more time
for plants to implement the proposed BAT requirements if they adopt
additional process changes and controls that provide significant
environmental protections beyond those achieved by the preferred
options for this proposed rule. The development of advanced process
changes and controls is a critical step toward the Clean Water Act's
ultimate goal of eliminating the discharge of pollutants into the
Nation's waters. See CWA Section 101(a)(1). Section 301(b)(1)(C)
demands that BAT result in ``reasonable further progress toward the
national goal of eliminating the discharge of pollutants.'' EPA intends
that, for any BAT option that is ultimately selected as part of any
final ELG rule, such option would represent ``reasonable further
progress,'' while the voluntary incentives program is designed to
continue progress toward achieving the national goal of the Act. In
addition, Section 104(a)(1) of the Act gives the Administrator
authority to establish national programs for the prevention, reduction,
and elimination of pollution, and it provides that such programs shall
promote the acceleration of research, experiments, and demonstrations
relating to the prevention, reduction, and elimination of pollution.
The voluntary incentives program being considered today would
effectively accelerate the research into and use of controls and
processes intended to prevent, reduce, and eliminate pollution because
it would increase the number of plants choosing to close and cap CCR
surface impoundments and eliminate discharges of all process wastewater
(except cooling water) to surface waters.
    This voluntary program would establish two levels, or ``tiers,'' of
advanced technology performance requirements which would be
incorporated into the NPDES permits for the facilities that participate
in the program. Under Tier 1, power plants would be granted two
additional years (beyond the time described below in Section VIII.B) if
they also dewater, close and cap all CCR surface impoundments (except
for those impoundments containing only combustion residual leachate) at
the facility, including those surface impoundments located on non-
adjoining property that receive CCRs from the facility. A power plant
participating in the Tier 1 program could continue to operate surface
impoundments for which combustion residual leachate is the only type of
CCR solids or wastewater contained in the impoundment. In general,
power plants accepted in the Tier 1 incentives program would first
convert ash handling operations to dry handling or closed-loop tank-
based systems and FGD wastewater treatment operations to tank-based
systems, as described above in Section VI. This first step would
eliminate new contributions of CCRs (solids and wastewater) to the
surface impoundments. The plants would then dewater the impoundments by
draining

or pumping the wastewater from the impoundments, in compliance with the
ELGs and other requirements established in their NPDES permits. Upon
completing the dewatering operations, plants would then stabilize the
contents and close and cap the impoundments consistent with state
requirements and any other additional requirements that may be
established by EPA as part of the Tier 1 incentives program or other
applicable requirements.
    Under Tier 2, power plants would be granted five additional years
(beyond the time described below in Section VIII.B) if they eliminate
the discharge of all process wastewater to surface waters, with the
exception of cooling water discharges. The Tier 2 incentives would not
be available to power plants that eliminate direct discharge to surface
water by sending the wastewater to a POTW. A plant accepted into the
Tier 2 incentives program would ultimately need to manage its processes
and wastewater in a manner that implements a coordinated approach
toward wastewater minimization, treatment and reuse. To achieve Tier 2
status, these plants would eliminate all process wastewater discharges
(except cooling water) by reducing the amount of wastewater generated
and preferentially using recycled wastewater to meet water supply
demands. To accomplish this, Tier 2 plants would conduct engineering
assessments of the processes that generate wastewater and identify
opportunities to eliminate or reduce the amount of wastewater they
generate. These plants would also assess the processes that use water
and determine how they could use recycled wastewater in those
processes, as well as the degree of treatment that may be needed to
enable such reuse. Based on responses to the industry survey, EPA has
identified a number of steam electric power plants that currently
discharge no process wastewater. In addition, two of the plants that
EPA visited in Italy previously discharged process wastewater, but have
implemented wastewater treatment and process changes, including
wastewater recycle, that now allow them to operate without discharging
any process wastewater except for their cooling water.
    The primary objective of this program is to encourage individual
power plants to install advanced pollution prevention technologies or
make process changes that would further reduce releases of toxic
pollutants to the environment beyond the limits that would be set by
the proposed rule. The voluntary incentive program being considered is
designed to promote improvements that, in concert with other
environmental practices, make significant progress toward achieving
EPA's vision of the ``power plant of the future''--one which will have
a minimum impact on the environment. This program would give power
plants a platform to advance the research and development of
technologies and processes that promote water conservation and water
recycling and provide greater environmental protection. EPA has
conducted site visits at power plants that have implemented processes
that eliminate the use of water or recycle process wastewater to a
substantial degree. Furthermore, as noted above, EPA observed
operations at power plants that implemented process modifications and
treatment technologies that eliminated all discharges of process
wastewater with the exception of their cooling water. Implementing such
practices at other power plants would dramatically reduce discharges of
toxic and other pollutants. These practices would also substantially
reduce the amount of water consumed or used by the plant, which could
be an important consideration for addressing water availability and
other concerns. In exchange for providing additional time for power
plants to comply with the proposed BAT limitations, the program would
lead to superior effluent quality and greater environmental protection.
    Participation in the program would be voluntary and it would be
available only to existing power plants that discharge directly to
surface waters. Power plants would have until July 1, 2017
(approximately 3 years after promulgation of the final ELGs) to commit
to the program and submit a plan for achieving the Tier 1 or Tier 2
requirements. Once a power plant enrolls in the program, the NPDES
permitting authority would develop specific discharge limits and key
milestones consistent with that tier.
    Power plants enrolled in the program would ultimately be agreeing
to adopt NPDES permit limits that are more stringent than those that
would be required by the proposed and final BAT in exchange for
additional time to comply with their new effluent limitations. These
power plants and their corporate owners would also receive public
recognition for their commitment to increased environmental protection.
    EPA considered including features of the Tier 1 and Tier 2
incentives as part of the options for the proposed rule. However,
although EPA has observed these practices in operation and they are
available for at least a portion of the industry, the degree of
complexity will vary from plant to plant and EPA does not have the
site-specific information that could be used to sufficiently assess how
that complexity may affect the engineering challenges and costs that
plants would encounter. EPA requests comment on the voluntary
incentives program described in this section and any appropriate
variations.
3. Rationale for the Proposed Best Available Technology (BAT)
    BAT represents the best available economically achievable
performance of facilities in an industrial subcategory or category
taking into account factors specified in the CWA. The CWA factors
considered in assessing BAT are the cost of achieving BAT effluent
reductions, the age of equipment and facilities involved, the process
employed, potential process changes, and non-water quality
environmental impacts, including energy requirements and such other
factors as the Administrator deems appropriate. See Section
304(b)(2)(B). In addition to technological availability, economic
achievability is also a factor considered in setting BAT. See Section
301(b)(2)(A).
    After considering all of the technologies described in Section
VII.B.2, in light of the factors specified in Section 304(b)(2)(B) and
Section 301(b)(2)(A) of the CWA, as appropriate, EPA is putting forth
four preferred alternatives for BAT. These four preferred alternatives
primarily differ in that some would establish more environmentally
protective BAT requirements for discharges from two of the wastestreams
from existing sources. Under the first preferred alternative, EPA is
proposing to establish BAT effluent limits based on the technologies
specified in Option 3a. With the exception of oil-fired generating
units and small generating units (i.e., 50 MW or smaller), the proposed
rule under Option 3a would:
     Establish a ``zero discharge'' effluent limit for all
pollutants in fly ash transport water and FGMC wastewater;
     Establish numeric effluent limits for mercury, arsenic,
selenium, and TDS in discharges of gasification wastewater;
     Establish numeric effluent limits for copper and iron in
discharges of nonchemical metal cleaning wastes \25\;
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    \25\ As described later in this section, EPA is proposing to
exempt from new BAT copper and iron limitations existing discharges
of nonchemical metal cleaning wastes that are currently authorized
under their existing NPDES permit without iron and copper limits.
For these discharges, BAT limits would be set equal to BPT limits
for low volume waste.
---------------------------------------------------------------------------

     Establish BAT effluent limits for bottom ash transport
water and

combustion residual leachate that are equal to the current BPT effluent
limits for these discharges (i.e., numeric effluent limits for TSS and
oil and grease; and
     BAT for discharges of FGD wastewater would continue to be
determined on a site-specific basis.
    Under the second preferred alternative for BAT, EPA is proposing to
establish BAT effluent limits based on the technologies specified in
Option 3b. With the exception of oil-fired generating units and small
generating units (i.e., 50 MW or smaller), the proposed rule under
Option 3b would:
     Establish numeric effluent limits for mercury, arsenic,
selenium, and nitrate-nitrite in discharges of FGD wastewater for units
located at plants with a total wet-scrubbed capacity of 2,000 MW or
more 26 27;
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    \26\ Total plant-level wet-scrubbed capacity is calculated by
summing the nameplate capacity for all of the units that are
serviced by wet FGD systems.
    \27\ For units below the 2,000 MW threshold, BAT would continue
to be determined on a site-specific basis.
---------------------------------------------------------------------------

     Establish a ``zero discharge'' effluent limit for all
pollutants in fly ash transport water and FGMC wastewater;
     Establish numeric effluent limits for mercury, arsenic,
selenium, and TDS in discharges of gasification wastewater;
     Establish numeric effluent limits for copper and iron in
discharges of nonchemical metal cleaning wastes \28\; and
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    \28\ As described later in this section, EPA is proposing to
exempt from new BAT copper and iron limitations existing discharges
of nonchemical metal cleaning wastes that are currently authorized
under their existing NPDES permit without iron and copper limits.
For these discharges, BAT limits would be set equal to BPT limits
for low volume wastes.
---------------------------------------------------------------------------

     Establish BAT effluent limits for bottom ash transport
water and leachate that are equal to the current BPT effluent limits
for these discharges (i.e., numeric effluent limits for TSS and oil and
grease).
    Under the third preferred alternative for BAT, EPA is proposing to
establish BAT effluent limits based on the technologies specified in
Option 3. In addition to the requirements described for Option 3b, the
proposed rule would establish the same numeric effluent limits as in
Option 3b for mercury, arsenic, selenium, and nitrate-nitrite in
discharges of FGD wastewater from units located at all steam electric
facilities, with the exception of oil-fired generating units and small
generating units (i.e., 50 MW or less).
    Under the fourth preferred alternative for BAT (Option 4a), in
addition to the requirements described for Option 3, the proposed rule
would establish ``zero discharge'' effluent limits for all pollutants
in bottom ash transport water from units greater than 400 MW.
    For oil-fired generating units and small generating units (i.e., 50
MW and smaller) that are existing sources, under all four preferred
options, EPA is proposing to set the BAT effluent limits equal to the
current BPT effluent limits for copper and iron for nonchemical metal
cleaning wastes,\29\ and for TSS and oil and grease for five of the six
wastestreams listed above (i.e., FGD wastewater, fly ash transport
water, FGMC wastewater, leachate from landfills and surface
impoundments containing combustion residuals, and gasification
wastewater). EPA is proposing Options 3a, 3b, 3 and 4a as the preferred
BAT regulatory options because its analysis to this date suggests that
they are all technologically available, economically achievable, and
have acceptable non-water quality environmental impacts. However, EPA
is putting forth a range of options as candidates for BAT in order to
enhance the Agency's understanding of the pros and cons of each of
these options in light of the statutory factors through the public
comment process and intends to evaluate this information and how it
relates to the factors specified in the CWA. As discussed above in
Sections VI and VIII.A.2, the data in EPA's record and its analysis to
date suggests that all four options are technologically available.
EPA's record indicates that the technologies comprising Options 3a, 3b,
3, and 4a are well-demonstrated and have been employed at a subset of
existing power plants.
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    \29\ As described later in this section, EPA is proposing to
exempt from new BAT copper and iron limitations existing discharges
of nonchemical metal cleaning wastes that are currently authorized
under their existing NPDES permit without iron and copper limits.
For these discharges, BAT limits would be set equal to BPT limits
for low volume waste.
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    Under all of the preferred options, the technology basis for fly
ash transport water is dry handling. All generating units built in the
30 years since the ELGs were last revised in 1982 have been subject to
a zero discharge standard for the pollutants in fly ash transport
water, in nearly all cases installing dry fly ash handling technologies
to comply with the standard. In addition, many other generating units
that could discharge their fly ash transport water upon meeting a TSS
effluent limit have instead retrofitted the dry fly ash handling
technology to meet operational needs or for economic reasons.
Approximately 40 percent of the plants that were operating wet-sluicing
systems in 2000 have converted generating units to dry fly ash
(approximately 115 generating units at 45 power plants). Another 61
generating units are slated to convert to dry fly ash handling by 2020.
Based on data collected by the industry survey, approximately 66
percent of coal- and petroleum coke-fired generating units handle all
fly ash with dry technologies. Another 15 percent of coal- and
petroleum coke-fired generating units have both wet and dry fly ash
handling systems (typically, the wet system is a legacy system that the
plant has not decommissioned following retrofit with a dry system).
Only 19 percent of coal- and petroleum coke-fired generating units
exclusively use a wet fly ash handling system. Furthermore, some of
these plants with wet fly ash handling systems manage the ash handling
process so that they do not discharge fly ash transport water. As a
result, EPA determined that only 13 percent of coal-fired power plants
would incur costs to comply with a BAT zero discharge requirement for
fly ash transport water. See Section 9.7.3 of the TDD.
    Power plants recently began installing FGMC systems either to
comply with state requirements or to prepare for emissions limits
established by the MATS rule. Plants using sorbent injection systems
(e.g., activated carbon injection) typically handle the spent sorbent
in the same manner as their fly ash. Nearly all plants with FGMC
systems use dry handling technologies. Only a few plants use wet
systems to transport the spent sorbent to disposal in surface
impoundments. Based on the industry survey, the plants using wet
handling systems currently operate them as closed-loop systems and do
not discharge FGMC wastewater to surface waters, or have the capability
to do so. These plants could continue to operate these wet systems as
closed-loop systems, or could convert to dry handling technologies by
managing the fly ash and spent sorbent together in a retrofitted dry
system (the wastes are currently managed together in the impoundments)
or by installing dedicated dry handling equipment for the FGMC wastes
similar to the equipment used for fly ash.
    The technology basis for control of discharges of FGD wastewater
under Options 3, 3b (for units located at plants with a total wet-
scrubbed capacity of 2,000 MW or more), and 4a is chemical
precipitation followed by anaerobic biological treatment. Four power
plants, or approximately three percent of wet-scrubbed power plants
that discharge FGD wastewater already have the

Options 3b (for units located at plants with a total wet-scrubbed
capacity of 2,000 MW or more), 3 and 4a BAT technology in place. Under
Options 3b (for units located at plants with a total wet-scrubbed
capacity of 2,000 MW or more), 3, and 4a, in addition to other new
requirements that would be established, numeric limits would be
established for toxic discharges including arsenic, mercury, and
selenium from FGD wastewater.
    The technology used as the basis for FGD wastewater treatment under
Options 3b (for units at plants with a total wet-scrubbed capacity of
2,000 MW or more), 3 and 4a has been tested at power plants for more
than 10 years and full-scale systems have been operating at a subset of
plants for 5 years. The biological treatment processes used in the
bioreactor portion of the treatment technology have been widely used in
many industrial applications for decades both in the U.S. and
internationally. Five steam electric power plants operate fixed-film
anoxic/anaerobic biological treatment systems to treat FGD wastewater
and another operates a suspended growth biological treatment system
that targets removal of selenium.\30\ Other power plants are
considering installing the biological treatment technology to remove
selenium and at least one plant is moving forward with construction.
See DCN SE03874. In addition, four additional power plants currently
operate anaerobic biological treatment systems for their FGD
wastewater, indicative that this is available technology. EPA is aware
of industry concerns with the feasibility of biological treatment at
some power plants. Specifically, industry has asserted that the
efficacy of these systems is unpredictable, and is subject to
temperature changes, high chloride concentrations, and high oxidation
reduction potential in the absorber (which may kill the treatment
bacteria). EPA's record to date does not support these assertions, but
is interested in additional information that addresses these concerns.
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    \30\ Four of the six operate the biological treatment systems in
combination with chemical precipitation.
---------------------------------------------------------------------------

    More than one-third of plants that discharge FGD wastewater utilize
chemical precipitation (in some cases, also using additional treatment
steps). As noted above, four power plants currently operate chemical
precipitation systems in combination with anaerobic biological
treatment systems. The chemical precipitation treatment processes
included in the FGD wastewater technology basis for these options are
used at 24 percent of steam electric power plants that discharge FGD
wastewater (and another 11 percent of plants also use chemical
precipitation systems that could be upgraded to this technology basis)
and also at thousands of industrial facilities nationwide (See Section
8.1.3 of the TDD).\31\
---------------------------------------------------------------------------

    \31\ Physical/chemical treatment systems can be effective at
removing mercury and certain other metals; however, to achieve
effective removal of selenium this technology must be coupled with
additional treatment technology such as anoxic/anaerobic biological
treatment.
---------------------------------------------------------------------------

    Option 3b proposes limitations based on this technology for units
at the largest plants (as determined by a 2,000 MW total wet-scrubbed
capacity threshold), and BAT for the control of discharges of FGD
wastewater from units at plants below this threshold would continue to
be determined on a site-specific basis. For FGD wastewater only, EPA
believes any threshold should be based on a plant level rather than a
unit level because many plants currently use a single FGD treatment
systems to service multiple units. Additionally, EPA determined that
wet-scrubbed capacity is an appropriate metric because it only reflects
units that are generating FGD wastewater. For example, a plant could
have a total plant nameplate generating capacity of 3,500 MW, but only
have a wet-scrubbed capacity of 200 MW if only one of its units is wet-
scrubbed. EPA is putting forth this option as a preferred option based
on an assumption that these facilities are more able to achieve these
limits based on economies of scale. These largest facilities will
likely also be able to absorb the costs of installing and operating the
chemical precipitation and anaerobic biological treatment systems on
which the FGD wastewater limitations are based. For these reasons, as
well as those specified above related to current innovation and
treatment trends, Option 3b proposes that BAT effluent limitations for
discharges of FGD wastewater would continue to be determined on a site-
specific basis for units at facilities below the 2,000 MW threshold.
EPA solicits comment on the proposed 2,000 MW threshold applicable to
discharges of FGD wastewater under Option 3b, including whether this or
another threshold may be more appropriate.
    The fourth preferred alternative for this proposed rule, Option 4a,
in addition to the requirements that would be established under Option
3, would eliminate discharges of pollutants in bottom ash transport
water from units greater than 400 MW. The technology basis for bottom
ash for the zero discharge requirement is dry handling or a closed-loop
system. Bottom ash transport water is one of the three largest sources
for discharges of the pollutants of concern from steam electric power
plants and these discharges occur at many power plants across the
nation. Based on data collected by the industry survey, approximately
30 percent of coal-fired and petroleum coke-fired power plants handle
bottom ash using technologies that do not generate any transport water.
In addition, another 12 percent of coal- and petroleum coke-fired power
plants manage the wet-sluicing bottom ash handling system as a closed-
loop system that recirculates all bottom ash transport water so that it
is not discharged. In addition, 83 percent of coal-fired generating
units built in the last 20 years installed dry bottom ash handling
systems.
    EPA recognizes that the potential costs associated with compliance
with a zero discharge standard for discharges of bottom ash transport
water would be substantial if applied to all facilities (for example,
approximately half of Option 4 costs and approximately a third of
Option 5 costs), and, therefore, looked carefully at this wastestream
with a particular focus on generating unit size. Our review
demonstrated that, in the case of bottom ash transport water, units
less than or equal to 400 MW are more likely to incur compliance costs
that are disproportionately higher per MW than those incurred by larger
units. For example, the average annualized cost of achieving zero
discharge limits for bottom ash discharges (i.e. dry handling or closed
loop) per MW for a 200 MW unit is more than three times higher than the
average cost for a 400 MW unit. Based on the data from the industry
survey, EPA estimates that 25 percent of coal-fired power plants would
incur costs to comply with a BAT zero discharge requirement for bottom
ash transport water from units greater than 400 MW.
    Furthermore, while all plants, regardless of size, are capable of
installing and operating dry handling or closed-loop systems for bottom
ash transport water, and the costs would be affordable for most plants,
EPA believes that companies may choose to shut down 400 MW and smaller
units instead of making new investments to comply with proposed zero
discharge bottom ash requirements. EPA is basing this belief on its
review of units that facilities have announced will be retired or
converted to non-coal based fuel sources. Of those units that plants
have announced for retirement, and that also

generate bottom ash transport water, over 90 percent are 400 MW or
less. See DCN SE03834.
    Therefore, for the reasons specified above, for units less than or
equal to 400 MW, Option 4a proposes to set the BAT effluent limits
equal to the current BPT effluent limits based on surface impoundments.
EPA solicits comment on the proposed 400 MW threshold applicable to
discharges of bottom ash transport water under Option 4a, including
whether this or another threshold may be more appropriate.
    The two IGCC plants currently operating in the United States use
the technology that is the basis for all four preferred options for
gasification wastewater. A third IGCC plant that will soon begin
commercial operation will also use the technology and, in addition to
that, will also operate a cyanide destruction step as part of the
treatment system.
    For all four preferred options, the proposed BAT limits for copper
and iron in discharges of nonchemical metal cleaning waste are equal to
the current BPT effluent limits for these pollutants in metal cleaning
waste. These effluent limits are based on the same technology that was
used as the basis for the current ELG BPT requirements for metal
cleaning waste (i.e., chemical precipitation).
    Discharges of metal cleaning wastes that are generated from
cleaning metal process equipment without chemical cleaning compounds
(i.e., nonchemical metal cleaning waste) are already subject to BPT
effluent limits for copper and iron equal to the BAT effluent limits
being proposed today. Based on responses to the industry survey,
facilities typically treat both chemical and nonchemical metal cleaning
waste in similar fashion.
    Since, as described above, nonchemical metal cleaning waste is
included within the definition of metal cleaning waste, and copper and
iron are already regulated under metal cleaning wastes, EPA would be
establishing BAT limits equal to the BPT limits (for copper and iron)
that already apply to these wastes. As a result, facilities should
incur no cost to comply with the proposed BAT for these wastes.
However, EPA recognizes that previous guidance provided after the final
1974 regulation stated that wastes from metal cleaning with water are
considered ``low volume'' wastes. The extent to which this statement
was relied upon is unclear, and EPA rejected the guidance in the 1982
rulemaking for the steam electric ELGs (47 FR 52297). However, because
permitting authorities and others may have relied on this guidance and
the potential costs to those facilities are not known, EPA is proposing
to exempt from any new copper and iron BAT requirements those
discharges of nonchemical metal cleaning waste to which this guidance
was applied in the past. In other words, EPA is proposing to exempt
from proposed new copper and iron BAT limitations those discharges of
nonchemical metal cleaning wastes from generating units that are
currently authorized to discharge nonchemical metal cleaning wastes
without copper and iron limits pursuant to existing BPT requirements
for metal cleaning waste. For such discharges, EPA is proposing to set
BAT limitations equal to BPT limitations for low volume waste.
    To get a better understanding of how discharges of nonchemical
metal cleaning wastes are currently permitted, EPA's regional offices
recently reviewed 45 permits for plants that EPA had reason to believe
generated nonchemical metal cleaning waste based on responses to the
industry survey. For these permits, EPA determined the following based
on the review:
     64 percent of the plants are either zero discharge of
metal cleaning wastes or have to comply with copper and iron limits;
     27 percent of plants do not have to comply with copper and
iron limits; and
     9 percent of plant permits do not include enough
information to determine whether the plant would be in compliance with
the proposed BAT limitations.

While not exhaustive, this review provides some information to suggest
that many, but not all, plants are either zero discharge or have iron
and copper limits and thus are already meeting these proposed BAT
limitations. Also see Section 7.7 of the TDD.
    In order to implement the exemption proposed today for certain
discharges of nonchemical metal cleaning waste that have historically
been treated as low volume wastes and not subject to copper and iron
limits under metal cleaning waste BPT requirements, EPA's current
thinking is to develop a specific list of generating units eligible for
the exemption. Therefore, EPA is seeking to identify those generating
units that should be eligible for the exemption through the public
comment process on this rulemaking. To qualify for the proposed
exemption, the generating unit must meet all three of the following
criteria:
     The generating unit must currently generate nonchemical
metal cleaning wastes;
     The generating unit must discharge the nonchemical metal
cleaning waste; and
     The generating unit must be located at a plant that is
authorized to discharge the nonchemical metal cleaning waste without
limitations for copper and iron.

If the nonchemical metal cleaning wastes generated and discharged by a
generating unit do not meet all of these three criteria, then EPA
proposes that the generating unit will not be eligible for the
exemption. For example, if the plant currently hauls the nonchemical
metal cleaning wastes off site for disposal, the generating units
associated with the nonchemical metal cleaning waste generation would
not be exempt. Any public comments submitted with the intention of
identifying generating units that might appropriately fall within the
exemption must provide the necessary documentation (e.g., permits, fact
sheets) to support a finding that the generating unit meets all three
criteria. EPA also requests comment on this general method of
implementing the exemption. Another approach would be to define the
conditions of the exemption, and then make it available to any facility
that qualified, regardless of whether the facility was identified to
EPA during the comment period. This would give EPA less information on
the potential effects of including this exemption in the final rule,
but would also allow qualified facilities to make use of the exemption
even if they were unaware of the need to file comments during the
comment period in order to make use of it. EPA requests comment on
this, or any other, way of implementing the proposed exemption.
    EPA is also considering setting BAT limitations equal to BPT
limitations applicable to metal cleaning waste for all discharges of
nonchemical metal cleaning wastes (i.e., not creating an exemption from
copper and iron limits for discharges of nonchemical metal cleaning
wastes from generating units currently authorized to discharge those
wastes without copper and iron limits). As part of this approach, EPA
is evaluating whether plants would incur costs to comply with the
current BPT requirements applicable to discharge of metal cleaning
wastes. Therefore, EPA is also soliciting comments that provide
information on those generating units that are not currently subject to
the BPT metal cleaning waste limitations for copper and iron, in order
to understand what actions would be required to comply with the
proposed BAT nonchemical metal cleaning waste limitations for iron and
copper. EPA is

particularly interested in the following information:
     Type of nonchemical metal cleaning waste generated,
frequency of generation, and volume generated;
     Wastewater characterization data (i.e., monitoring data)
for the nonchemical metal cleaning waste; \32\
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    \32\ Commenters should provide available monitoring data (i.e.,
EPA is not requiring the commenters to collect additional samples).
Additionally, commenters should specify what data are represented by
the characterization data (which wastestreams were sampled, the
percent contribution of each wastestream, whether the samples are
untreated or treated, and if treated, the type of treatment system
represented).
---------------------------------------------------------------------------

     Information regarding the actions that would need to be
taken to comply with the iron and copper limits for the nonchemical
metal cleaning wastes discharged; and
     Estimated capital and operating and maintenance costs,
broken out by specific cost components (e.g., equipment costs,
installation costs, labor costs), to comply with the proposed copper
and iron limits, along with the basis for the cost estimate.
    EPA's analysis to date suggests that all four preferred options,
Option 3a, Option 3b, Option 3, and Option 4a, are economically
achievable. EPA performed cost and economic impact assessments using
the Integrated Planning Model (IPM) for Option 3 and Option 4.\33\
Option 4 is more costly than any of the four preferred options
including Option 4a; therefore by performing the assessments with these
two options, EPA can evaluate the potential effects of each of the
preferred options. Because the costs and the facilities affected by
Option 3a and 3b are a subset of Option 3, EPA can use the results of
Option 3 to inform the potential impacts of Option 3a and Option 3b. In
a similar way, because the costs and the facilities affected by Option
4a are a subset of Option 4, EPA can use the results of Option 4 to
inform the potential impacts of Option 4a.
---------------------------------------------------------------------------

    \33\ IPM is a comprehensive electricity market optimization
model that can evaluate such impacts within the context of regional
and national electricity markets. See Section XI for additional
discussion.
---------------------------------------------------------------------------

    For the options analyzed overall, the model showed very small
effects on the electricity market, on both a national and regional sub-
market basis. Based on the results of these analyses, EPA estimates
that the proposed requirements associated with Option 3a, Option 3b,
and Option 3 would not lead to the premature retirement of any steam
electric generating units (i.e., no partial or full plant closures).
    The results for Option 4 show fourteen unit (partial) closures and
zero plant (full) closures projected as of the model year 2030,
reflecting full compliance of all facilities.34 35 The 14
generating units are located at six plants. The IPM results also show
that five steam electric units that are projected to close under the
base case (i.e., in the absence of the proposed revisions to the ELG)
would remain operating under proposed Option 4 (i.e., avoiding
closure). As a result, for Option 4, the IPM analysis projects total
net closure of nine generating units, with total combined generating
capacity of 317 MW. These results support EPA's conclusion that Option
4 is economically achievable. As explained above, because the costs and
facilities affected by Option 4a are only a subset of Option 4 (i.e.,
are less than those for Option 4), the model would project similar or
smaller effects for Option 4a. These IPM estimates for closures and
avoided closures also support EPA's conclusion that Option 4a is
economically achievable for the steam electric industry.
---------------------------------------------------------------------------

    \34\ As used here for the purpose of this rulemaking, the term
partial closure refers to a plant where the closure of a generating
unit is projected, but one or more generating units at the plant
will continue operating. A full closure refers to a situation where
all generating units at a plant are projected to shut down.
    \35\ Given the design of IPM, unit-level and thereby plant-level
projections are presented as an indicator of overall regulatory
impact rather than a prediction of future unit-level or plant-
specific compliance actions.
---------------------------------------------------------------------------

    As part of its consideration of technological availability and
economic achievability, EPA also considered the magnitude and
complexity of process changes and new equipment installations that
would be required at facilities to meet the requirements of the rule.
As described in greater detail in Section XVI, EPA is proposing that,
where the limitations and standards being proposed today for existing
direct and indirect dischargers are more stringent than existing BPT
requirements, those limitations and standards do not begin to apply
until July 1, 2017 (approximately three years following promulgation of
the final rule). EPA is proposing this approach to provide the time
that many facilities will need to raise capital, plan and design
systems, procure equipment, and construct and then test systems.
Moreover, this approach will enable facilities to take advantage of
planned shutdown or maintenance periods to install new pollution
control technologies. EPA's proposal is designed to minimize any
potential impacts on electricity availability caused by forced outages.
    Options 3a, 3b, 3 and 4a have acceptable non-water quality
environmental impacts, as discussed in Section XV of the preamble and
in the TDD. EPA estimates that Options 3a, 3b, 3, and 4a would increase
energy consumption by less than 0.003 percent, less than 0.004 percent,
less than 0.008 percent, and less than 0.012 percent, respectively, of
the total electricity generated by power plants. EPA also estimates
that Options 3a, 3b, 3, and 4a would increase the amount of fuel
consumed by increased operation of motor vehicles (e.g., for
transporting fly ash) by less than 0.009 percent, less than 0.009
percent, less than 0.009 percent, and less than 0.014 percent,
respectively, of total fuel consumption by all motor vehicles.
    As discussed in Section XV.B., EPA also evaluated the effect of the
proposed rule on air emissions generated by power plants
(NOX, sulfur oxides (SOX), and CO2).
For Options 3a, 3b, and 3, the NOX emissions are estimated
to increase by no more than 0.12 percent, and for Option 4a, by no more
than 0.13 percent. EPA projects no significant increase in emissions of
SOX or CO2 under the four preferred options.
    EPA also evaluated the effect of the proposed rule on solid waste
generation and water usage. There would be no increase in solid waste
generation under Option 3a, and EPA estimates that solid waste
generation at power plants will increase by less than 0.001 percent
under the other three preferred options. EPA estimates the power plants
would reduce water use by 50 billion gallons per year (136 million
gallons per day) under Option 3a, 52 billion gallons per year (143
million gallons per day) under Option 3b, 53 billion gallons per year
(144 million gallons per day) under Option 3, and 103 billion gallons
per year (282 million gallons per day) under Option 4a.
    EPA also examined the effects of the preferred options on consumers
as an ``other factor'' that might be appropriate when considering what
level of control represents BAT. If all compliance costs were passed on
to residential consumers of electricity instead of being borne by the
operators and owners of power plants, the monthly increase in
electricity bill would be no more than $0.04, $0.06, $0.13, and $0.22,
respectively under Options 3a, 3b, 3, and 4a.
    EPA is not proposing either Option 1 or Option 2 as its preferred
option for BAT because neither option would represent the best
available technology level of control for steam electric power plant
discharges. For example, Options 1 and 2 would allow plants to continue

to discharge fly ash transport wastewater without treating the wastes
to remove dissolved metals and many of the other pollutants present in
the wastewater. However, 66 percent of all coal- and petroleum coke-
fired generating units that produce fly ash as a residue of the
combustion process already use dry fly ash technologies to manage all
of their fly ash without any associated creation or discharge of fly
ash transport water. And another 15 percent of the coal- and petroleum
coke-fired generating units that produce fly ash also already operate
dry fly ash handling systems in addition to a wet ash handling system
(either as a completely redundant system, or to manage a fraction of
the fly ash that is produced during combustion). Similarly, every
generating unit operating a FGMC system does so in a manner that avoids
creating any FGMC wastewater (92 percent of units with FGMC), or
manages the FGMC wastewater in a closed cycle process that does not
result in a discharge to surface water (8 percent of units with FGMC).
The technology serving as the basis for FGD effluent limits under
Option 1 is not effective at removing many of the pollutants of concern
in FGD wastewater, including selenium, nitrogen compounds, and certain
metals that contribute to high concentrations of total dissolved solids
in FGD wastewater (e.g., bromides, boron). Furthermore, the information
in the record for this proposed rule demonstrates that the amount of
mercury, selenium, and other pollutants removed by the biological
treatment stage of the treatment system, above and beyond the amount of
pollutants removed in the chemical precipitation treatment stage
preceding the bioreactor, can be substantial. Options 1 and 2 would
remove fewer or similar levels of pollutants to the preferred options,
all of which EPA believes, based on its analysis to date, to be
technologically available, economically achievable, and have acceptable
non-water quality environmental impacts. Options 1 and 2 would
establish new effluent limits for three of the seven key wastestreams
addressed in this rulemaking. For the remaining four wastestreams, BAT
effluent limits would be set equal to the current BPT effluent limits.
    EPA did not select Option 4 as its preferred regulatory option
because of concerns expressed above associated with the projected
compliance costs associated with zero discharge requirements for bottom
ash for units equal to or below 400 MW. The bottom ash requirements for
Option 4 and the preferred Option 4a are the same with the exception
that Option 4a proposes to set the BAT effluent limits for bottom ash
transport water equal to the current BPT effluent limits for units less
than or equal to 400 MW, while Option 4 would set the BAT effluent
limits for bottom ash transport water equal to the BPT effluent limits
for units less than or equal to 50 MW. All other units would be subject
to ``zero discharge'' effluent limits for all pollutants in bottom ash
transport water.
    Moreover, Option 4 proposes to establish BAT discharge limitations
for toxic discharges for leachate. The record demonstrates that the
amount of pollutants collectively discharged in leachate by steam
electric plants is a very small portion of the pollutants discharged
collectively for all steam electric power plants (i.e., less than \1/2\
a percent). The technology basis for limitations on discharges of
combustion residual leachate proposed under Option 4 is chemical
precipitation. Because of the relatively low level of pollutants in
this wastestream, and because EPA believes this is an area ripe for
innovation and improved cost effectiveness, EPA is not putting forward
this option as a preferred option. On balance, EPA would like to
collect additional information on costs and effectiveness of chemical
precipitation and other possible technologies for reducing pollutants
discharged in leachate before making a finding with respect to what
technologies represent the best available technology economically
achievable for controlling discharges of pollutants found in combustion
residual leachate. Consequently, EPA is interested in receiving
information through the public-comment process related to cost,
pollutant reduction, and effectiveness data on chemical precipitation
and alternative approaches to treatment of combustion residual
leachate.
    EPA did not select Option 5 as its preferred option for BAT because
of the high total industry cost for the option ($2.3 billion/year
annualized social cost) and because of preliminary indications that
Option 5 may not be economically achievable. While EPA has
traditionally looked at affordability of the rule to the regulated
industry, EPA has in some limited instances over the past three decades
rejected an option primarily on the basis of total industry costs. See
48 FR 32462, 32468 (July 15, 1983) (Final Rule establishing ELGs for
the Electroplating and Metal Finishing Point Source Categories); 74 FR
62996, 63026 (Dec. 1, 2009) (Final Rule establishing ELGs for the
Construction and Development Point Source Category); BP Exploration &
Oil, Inc. v. EPA, 66 F.3d 784, 796-97 (6th Cir. 1996) (upholding EPA's
decision not to require zero discharge of produced waters based on
reinjection for the Offshore subcategory of the Oil and Gas Extraction
Point Source Category based in part on total industry cost). EPA
similarly finds this appropriate here. In addition, certain screening-
level economic impact analyses indicated that compliance costs may
result in financial stress to some entities owning steam electric
plants. Although EPA did not select Option 5 as the preferred BAT
option, without question, Option 5 would remove the most pollutants
from steam electric power plant discharges. Also, the technologies are
all potentially available and may be appropriate (individually or in
totality) as the basis for water quality-based effluent limits in NPDES
permits, depending on site-specific conditions. For example, any of the
requirements that would be established under Option 5, including at a
minimum the vapor compression evaporation technology serving as the
Option 5 technology basis for FGD wastewater, may be appropriate for
those power plants that discharge upstream of drinking water treatment
plants and that have bromide releases in wastewaters that impact
treatment of source waters at the drinking water treatment plants.
Section XIII of the preamble includes additional discussion about
discharges of bromides. Also, see the EA.
    For the reasons described below in Section VIII.B., EPA is
proposing that, where the limitations and standards being proposed
today are more stringent than existing BPT requirements, those
limitations and standards do not begin to apply until July 1, 2017
(approximately three years from the effective date of this rule).
    For all eight of the main BAT options under consideration, EPA is
proposing to establish effluent limits for oil-fired generating units
and small generating units (i.e., 50 MW or less) that differ from the
effluent limits for all other generating units.\36\ For oil-fired
generating units and small generating units, EPA is proposing to set
the BAT effluent limits equal to the current BPT effluent limits for
all seven of the key wastestreams addressed by this proposed rule. For
six of these wastestreams, BAT would be set equal to current BPT
numeric limits for TSS

and oil and grease, with these pollutants regulated as indicator
pollutants for the control of toxic and nonconventional pollutants. For
nonchemical metal cleaning wastes, EPA is proposing to set BAT equal to
the current BPT effluent limits for copper and iron in metal cleaning
wastes \37\, but would not establish BAT effluent limits for TSS and
oil and grease (which are also currently regulated by BPT for metal
cleaning wastes). EPA's proposal and reasoning is detailed below.
---------------------------------------------------------------------------

    \36\ For Option 4a, for discharges of pollutants found in bottom
ash transport water only, as explained previously, EPA is proposing
to raise the value from less than or equal to 50 MW to less than or
equal to 400 MW.
    \37\ As described earlier in this section, EPA is proposing to
exempt from new BAT copper and iron limitations existing discharges
of nonchemical metal cleaning wastes that are currently authorized
under their existing NPDES permit without iron and copper limits.
For these discharges, BAT limits would be set equal to BPT limits
for low volume waste.
---------------------------------------------------------------------------

    In addition, EPA has identified some differences among the options
in terms of cost effectiveness. Section XII of this preamble describes
EPA's cost-effectiveness analysis for the preferred regulatory options.
EPA's analysis to date shows that the average cost effectiveness
($1981/TWPE) under Option 3a, 3b, 3, and 4a for existing direct
dischargers is $27, $31, $44, and $57, respectively. This demonstrates
that Option 3a is the most cost effective of the preferred options,
Option 4a is the least cost effective of the preferred options, and
Option 3 and Option 3b are between the two.
    EPA also calculated the cost-effectiveness of particular controls
for the wastestreams that would be controlled under the preferred
options for existing direct dischargers.\38\ The cost-effectiveness for
zero discharge of fly ash transport and FGMC wastewater, as in Option
3a, is $27 per TWPE removed. The cost effectiveness of chemical
precipitation alone is $70 per TWPE removed, while the cost
effectiveness of chemical precipitation plus anaerobic biological
treatment, which is included in all options except Option 3a, is $60
per TWPE removed. The cost effectiveness of zero discharge of bottom
ash transport water for all units more than 50 MW is $107 per TWPE. In
comparison, when this requirement is applied only to units more than
400 MW, as in Option 4a, the cost effectiveness value is $99 per TWPE
removed.
---------------------------------------------------------------------------

    \38\ While it is not included in the preferred options as a
wastestream with additional controls, EPA also looked at the cost
effectiveness of controlling leachate using chemical precipitation
and this value would exceed $1,000 per TWPE removed.
---------------------------------------------------------------------------

    Thus, the cost effectiveness for control of the various
wastestreams included within the preferred options ranges from $27-$107
per TWPE in $1981; with zero discharge controls on fly ash transport
wastewater being the most cost-effective, zero discharge controls on
bottom ash transport wastewater being the least cost effective, and
controls for FGD wastewater based on chemical precipitation in
combination with anaerobic biological treatment between the two.
    Effluent Limits for Oil-fired Generating Units. EPA is proposing to
establish BAT limits equal to BPT for existing oil-fired units. For the
purpose of the proposed BAT effluent limits, oil-fired generating units
would be those that use oil as either the primary or secondary fuel and
do not burn coal or petroleum coke. Units that use oil only during
startup or for flame stabilization would not be considered oil-fired
generating units. EPA is proposing to set BAT limits equal to BPT for
existing oil-fired units because, in comparison to coal- and petroleum
coke-fired units, oil-fired units generate substantially fewer
pollutants, are generally older and operate less frequently, and in
many cases are more susceptible to early retirement when faced with
compliance costs attributable to the proposed ELGs.
    The amount of ash generated at oil-fired units is a small fraction
of the amount produced by coal-fired units. Coal-fired units generate
hundreds or thousands of tons of ash each day, with some plants
generating more than 1,500 tons per day of ash. In contrast, oil-fired
units generate less than one ton of ash per day. This disparity is also
apparent when comparing the ash tonnage to the amount of power
generated, with coal-fired units producing nearly 300 times more ash
than oil-fired units (0.04 tons per MW-hour on average for coal units;
0.000145 tons per MW-hour on average for oil units). The amount of
pollutants discharged to surface waters is roughly correlated to the
amount of ash wastewater discharged, thus oil-fired units discharge
substantially less pollutants to surface waters than a coal-fired unit
even when generating the same amount of electricity. EPA estimates that
if BAT effluent limits for oil-fired units were set equal to either the
proposed Option 3 or Option 4a limits for coal-fired units (>50 MW),
the total industry pollutant reductions attributable to the proposed
rule would increase by less than one percent.
    Oil-fired units are generally among the oldest steam electric units
in the industry. Eighty-seven percent of the units are more than 25
years old. In fact, more than a quarter of the units began operation
more than 50 years ago. Based on responses to the industry survey, only
20 percent of oil-fired units operate as baseload units; the rest are
either cycling/intermediate units (45 percent) or peaking units (35
percent). These units also have notably low capacity utilization. While
a quarter of the baseload units report capacity utilization greater
than 75 percent, most baseload units (60 percent) report a capacity
utilization of less than 25 percent. Eighty percent of the cycling/
intermediate units and all peaking units also report capacity
utilization less than 25 percent. Thirty-five percent of oil-fired
units operated for more than six months in 2009; nearly half of the
units operated for less than 30 days.
    As shown above, oil-fired units are generally older and operate
intermittently (i.e., they are peaking, cycling, or intermediate
units). While these oil-fired units are capable of installing and
operating the treatment technologies evaluated as part of this
rulemaking, and the costs would be affordable for most of the plants,
EPA believes that, due to the factors described here, companies may
choose to shut down these oil-fired units instead of making new
investments to comply with the rule. If these units shut down, it could
reduce the flexibility that grid operators have during peak demand
because there would be less reserve generating capacity to draw upon.
But more importantly, maintaining a diverse fleet of generating units
that includes a variety of fuel sources is vital to the nation's energy
security. Because the supply/delivery network for oil is different from
other fuel sources, maintaining the existence of oil-fired generating
units helps ensure reliable electric power generation. Thus, the oil-
fired generating units add substantially to electric grid reliability
and the nation's energy security.
    Based on responses to the industry survey, EPA estimates that less
than 20 oil-fired units discharged fly ash or bottom ash transport
water in 2009. At the same time, EPA notes that many oil-fired units
operate infrequently, which could contribute to the relatively low
numbers of units discharging ash-related wastewater. Should more
widespread operation of oil units be required to meet demands of the
electric grid, additional plants may find it necessary to discharge ash
transport water. Because of the operating conditions unique to the
existing fleet of oil-fired units and potential effects on the nation's
electric power grid, a non-water quality environmental impact that EPA
considers under Section 304(b) of the CWA, EPA believes it is
appropriate to set BAT effluent limits for oil-fired equal to the
current BPT limits.
    Effluent Limits for Small Generating Units. EPA is proposing to
establish

BAT effluent limits equal to BPT for existing small generating units,
which would be defined as those units with a total nameplate generating
capacity of 50 MW or less.\39\ Small units are more likely to incur
compliance costs that are disproportionately higher per amount of
energy produced than those incurred by large units because they are not
as able to take advantage of economies of scale. For example, the unit-
level annualized cost for the proposed FGD wastewater treatment
technology under Option 3 (chemical precipitation plus biological
treatment) is approximately seven times more expensive on a dollar-per-
megawatt basis for small generating units, relative to units larger
than 50 MW. Similarly, the unit-level annualized cost to convert the
fly ash handling system to dry technology (conveyance equipment and
intermediate storage silos) is more than four times more expensive on a
dollar-per-megawatt basis for small generating units, relative to units
larger than 50 MW. For Option 4, bottom ash conversions are more than
six times more expensive for small units, on a dollar-per-megawatt
basis.
---------------------------------------------------------------------------

    \39\ Preferred Option 4a would increase this threshold for
purposes of discharges of pollutants in bottom ash transport water
only, to 400 MW or less.
---------------------------------------------------------------------------

    Moreover, the record demonstrates that the amount of pollutants
collectively discharged by small generating units is a very small
portion of the pollutants discharged collectively for all steam
electric power plants (e.g., less than 1 percent under Option 3). As a
result, setting BAT limits equal to BPT for existing steam electric
generating units with a capacity of 50 MW or less will have little
impact on the pollutant removals for the overall rule.
    EPA considered establishing the size thresholds for small
generating units at 25 MW because that threshold is already used for
this industry sector in some regulatory contexts. For example, the
Clean Air act defines an ``electric utility generating unit'' as ``any
fossil fuel fired combustion unit of more than 25 megawatts that serves
a generator that produces electricity for sale.'' CAA Section
112(a)(8), 42 U.S.C. 7412(a)(8). The existing ELGs for the steam
electric power generating point source category also include different
effluent limitations for plants with total rated generating capacity of
less than 25 MW. See 40 CFR 423.13(c)(1) and 423.15(i)(1).
    EPA currently proposes a threshold of 50 MW \40\ rather than 25 MW
because the proposed 50 MW threshold would do more to alleviate
potential impacts.\41\ EPA recognizes that any attempt to establish a
size threshold for generating units will be imperfect due to individual
differences across units and firms. However, EPA believes that a
threshold of 50 MW or less reasonably and effectively targets those
generating units that should receive different treatment based on the
considerations described above. EPA requests comment on the proposed 50
MW threshold applicable to discharges of the wastestreams described
under each of the preferred options, and as well as other possible
thresholds for small units.
---------------------------------------------------------------------------

    \40\ For Option 4a, for bottom ash transport water only, as
explained previously, EPA is proposing to raise the value from less
than or equal to 50 MW to less than or equal to 400 MW.
    \41\ As discussed in Section XVII.C, the proposed 50 MW
threshold also alleviates potential impacts which may be borne by
small entities or municipalities.
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4. Rationale for the Proposed Best Available Demonstrated Control/NSPS
Technology
    Section 306 of the CWA directs EPA to promulgate New Source
Performance Standards, or NSPS, ``for the control of the discharge of
pollutants which reflects the greatest degree of effluent reduction
which the Administrator determines to be achievable through application
of the best available demonstrated control technology, processes,
operating methods, or other alternatives, including, where practicable,
a standard permitting no discharge of pollutants.'' Congress envisioned
that new sources could meet tighter controls than existing sources
because of the opportunity to incorporate the most efficient processes
and treatment systems into the facility design. As a result, NSPS
should represent the most stringent controls attainable through the
application of the best available demonstrated control technology, or
BADCT, for all pollutants (that is, conventional, nonconventional, and
priority pollutants).
    After considering all of the technology options described above in
Section VII.B.2, EPA is proposing to establish NSPS based on the suite
of technologies identified for Option 4 in Table VIII-1. Thus, the
proposed NSPS would do the following:
     Establish numeric effluent limits for mercury, arsenic,
selenium, and nitrate-nitrite in discharges of FGD wastewater;
     Maintain the current ``zero discharge'' effluent limit for
all pollutants in fly ash transport water, and establish new ``zero
discharge'' effluent limits for all pollutants in bottom ash transport
water and FGMC wastewater;
     Establish numeric effluent limits for mercury, arsenic,
selenium, and TDS in discharges of gasification wastewater;
     Establish numeric effluent limits for TSS, oil and grease,
copper, and iron in discharges of nonchemical metal cleaning wastes;
and
     Establish numeric effluent limits for mercury and arsenic
in discharges of leachate.
    The record indicates that the proposed NSPS is technologically
available and demonstrated. The technologies that serve as the basis
for Option 4 are all available based on the performance of plants using
components of the suite of technologies within the past decade. For
example, approximately a third of plants that discharge FGD wastewater
utilize chemical precipitation (in some cases, also using additional
treatment steps). Five plants operate fixed-film anoxic/anaerobic
biological treatment systems for the treatment of FGD wastewater and
another operates a suspended growth biological treatment system that
targets removal of selenium.\42\ EPA is aware of industry concerns with
the feasibility of biological treatment at some power plants.
Specifically, industry has asserted that the efficacy of these systems
is unpredictable, and is subject to temperature changes, high chloride
concentrations, and high oxidation reduction potential in the absorber
(that may kill the treatment bacteria). EPA's record to date does not
support these assertions, but is interested in additional information
that addresses these concerns. Moreover, approximately 50 coal-fired
generating units were built within the last 20 years and most (83
percent) manage their bottom ash without using water to transport the
ash and, as a result, do not discharge bottom ash transport water. The
Option 4 technologies being proposed today represent current industry
practice for gasification wastewater. Every IGCC power plant currently
in operation uses vapor compression evaporation to treat the
gasification wastewater, even when the wastewater is not discharged and
is instead reused at the plant. In the case of FGMC wastewater, every
plant currently using post-combustion sorbent injection (e.g.,
activated carbon injection) either handles the captured spent sorbent
with a dry process or

manages the FGMC wastewater so that it is not discharged to surface
waters (or has the capability to do so). For leachate, as discussed
above in Section VI, chemical precipitation is a well-demonstrated
technology for removing metals and other pollutants from a variety of
industrial wastewater, including leachate from other landfills not
located at power plants. It therefore represents the ``greatest degree
of effluent reduction . . . achievable'' as that phrase is used in
section 306 of the Clean Water Act.
---------------------------------------------------------------------------

    \42\ Four of the six operate the biological treatment systems in
combination with chemical precipitation. Other power plants are
considering installing the biological treatment technology to remove
selenium, and at least one plant is moving forward with
construction.
---------------------------------------------------------------------------

    The proposed NSPS for discharges of nonchemical metal cleaning
waste are equal to the current BPT effluent limits that apply to
discharges of these wastes from existing sources. As such, the proposed
NSPS would be consistent with current industry practice for treating
nonchemical metal cleaning waste and is based on the same technology
that was used as the basis for the current NSPS for chemical metal
cleaning waste. Based on responses to the industry survey, facilities
typically treat both chemical and nonchemical metal cleaning waste in
similar fashion.
    The NSPS being proposed today also poses no barrier to entry. The
cost to install technologies at new units are typically less than the
cost to retrofit existing units. For example, the cost differential
between BAT Options 3 and 4 for existing sources is mostly associated
with retrofitting controls for bottom ash handling systems. For
existing generating units, the effluent requirements considered under
Option 4a for BAT would cause those plants with units greater than 400
MW that discharge bottom ash wastewater to either modify their
processes to become a closed-loop wet sluicing system, or retrofit
modifications such as replacing the bottom of boilers to accommodate
mechanical drag chain systems. For new sources, however, Option 4 would
not present plants with the same choice of retrofit versus modification
of existing processes. This is because every new generating unit
already has to install some type of bottom ash handling system as the
unit is constructed. Establishing a zero discharge standard for
pollutants in bottom ash transport water as part of the NSPS means that
power plants will install a dry bottom ash handling system during
construction instead of installing a wet-sluicing system. EPA estimates
that over the past 20 years, more than 50 new coal-fired generating
units were built and that most of these units (83 percent) installed
dry bottom ash handling systems.
    Moreover, as described above in Section XI, EPA assessed the
possible impacts of Option 4 to new units by comparing the costs of the
Option 4 technologies to the costs of a new generating unit and as part
of its Integrated Planning Model analyses. In both cases, the results
show that the incremental costs that would be imposed by Option 4 do
not present a barrier to entry. EPA estimated that the compliance costs
for a new unit (capital and O&M) represent at most 1.5 percent of the
annualized cost of building and operating a new 1,300 MW coal-fired
plant, with capital costs representing less than 1 percent of the
overnight construction costs, and annual O&M costs representing less
than 5 percent of the cost of operating a new plant. IPM results show
no barrier to new generation capacity during the model years in which
all existing plants must be in compliance as a result of the BAT/NSPS
compliance scenario.
    Finally, EPA has analyzed non-water quality environmental impacts
associated with Option 4 for existing sources, and its analysis is
relevant to the consideration of non-water quality environmental
impacts associated with Option 4 for new sources. EPA's analysis
demonstrates that the non-water quality environmental impacts
associated with Option 4 for existing sources are acceptable. Given
that there is nothing inherent about a new unit that would alter the
analysis for such sources, EPA believes that the non-water quality
environmental impacts associated with the proposed NSPS regulatory
option are, likewise, acceptable.
    In contrast to the best available technology economically
achievable, or BAT, that EPA is proposing today for existing sources,
the proposed NSPS would establish the same limits for oil-fired
generating units and small generating units \43\ that are being
proposed for all other new sources. A key factor that affects
compliance costs for existing sources is the need to retrofit new
pollution controls to replace existing pollution controls. New sources
do not trigger retrofit costs because the pollution controls (process
operations or treatment technology) are installed at the time the new
source is constructed. Thus, new sources are less likely than an
existing source to experience financial stress by the cost of
installing pollution controls, even if the pollution controls are
identical. EPA requests comment on its proposal to establish the same
NSPS for small generating units as for larger units.
---------------------------------------------------------------------------

    \43\ As a point of clarification, this similarly holds true for
bottom ash limitations.
---------------------------------------------------------------------------

    EPA is not proposing regulatory Options 1 or 2, which would
establish new effluent limits for only two of the seven key
wastestreams addressed by this proposed rule, as its preferred option
for NSPS. As explained above, neither of these two options represents
the greatest degree of effluent reduction which the Administrator
determines to be achievable through the best available demonstrated
control technology.
    EPA also did not select any of the preferred BAT regulatory Options
(i.e., Options 3a, 3b, 3, or 4a) as its preferred option for NSPS
because they would not control FGD wastewater (Option 3a and Option 3b
for units at plants with a total wet-scrubbed capacity of less than
2,000 MW), bottom ash transport water (Option 3a, Option 3b, Option 3,
and Option 4a for units less than or equal to 400 MW) or leachate
discharges (Options 3a, 3b, 3, and 4a) and other, more effective,
available technologies exist that do not present a barrier to entry and
have acceptable non-water quality environmental impacts. EPA did not
select preferred Option 3a for the same reasons it rejected Options 1
and 2. EPA did not select Options 3b, 3, or 4a because, under these
regulatory options, NSPS effluent limits for bottom ash transport water
for all or some portion of units and leachate would be set equal to the
current BAT effluent limits on TSS and oil and grease, which are based
on using surface impoundments.\44\ The record demonstrates that zero
discharge technologies are effective and available for managing bottom
ash at new sources. Since these zero discharge technologies have been
installed at 83 percent of coal-fired units built in the last 20 years,
effluent standards based on surface impoundments do not represent Best
Available Demonstrated Control Technology to control the discharge of
pollutants in the bottom ash wastestream from new sources regardless of
the unit size. In addition, the record demonstrates that chemical
precipitation is a more effective technology than surface impoundments
for controlling the pollutants present in leachate. For these reasons,
Options 3b, 3 and 4a do not represent the best available demonstrated
control technology to control the discharge of pollutants of concern
from new sources.
---------------------------------------------------------------------------

    \44\ This rationale similarly applies to Option 3a.
---------------------------------------------------------------------------

    EPA did not select Option 5 as its preferred option for NSPS
because of its high costs, which are substantially higher than the
costs for Option 4 and the other options evaluated for NSPS. See the
TDD and RIA for more information about the estimated

compliance costs for the NSPS options. Also, see Section XI below. The
cost differential between Options 4 and 5 is primarily due to the
evaporation technology basis for controlling pollutants in FGD
wastewater under Option 5.
    Finally, EPA notes that Option 5 is comparable to Option 4 with
respect to much of the anticipated pollutant removals, particularly the
expected removals of arsenic, mercury, selenium and nitrogen. At the
same time, Option 5 would control other pollutants in FGD wastewater
that Options 1 through 4 do not effectively control, namely boron,
bromides, and TDS. EPA is aware that bromide in wastewater discharges
from steam electric power plants located upstream from a drinking water
intake has been associated with the formation of trihalomethanes, also
known as THMs, when it is exposed to disinfectant processes in water
treatment plants. EPA recommends that permitting authorities consider
the potential for bromide discharges to adversely impact drinking water
intakes when determining whether additional water quality-based
effluent limits may be warranted. Although EPA did not select Option 5
as the preferred NSPS option, the technologies forming the basis for
Option 5 are all technologically available and may be appropriate
(individually or in totality) as the basis for water quality-based
effluent limits in individual or general permits depending on site-
specific conditions. EPA requests comment on its selection of Option 4
instead of Option 5 as the basis for NSPS.
5. Rationale for the Proposed PSES Technology
    Section 307(b), 33 U.S.C. 1317(b), of the Clean Water Act requires
EPA to promulgate pretreatment standards for pollutants that are not
susceptible to treatment by POTWs or which would interfere with the
operation of POTWs. EPA looks at a number of factors in selecting the
technology basis for pretreatment standards. For existing sources,
these factors are generally the same as those considered in
establishing BAT. However, unlike direct dischargers whose wastewater
will receive no further treatment once it leaves the facility, indirect
dischargers send their wastewater to POTWs for further treatment. As
such, EPA must also determine that a pollutant is not susceptible to
treatment at a POTW or would interfere with POTW operations.
    Table VIII-3 summarizes the pass through analysis results for the
BAT/NSPS pollutants for the various wastestreams and regulatory
options. As shown in the table, all of the pollutants proposed for
regulation under BAT/NSPS pass through.

         Table VIII-3--Summary of Pass Through Analysis Results
------------------------------------------------------------------------
                                                    Pass through? (Yes/
       Treatment option             Pollutant               No)
------------------------------------------------------------------------
Chemical Precipitation for FGD  Arsenic..........  Yes.
 Wastewater and/or Leachate.    Mercury..........  Yes.
Biological (chemical            Arsenic..........  Yes.
 precipitation followed by      Mercury..........  Yes.
 anoxic/anaerobic biological)   Nitrate Nitrite    Yes.
 for FGD Wastewater and/or       as N.
 Leachate.
                                Selenium.........  Yes.
Mechanical Vapor-Compression    Arsenic..........  Yes.
 Evaporation for FGD            Mercury..........  Yes.
 Wastewater.
                                Selenium.........  Yes.
                                TDS..............  Yes.
Mechanical Vapor-Compression    Arsenic..........  Yes.
 Evaporation for IGCC           Mercury..........  Yes.
 Wastewater.
                                Selenium.........  Yes.
                                TDS..............  Yes.
Nonchemical Metal Cleaning      Copper...........  Yes.
 Wastes.
------------------------------------------------------------------------

    For this proposal, EPA evaluated the same model technologies and
regulatory options for PSES that it evaluated for BAT (described in
Section VIII.A.2). These standards would apply to existing generating
units that discharge wastewater to POTWs.
    As explained above in Section III.B.5, in selecting the PSES
technology basis, the Agency generally considers the same factors as it
considers when setting BAT, including economic achievability.
Typically, the result is that the PSES technology basis is the same as
the BAT technology basis. This proposal is no exception. After
considering all of the technology options described in Section
VIII.A.2, as is the case for BAT, EPA is proposing four preferred
alternatives for PSES (i.e., Options 3a, 3b, 3, and 4a).
    With the exception of oil-fired generating units and small
generating units (i.e., 50 MW or smaller), the proposed rule under
Option 3a would:
     Establish a ``zero discharge'' effluent limit for all
pollutants in fly ash transport water and FGMC wastewater;
     Establish numeric effluent limits for mercury, arsenic,
selenium, and TDS in discharges of gasification wastewater;
     Establish numeric effluent limits for copper in discharges
of nonchemical metal cleaning wastes; \45\ and
---------------------------------------------------------------------------

    \45\ As described in Section VIII.A.3, EPA is proposing to
exempt from new BAT copper and iron effluent limits existing
discharges of nonchemical metal cleaning wastes that are currently
authorized by an NPDES permit without iron and copper limits. This
exemption also applies to any indirect discharges of nonchemical
metal cleaning waste that are authorized without copper pretreatment
standards. For such indirect discharges, the regulation would not
specify PSES.
---------------------------------------------------------------------------

     Establish BAT effluent limits for bottom ash transport
water and leachate that are equal to the current BPT effluent limits
for these discharges (i.e., numeric effluent limits for TSS and oil and
grease).
    With the exception of oil-fired generating units and small
generating units (i.e., 50 MW or smaller), the proposed PSES under
Option 3b would:
     Establish standards for mercury, arsenic, selenium, and
nitrate-nitrite in discharges of FGD wastewater for units located at
plants with a total wet-scrubbed capacity of 2,000 MW; \46\
---------------------------------------------------------------------------

    \46\ Under Option 3b (for units located at plants with a total
wet-scrubbed capacity of less than 2,000 MW), the regulations would
not specify PSES for FGD wastewater, and POTWs would need to develop
local limits to address the introduction of pollutants by steam
electric power plants to the POTWs that cause pass through or
interference, as specified in 40 CFR 403.5(c)(2).
---------------------------------------------------------------------------

     Establish a ``zero discharge'' standard for all pollutants
in fly ash transport water and FGMC wastewater;

     Establish standards for copper in discharges of
nonchemical metal cleaning wastes; \47\ and
---------------------------------------------------------------------------

    \47\ As described in Section VIII.A.3, EPA is proposing to
exempt from new BAT copper and iron effluent limits existing
discharges of nonchemical metal cleaning wastes that are currently
authorized by an NPDES permit without iron and copper limits. This
exemption also applies to any indirect discharges of nonchemical
metal cleaning waste that are authorized without copper pretreatment
standards. For such indirect discharges, the regulation would not
specify PSES.
---------------------------------------------------------------------------

     Establish standards for mercury, arsenic, selenium and TDS
in discharges of gasification wastewater.
    Under the third preferred alternative for PSES (Option 3), in
addition to the requirements described for Option 3b, the proposed rule
would establish the same standards for mercury, arsenic, selenium, and
nitrate-nitrite in discharges of FGD wastewater as for Option 3b from
units at all steam electric facilities, with the exception of oil-fired
generating units and small generating units (i.e., 50 MW or smaller).
    Under the fourth preferred alternative for PSES (Option 4a), the
proposed rule would establish ``zero discharge'' effluent limits for
all pollutants in bottom ash transport water for units greater than 400
MW. All other proposed Option 4a requirements are identical to the
proposed Option 3 requirements.
    EPA is putting forth Options 3a, 3b, 3, and 4a as the Agency's
preferred PSES regulatory options in order to confirm its understanding
of the pros and cons of these options through the public comment
process and intends to evaluate this information and how it relates to
the factors specified in the CWA. For the same reasons identified in
Section VIII.A.3 above for BAT, EPA's analysis to date suggests that
for indirect dischargers as well as direct dischargers, the Option 3a,
Option 3b, Option 3, and Option 4a technologies are available and
economically achievable, and that the other regulatory options (Options
1, 2, 4, and 5) do not reflect the criteria for PSES. In addition, EPA
has determined that these standards will prevent pass-through of
pollutants from POTWs into receiving streams and also help control
contamination of POTW sludge. EPA also considered the non-water quality
environmental impacts and found them to be acceptable, as described in
Section XV. Furthermore, for the same reasons that apply to EPA's
preferred BAT options and described in Section VIII.A.3, with the
exception of numeric standards for copper in discharges of nonchemical
metal cleaning wastes,\48\ EPA is proposing not to subject discharges
from oil-fired generating units and small generating units (i.e., 50 MW
or smaller \49\) to POTWs to requirements based on Options 3a, 3b, 3,
or Option 4a.
---------------------------------------------------------------------------

    \48\ EPA is proposing to exempt from new PSES copper standards
for existing discharges of nonchemical metal cleaning wastes that
are currently authorized. For these discharges, the regulation would
not specify PSES.
    \49\ Preferred Option 4a would increase this threshold for
purposes of discharges of pollutants in bottom ash transport water
only, to 400 MW or less.
---------------------------------------------------------------------------

    Finally, similar to EPA's preferred BAT options and for the reasons
supporting those options, for certain wastestreams, EPA is proposing
that any new PSES discharge standards would apply to discharges of the
regulated wastewater generated after July 1, 2017. See discussion in
Section XVI.
6. Rationale for the Proposed PSNS Technology
    Section 307(c) of the CWA, 33 U.S.C. 1317(c), authorizes EPA to
promulgate pretreatment standards for new sources (PSNS) at the same
time it promulgates new source performance standards (NSPS). As is the
case for PSES, PSNS are designed to prevent the discharge of any
pollutant into a POTW that may interfere with, pass through, or may
otherwise be incompatible with POTWs. In selecting the PSNS technology
basis, the Agency generally considers the same factors it considers in
establishing NSPS along with the results of a pass through analysis. As
a result, EPA typically promulgates pretreatment standards for new
sources based on best available demonstrated technology for new
sources. See National Ass'n of Metal Finishers v. EPA, 719 F.2d 624,
634 (3rd Cir. 1983). The legislative history explains that Congress
required simultaneous establishment of new source standards and
pretreatment standards for new sources for two reasons. First, Congress
wanted to ensure that any new source industrial user achieve the
highest degree of internal effluent controls necessary to ensure that
such user's contribution to the POTW would not cause a violation of the
POTW's permit. Second, Congress wished to eliminate from the new user's
discharge any pollutant that would pass through, interfere, or was
otherwise incompatible with POTW operations.
    For this proposal, EPA evaluated the same model technologies and
regulatory options for PSNS that it evaluated for NSPS (described above
in Section VIII.A.4). These standards would apply to new generating
units or new facilities that discharge wastewater to POTWs. After
considering all of the technology options described in Section
VIII.A.2, as is the case for NSPS, EPA is proposing to establish PSNS
based on the technologies specified in Option 4. The proposed PSNS
would:
     Establish standards for mercury, arsenic, selenium, and
nitrate-nitrite in discharges of FGD wastewater;
     Maintain a ``zero discharge'' standard for all pollutants
in fly ash transport water, and establish a zero discharge standard for
bottom ash transport water and FGMC wastewater;
     Establish standards for mercury, arsenic, selenium and TDS
in discharges of gasification wastewater;
     Establish standards for copper in discharges of
nonchemical metal cleaning wastes; and
     Establish standards for mercury and arsenic in discharges
of leachate.
    For the same reasons identified for NSPS in Section VIII.A.4, EPA
is proposing Option 4 as its preferred option because the technologies
forming the basis for that option are available and demonstrated and
will not pose a barrier to entry.\50\ In addition, EPA has determined
that these standards will prevent pass-through of pollutants from POTWs
into receiving streams and also help control contamination of POTW
sludge. EPA also considered the non-water quality environmental impacts
associated with the preferred option and found them to be acceptable,
as described in Section XV.
---------------------------------------------------------------------------

    \50\ For the same reasons discussed above in Section VIII for
NSPS, EPA similarly determined the other regulatory options do not
reflect PSNS.
---------------------------------------------------------------------------

7. Consideration of Future FGD Installations on the Analyses for the
ELG Rulemaking
    As explained earlier, implementation of air pollution controls may
create new wastewater streams at power plants. The analyses and the
findings on economic achievability presented in this preamble reflect
consideration of wastestreams generated by air pollution controls that
will likely be in operation at plants at the time EPA takes final
action on this rulemaking. However, EPA recognizes that some recently
promulgated Clean Air Act requirements, along with state requirements
or enforcement actions, may lead to additional air pollution controls
(and resulting wastestreams) at existing plants beyond this date. In an
effort to assess the economic achievability of the proposed rule in
such cases, EPA also conducted a sensitivity analysis that forecasts
future installations of air controls through 2020 \51\ and the
associated costs of

complying with these proposed regulatory requirements for the
wastewater that may result from the forecasted air control
installations. The sensitivity analysis and results are described in
more detail in DCN SE01989.
---------------------------------------------------------------------------

    \51\ EPA considers that by forecasting future installations of
controls out to the year 2020, the sensitivity analyses for this
rulemaking reasonably reflect full implementation of air pollution
controls to comply with existing federal and state requirements.
---------------------------------------------------------------------------

    EPA has two primary data sources upon which to make its projections
of future air control installations: 1) Integrated Planning Model
estimates for the final MATS rule; \52\ and 2) responses to EPA's steam
electric industry survey. At the time EPA promulgated the MATS rule in
2011, it projected air pollution control retrofits using IPM (which
also included projected retrofits for CSAPR). To support this
rulemaking, EPA surveyed the industry about its plans for installing
certain new air pollution controls at facilities through 2020. EPA has
no reason to conclude that either the IPM FGD projections or the survey
projections are more accurate than the other. In fact, both of these
sources may overstate actual installations. Prior to MATS becoming
final, many plant owners and operators assumed that wet scrubbers would
be the only technology available to meet emissions limits for acid
gases. As EPA gathered and published additional data on facility
emission rates (which informed how the Agency set the standards), and
as stakeholders researched and published additional information on the
performance of less capital-intensive control technologies such as dry
sorbent injection, it has become clear that many facilities will find
it more cost-effective to forgo wet scrubbers in favor of other
emission-reduction strategies. Furthermore, major economic variables
such as electricity demand and natural gas prices have changed
substantially since the prevailing market conditions in 2010, when
respondents were answering the survey. For example, a facility
originally indicating an expectation in the industry survey to install
a wet scrubber by 2020 may now find itself no longer competitive in the
updated marketplace with substantially lower natural gas prices and
lower electricity demand growth than previously expected. Consequently,
the facility may elect to retire and thereby neutralize the previously
reported intent to scrub. Nevertheless, these two sources remain the
best available information EPA has with which to estimate future
conditions.
---------------------------------------------------------------------------

    \52\ EPA IPM v.4.10 projections for units based on compliance
with CSAPR, MATS, state rules, and enforcement actions including
consent decrees.
---------------------------------------------------------------------------

    As a first step in conducting a sensitivity analysis, EPA compared
the projections from the two sources described above. This comparison
demonstrates that the IPM results for the MATS Policy Case and the ELG
industry survey responses are consistent at the aggregate level.
Furthermore, in very large part, both the survey and IPM identify the
same generating units as being wet-scrubbed, either currently or in the
future (the two sources are in agreement for approximately 94 percent
of the wet-scrubbed units). The two sources also project similar wet-
scrubbed capacities. In the very few cases where there are differences
between the two sources, the differences are primarily due to the
expected variation at a unit-level (e.g., IPM projects wet FGD at unit
A and dry FGD at unit B, but instead the survey responses report wet
FGD at unit B and dry FGD at unit A). Another difference between the
MATS IPM estimates and the industry survey estimates is that, in a very
few cases, the IPM results estimate that certain plants would retire
(and therefore would not install wet scrubbers). In conducting the
analyses for the ELG, EPA made the conservative assumption (i.e., one
that would tend to overestimate cost, if anything) that a plant would
still be in operation in 2020 unless the plant has formally announced
its closure by 2014.
    Because its goal in conducting this sensitivity analysis was to
assess the economic achievability of the proposed ELG, even in light of
possible future air controls, EPA developed a conservative upper bound
estimate of future installations by combining the results of the two
sources to develop its ``future steam profile.'' In other words, EPA
combined any source that reported or projected a wet FGD into one
``future steam profile.'' This ``future steam profile'' is conservative
because it reflects more wet FGDs than are anticipated to actually be
installed; that is, by aggregating the survey and IPM forecast
estimates it results in a total number of wet FGD systems and wet-
scrubbed capacity that is greater than either of those individual
sources. EPA then added costs associated with projected wastewater
discharges from this future steam profile to comply with this proposal
to the total costs it previously calculated for the existing universe.
Based on the results of this conservative analysis, EPA finds that
discharges from these additional air controls (which, if actually
installed, would be due to various requirements including state rules,
consent decrees, CSAPR/CAIR, and MATS) may increase the costs of this
proposed rule by no more than 10 to 15 percent. See discussion in
Section VII.A.7. Even if all of these additional costs were to come to
fruition, which is unlikely since the ``future steam profile''
overestimates the number of new wet FGD systems that are anticipated,
EPA finds that these additional costs are economically achievable.
    EPA notes that subsequent to its analysis, the D.C. Circuit Court
of Appeals vacated the CSAPR. EPA will continue to assess the potential
impacts that changes to air pollution regulations may have on future
installations of wet FGD systems. For the purpose of FGD wastewater
analyses for this rulemaking, EPA has made a conservative assumption
that all of the previously projected wet scrubber additions in the
CSAPR-inclusive baseline (which also included MATS, state rules,
consent decrees, etc.) would continue to be built, and that discharges
from those additional wet scrubbers would therefore be subject to the
proposed revisions to the ELGs.
8. Timing of New Requirements
    As part of its consideration of technological availability and
economic achievability, EPA considered the magnitude and complexity of
process changes and new equipment installations that would be required
at many existing facilities to meet the requirements of the rule. As
discussed in Section VIII.A.2, EPA proposes that certain BAT
limitations for existing sources being proposed today (those that would
establish requirements more stringent than existing BPT requirements)
would apply on a date determined by the permitting authority that is as
soon as possible when the next permit is issued beginning July 1, 2017
(approximately three years from the effective date of this rule). This
is true of the proposed limitations and standards based on any of the
eight main regulatory options, including the preferred options, Option
3a, Option 3b, Option 3, or Option 4a.
    EPA is proposing this approach for several practical reasons. While
some facilities already have the necessary equipment and processes in
place, or could do so relatively quickly, and may need little time
before they are able to comply with the revised ELG requirements, not
all will be able to do so. Some facilities will need time to raise the
capital, plan and design the system, procure equipment, construct and
then test the system. Moreover, providing a window of time will better
enable facilities to install the pollution control technology during an
otherwise

planned shutdown or maintenance period. In some cases, a facility must
apply for permission to enter into such a period where they are
producing no or less power.
    During site visits, EPA found that most facilities need several
years to plan, design, contract, and install major system
modifications, especially if they are to be accomplished during planned
maintenance periods to avoid causing forced outages. EPA recognizes
that the proposed rule would require a significant amount of system
design by engineering firms, equipment procurement from vendors, and
installation by trained labor forces. EPA anticipates that changes to
FGD wastewater treatment systems, fly ash system, bottom ash systems,
and/or leachate treatment systems would constitute major system
modifications requiring several years to accomplish for many plants.
EPA identified certain technical and logistical issues at some
facilities that may warrant additional time, such as coordinating ash
system conversions for multiple generating units. In order to avoid any
impacts on the consistency and reliability of power generation, outages
at multiple facilities in one geographic area would need to be
coordinated, which could also result in the need for more time.
    EPA recognizes that permitting authorities have discretion with
respect to when to reissue permits and can take into consideration the
need to provide additional time to include BAT limits to prevent or
minimize forced outages. Thus, in some cases, the new BAT requirements
may as a practical matter be applied to a facility sometime after July
1, 2017. However, EPA judges that, under this proposed approach, all
steam electric facilities will have the proposed BAT limitations
applied to their permits no later than July 1, 2022, approximately 8
years from the date of promulgation of any final ELGs. For indirect
discharges, except with respect to discharges of nonchemical metal
cleaning waste, the proposed PSES requirements would apply by the date
determined by the control authority that is as soon as possible
beginning July 1, 2017, or approximately three years after promulgation
of any final ELGs. EPA's record indicates it may not take that long for
all facilities to meet the limitations and standards. Some plants may
not require a major modification for one or more systems to be able to
comply with new effluent limits and therefore would need less time. For
example, some plants have installed dry fly ash handling systems that
have capacity to handle all generated ash dry, yet they also maintain a
wet ash handling system as a backup. The backup wet system is typically
operated only a few days per year. According to the industry survey,
plants such as these could quickly cease operation of the wet system,
complying with a zero discharge requirement with relative ease.
    EPA envisions that each facility subject to this proposal would
study available technologies and operational measures, and subsequently
install, incorporate and optimize the technology most appropriate for
each site. EPA believes the proposed rule affords flexibility for a
reasonable amount of time to conduct engineering studies, assess and
select appropriate technologies, apply for necessary permits, complete
construction, and optimize the technologies' performance. The
permitting authority could establish any additional interim milestones,
as appropriate, within these timelines.

IX. Technology Costs and Pollutant Reductions

    This section provides an overview of EPA's approach for estimating
the compliance costs and pollutant reductions associated with the
regulatory options discussed in this proposal. Sections 9 and 10 of the
TDD provide a much more in depth discussion of these analyses.
    EPA often estimates costs and pollutant loads on a per plant basis
and then sums or otherwise escalates the plant-specific values to
represent industry-wide compliance costs and pollutant reductions.
Calculating costs and loads on a per plant basis allows EPA to account
for differences in plant characteristics such as types of processes
used, wastewaters generated and their flows/volumes and
characteristics, and wastewater controls in place (e.g., BMPs and end-
of-pipe treatment). EPA took this approach in estimating the compliance
costs and pollutant reductions associated with this proposed rule.
    EPA estimated the costs to steam electric power plants--whose
primary business is electric power generation or related electric power
services--of complying with the proposed ELGs. EPA evaluated the costs
of this proposal on all plants currently subject to the existing ELGs.
Some aspects of this proposal (e.g., applicability changes) would
likely not lead to increased costs to complying facilities. Other
aspects of this proposal would likely lead to increased costs to a
subset of complying facilities. These facilities are generally those
that generate and discharge the wastestreams for which EPA is proposing
new limitations or standards. EPA reviewed the steam electric industry
for all facilities that generate the specific types of wastewater
streams for which EPA evaluated additional limitations or standards.
The following describes the detailed costing and loadings evaluation
EPA performed for these plants.
    As discussed earlier in this preamble, EPA proposes to establish a
separate set of requirements for existing oil-fired generating units
and units with a capacity of 50 MW or less. For these units, EPA is
proposing to establish BAT limitations that would be set equal to BPT
limitations. Since this proposed rule would not establish additional
control on discharges associated with these operations, there would be
no incremental costs for these units to comply with the requirements of
this proposed rule.\53\
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    \53\ EPA did estimate costs for these existing oil-fired
generating units and small generating units to comply with the
options considered in this rulemaking and has included those
estimates in the docket for the proposed rule (see DCN SE01957,
Incremental Costs and Pollutant Removals for Proposed Effluent
Limitations Guidelines and Standards for the Steam Electric
Generating Point Source Category).
---------------------------------------------------------------------------

    For the aspects of these proposed regulatory options that include
limitations and standards for additional pollutants, EPA estimated
compliance costs and pollutant reductions from data collected through
survey responses, site visits, sampling episodes, and from individual
power plants and equipment vendors. EPA used this information to
develop computerized cost and pollutant loadings models for each of the
technologies that form the basis of the regulatory options. EPA used
these models to calculate facility-specific compliance costs and
pollutant reductions for all power plants that the information suggests
may incur costs to comply with one or more proposed limitations or
standards associated with the regulatory options.54 55
Therefore,

EPA's plant-specific cost and pollutant reduction estimates represent
the incremental costs/pollutant reductions for a plant when its
existing practices would not lead to compliance with the option being
evaluated for the proposed rule. While plants would not be required to
implement the specific technologies that form the basis for the
proposed limitations and standards for each of the regulatory options,
EPA calculated the cost and associated pollutant reductions for plants
to implement these technologies to estimate the compliance costs and
pollutant loading reductions associated with EPA's proposed rule.
---------------------------------------------------------------------------

    \54\ Because EPA anticipates taking final action on this
rulemaking in 2014, EPA did not include plants that are expected to
retire by 2014 and plants that do not discharge any of the
applicable wastestreams. Since this timeframe is approximately one
year following the date of the proposed rule, EPA considers there to
be sufficient certainty regarding plant/unit retirements or relevant
major system modifications for it to be reasonable for EPA to take
into account in the regulatory analyses for this rulemaking,
Retirements and modifications occurring farther into the future than
2014 become more uncertain and subject to change; thus, EPA has
considered such future changes, as appropriate, in sensitivity
analyses for proposed rule. However, this approach can result in
estimating compliance costs for generating units that companies have
announced will retire, repower, or convert from wet to dry ash
handling. Because of this, EPA is considering using alternative
dates, such as 2022 which may better reflect the implementation
timeframe for the ELG, for the baseline year for its analyses for
the final rule.
    \55\ EPA is considering establishing BMPs that would apply to
surface impoundments that receive, store, dispose of, or are
otherwise used to manage coal combustion residuals including FGD
wastes, fly ash, bottom ash (which includes boiler slag), leachate,
and other residuals associated with the combustion of coal to
prevent uncontrolled discharges from these impoundments. Costs for
the industry to implement the BMPs under consideration are included
in EPA's cost and economic analyses for the proposed rule.
---------------------------------------------------------------------------

    EPA's cost estimates include two key cost components: Capital costs
(one-time costs) and operating and maintenance (O&M) costs (which are
incurred every year). Capital costs comprise the direct and indirect
costs associated with the purchase, delivery, and installation of
pollution control technologies. Capital cost elements are specific to
the industry and commonly include purchased equipment and freight,
equipment installation, buildings, land, site preparation, engineering
costs, construction expenses, contractor's fees, and contingency.
Annual O&M costs comprise all costs related to operating and
maintaining the pollution control technologies or performing BMPs for a
period of one year. O&M costs are also specific to the industry and
commonly include costs associated with operating labor, maintenance
labor, maintenance materials (routine replacement of equipment due to
wear and tear), chemical purchase, energy requirements, residual
disposal, and compliance monitoring. In some cases, the technology
options may also result in recurring costs that are incurred less
frequently than annually (e.g., 3-year recurring costs) or one-time
costs other than capital investment (e.g., one-time engineering costs).

A. Methodology for Estimating Plant-Specific Costs

    The limitations and standards associated with the regulatory
options for this proposed rule address various wastestreams and, as
such, consist of multiple technology bases (see Table IX-1). As a first
step in estimating costs to control discharges associated with a
particular generating unit at an existing steam electric power plant
subject to this rulemaking (i.e., existing sources), EPA used the
plant's survey response to determine if the wastestreams it discharges
may be affected by the limitations and standards for the regulatory
options considered in this rulemaking. Then, for each of the
wastestreams that may be affected by an option, EPA reviewed the
industry survey response, available sampling data, and industry long-
term self-monitoring data to determine if the plant currently meets the
performance level of the technology basis for the requirement of an
option for that wastestream. A portion of the steam electric industry
has already implemented processes or treatment technologies that serve
as the basis for the regulatory options considered for the proposed
rule; as a result, these facilities would not incur costs to comply
with the proposed rule, or would incur costs lower than they would be
if the processes/technologies had not already been implemented. In such
cases, EPA assigned no compliance cost associated with the discharge of
that particular wastestream other than compliance monitoring costs. For
all other applicable wastestreams, EPA assessed the operations and
treatment system components in place at the plant, identified necessary
components that the plant would need to come into compliance, and
estimated the cost to install and operate those components. Table IX-2
presents a list of the major cost components included in the
evaluation. As appropriate, EPA also accounted for expected reductions
in the plant's costs associated with their current operations or
treatment systems that would no longer be needed as a result of
installing and operating the technology bases (e.g., avoided costs to
manage surface impoundments). For plants that may already have certain
components installed, EPA compared certain key operating
characteristics, such as chemical addition rates, to determine if
additional costs (e.g., chemical costs) were warranted.

                                          Table IX-1--Technology Cost Modules Used to Estimate Compliance Costs
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Regulatory option
                  Wastestream                        Technology cost modules     -----------------------------------------------------------------------
                                                                                1        3a       2        3b       3        4a       4        5
--------------------------------------------------------------------------------------------------------------------------------------------------------
FGD Wastewater................................  Chemical Precipitation..........       X   .......       X        X        X        X        X        X
                                                Biological Treatment............  .......  .......       X        X        X        X        X
                                                Vapor-Compression Evaporation...  .......  .......  .......  .......  .......  .......  .......       X
Fly Ash Transport Water.......................  Dry Fly Ash Handling............  .......       X   .......       X        X        X        X        X